Table of Contents UNITED STATESSECURITIES AND EXCHANGE COMMISSIONWashington, DC 20549 FORM 10-K (Mark One) xANNUAL REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended September 30, 2013OR ¨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 registeredCommon Units New York Stock ExchangeSecurities 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 xIndicate 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 xIndicate 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 1934during 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 filingrequirements 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 Filerequired 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 shorterperiod 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, tothe 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 tothis Form 10-K. xIndicate 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 xThe aggregate market value of the registrant’s common units held by non-affiliates on March 31, 2013 was approximately $270,937,000. As ofNovember 30, 2013, the registrant had 57,467,744 common units outstanding.Documents Incorporated by Reference: None Table of ContentsSTAR GAS PARTNERS, L.P.2013 FORM 10-K ANNUAL REPORTTABLE 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 2 Table of ContentsPART IStatement Regarding Forward-Looking DisclosureThis Annual Report on Form 10-K includes “forward-looking statements” which represent our expectations or beliefs concerning future events thatinvolve risks and uncertainties, including those associated with the effect of weather conditions on our financial performance, the price and supply of theproducts that we sell, the consumption patterns of our customers, our ability to obtain satisfactory gross profit margins, our ability to obtain new customersand retain existing customers, our ability to make strategic acquisitions, the impact of litigation, our ability to contract for our current and future supplyneeds, natural gas conversions, future union relations and the outcome of current and future union negotiations, the impact of current and futuregovernmental 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 factsincluded in this Report including, without limitation, the statements under “Management’s Discussion and Analysis of Financial Condition and Results ofOperations” 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 suchforward-looking statements are reasonable, we can give no assurance that such expectations will prove to be correct and actual results may differ materiallyfrom 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 Reportunder 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 personsacting on its behalf are expressly qualified in their entirety by the Cautionary Statements. Unless otherwise required by law, we undertake no obligation toupdate 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.BUSINESSStructureStar Gas Partners, L.P. (“Star Gas Partners,” the “Partnership,” “we,” “us,” or “our”) is a home heating oil and propane distributor and services providerwith one reportable operating segment that principally provides services to residential and commercial customers to heat homes and buildings. Star GasPartners is a Delaware limited partnership, which at November 30, 2013, had outstanding 57.5 million common partner units (NYSE: “SGU”) representing a99.44% 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: 3 Table of ContentsThe 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 Delawarelimited liability company (“Kestrel”). • Our operations are conducted through Petro Holdings, Inc. (a Minnesota corporation that is our indirect wholly owned subsidiary) and itssubsidiaries, all of which are corporations subject to Federal and state income taxes. At December 31, 2012, our Federal Net Operating Losscarryforwards (“NOLs”) were $10.6 million, subject to annual limitations on the amount of losses that can be used of between $1.0 million and $2.2million. • 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 notesor the senior notes. We are dependent on distributions, including inter-company dividends and interest payments, from our subsidiaries to serviceour debt obligations. The distributions from our subsidiaries are not guaranteed and are subject to certain loan restrictions. Star Gas FinanceCompany has nominal assets and conducts no business operations. (See Note 11 of the Notes to the Consolidated Financial Statements - Long-TermDebt 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 viewedand 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 reasonablypracticable 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 publicreference room located at Judiciary Plaza, 100 F Street, N.E., Washington, D.C. 20549. The public may obtain information on the operation of the publicreference 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 StockExchange 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 forinformational purposes only and are not intended to be hyperlinks. Accordingly, no information found and/or provided at such Internet addresses is intendedor deemed to be incorporated by reference herein.Partnership StructureThe following chart summarizes our partnership structure as of September 30, 2013. Other than Star Gas Partners, L.P. all other entities in this structureare taxable as corporations for Federal and state income tax purposes. 4 Table of ContentsBusiness OverviewAs of September 30, 2013, we sold home heating oil and propane to approximately 404,000 full service residential and commercial customers. Webelieve 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 equipmentfor our customers and provide ancillary home services, including home security and plumbing, to approximately 15,700 customers. During fiscal 2013, totalsales were comprised of approximately 75% from sales of home heating oil and propane; 13% from the installation and repair of heating and air conditioningequipment 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 PetroHeating & Air Conditioning Services and Meenan Oil. We believe that the Petro, Meenan and other trademarks and service marks are an important part of ourability 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 residentialand 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 equalmonthly 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 derivativeinstruments as a hedge against our home heating oil physical inventory and home heating oil priced purchase commitments. Our size gives us the ability torealize economies of scale and the ability to provide consistent, strong customer service. 5 Table of ContentsCurrently, we have heating oil and/or propane customers in the following states, regions and counties: MaineYork New HampshireHillsborough CountyMerrimackRockinghamStrafford VermontBenningtonRutland MassachusettsBarnstableBerkshireBristolEssexMiddlesexNorfolkPlymouthSuffolkWorcester Rhode IslandBristolKentNewportProvidenceWashington ConnecticutFairfieldHartfordLitchfieldMiddlesexNew HavenNew LondonTollandWindham New YorkAlbanyBronxColumbiaDutchessEssexFranklinFultonGreeneHamiltonKingsMontgomeryNassauNew YorkOnondagaOrangePutnamQueensRensselaerRichmondRocklandSaratogaSchenectadySchoharieSuffolkSullivanUlsterWarrenWashingtonWestchester New JerseyBergenBurlingtonCamdenEssexGloucesterHudsonHunterdonMercerMiddlesexMonmouthMorrisOceanPassaicSalemSomersetSussexUnionWarren PennsylvaniaBerksBucksChesterCumberlandDauphinDelawareLancasterLebanonLehighMonroeMontgomeryNorthamptonPerryPhiladelphiaPikeYork MarylandAnne ArundelBaltimoreCalvertCarrollCecilCharlesFrederickHarfordHowardMontgomeryNorth CalvertPrince George’s Washington, D.C.District of Columbia VirginiaArlingtonFairfaxFauquierLoudounPrince WilliamStafford North CarolinaUnion County South CarolinaBambergCalhounDorchesterLexingtonOrangeburgIndustry CharacteristicsHome heating oil is primarily used as a source of fuel to heat residences and businesses in the Northeast and Mid-Atlantic regions. According to theU.S. Department of Energy—Energy Information Administration, 2009 Residential Energy Consumption Survey (the latest survey published), these regionsaccount 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 of20.8 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 naturalgas. We believe that conversions to natural gas have increased and may continue to do so as natural gas has become significantly less expensive than homeheating 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 asthe success of our marketing programs. Conversions to natural gas are increasing and we believe this may continue as natural gas has become significantlyless expensive than home heating oil on an equivalent BTU basis. In addition, the states of New York, Connecticut and Pennsylvania are seeking toencourage homeowners to expand the use of natural gas as a heating fuel through legislation and regulatory efforts. 6 Table of ContentsPropane is a by-product of natural gas processing and petroleum refining. Propane use falls into three broad categories: residential and commercialapplications; industrial applications; and agricultural uses. In the residential and commercial markets, propane is used primarily for space heating, waterheating, clothes drying and cooking. Industrial customers use propane generally as a motor fuel to power over-the-road vehicles, forklifts and stationaryengines, to fire furnaces, as a cutting gas and in other process applications. In the agricultural market, propane is primarily used for tobacco curing, cropdrying, 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 believedistributors such as ourselves generally seek to maintain their per gallon margins by passing wholesale price increases through to customers, thus insulatingtheir margins from the volatility in wholesale prices. However, distributors may be unable or unwilling to pass the entire product cost increases through tocustomers. In these cases, significant decreases in per gallon margins may result. The timing of cost pass-throughs can also significantly affect margins. Theretail home heating oil industry is highly fragmented, characterized by a large number of relatively small, independently owned and operated localdistributors. 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 lesserextent. The industry is complex and costly due to regulations, working capital requirements and the cost to hedge for price-protected customers.Business StrategyOur business strategy is to increase operating profits and cash flow by conservatively managing our operations and growing and retaining our customerbase as a retail distributor of home heating oil and propane and provider of ancillary products and services. The key elements of this strategy include thefollowing:Deliver superior customer service. We are completely focused on providing the best customer service in our regions, with the aim of maximizingcustomer satisfaction and retention. To engage our employees and enhance their ability to provide superior customer service and reduce gross customerlosses, 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 andpotential 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 acquiredcustomers into our operations. Through our acquisitions, we have been able to increase our presence in some of our existing geographic markets andselectively expand into new markets. Our acquisition strategy has enabled us to achieve our current market position and offers us the opportunity to achieveoperating 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 ofredundant systems and appropriate reductions in overhead.SeasonalityOur fiscal year ends on September 30. All references to quarters and years respectively in this document are to fiscal quarters and years unless otherwisenoted. 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 quarterand 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 andsecond 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 fourthfiscal quarter operating results will continue. In addition, sales volume typically fluctuates from year to year in response to variations in weather, wholesaleenergy prices and other factors. 7 Table of ContentsCompetitionMost of our operating locations compete with numerous distributors, primarily on the basis of price, reliability of service and response to customerneeds. 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 deliveryonly. 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, 52weeks a year basis. We believe that this level of service tends to help build customer loyalty. In some instances homeowners have formed buyingcooperatives that seek a lower price than individual customers are otherwise able to obtain. Our business competes for retail customers with suppliers ofalternative energy products, principally natural gas, propane (in the case of our home heating oil operations) and electricity.Customer AttritionWe measure net customer attrition for our full service residential and commercial home heating oil and propane customers. Since October 1, 2010, wehave included propane customers in this calculation as several of our acquisitions since such date have included propane operations. Net customer attrition isthe difference between gross customer losses and customers added through marketing efforts. Customers added through acquisitions are not included in thecalculation of gross customer gains. However, additional customers that are obtained through marketing efforts at newly acquired businesses are included inthese calculations. Customer attrition percentage calculations include customers added through acquisitions in the denominators of the calculations on aweighted average basis. Gross customer losses are the result of a number of factors, including price competition, move outs, credit losses and conversions tonatural gas. (See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Customer Attrition.)Customers and PricingOur full service home heating oil customer base is comprised of 95% residential customers and 5% commercial customers. Our residential customerreceives on average 150 gallons per delivery and our commercial accounts receive on average 310 gallons per delivery. Typically, we make four to sixdeliveries per customer per year. Currently, 96% of our full service residential and commercial home heating oil customers have their deliveries scheduledautomatically and 4% of our home heating oil customer base call from time to time to schedule a delivery. Automatic deliveries are scheduled based on eachcustomer’s historical consumption pattern and prevailing weather conditions. Our practice is to bill customers promptly after delivery. We also offer abalanced 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 homeheating oil market and other factors. In addition, we offer price protected programs, which establish either a ceiling or a fixed price per gallon that thecustomer would pay over a defined period. The following chart depicts the percentage of the pricing plans selected by our residential home heating oilcustomers 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 andhedging costs of residential price-protected customers, the per gallon margins realized from price protected customers generally are less than from variablepriced residential customers. 8 Table of ContentsDerivativesWe use derivative instruments in order to mitigate our exposure to market risk associated with the purchase of home heating oil for our price-protectedcustomers, physical inventory on hand, inventory in transit and priced purchase commitments. Currently, the Partnership’s derivative instruments are with thefollowing counterparties: Bank of America, N.A., Bank of Montreal, Cargill, Inc., Citibank, N.A., JPMorgan Chase Bank, N.A., Key Bank, N.A., RegionsFinancial 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 thatderivative instruments be recorded at fair value and included in the consolidated balance sheet as assets or liabilities. To the extent derivative instrumentsdesignated as cash flow hedges are effective, as defined under this guidance, changes in fair value are recognized in other comprehensive income until theforecasted 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, weexperience volatility in earnings as outstanding derivative instruments are marked to market and non-cash gains and losses are recorded prior to the sale ofthe commodity to the customer. The volatility in any given period related to unrealized non-cash gains or losses on derivative instruments can be significantto 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 beinghedged, realized gains and losses are recorded in cost of product, cost of installations and service, or delivery and branch expenses.Suppliers and Supply ArrangementsWe purchase our product for delivery in either barge, pipeline or truckload quantities, and as of September 30, 2013 had contracts with approximately70 third-party terminals for the right to temporarily store petroleum products and propane at their facilities. Home heating oil and propane purchases are madeunder supply contracts or on the spot market. We have entered into market price based contracts for approximately 81% of our expected retail home heatingoil and propane requirements for the fiscal 2014 heating season. During fiscal 2013, Global Companies LLC and JPMorgan Ventures Energy Corporationprovided approximately 19% and 11%, respectively, of our petroleum product purchases. No other single supplier provided more than 10% of our productsupply during fiscal 2013, however, NIC Holding Corp. and Phillips 66 each provided approximately 9% of our petroleum product purchases. For fiscal2014, 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 supplycontracts 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 deliveryor pricing date plus an agreed upon differential. We believe that our policy of contracting for the majority of our anticipated supply needs with diverse andreliable sources will enable us to obtain sufficient product should unforeseen shortages develop in worldwide supplies.Home Heating Oil Price VolatilityIn recent years, the wholesale price of home heating oil has been extremely volatile, resulting in increased consumer sensitivity to heating costs andincreased gross customer attrition. Like any other market commodity, the price of home heating oil is generally impacted by many factors, includingeconomic 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 componentof home heating oil. The volatility in the wholesale cost of home heating oil, as measured by the New York Mercantile Exchange (“NYMEX”) price pergallon 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. 9 Table of ContentsAcquisitionsPart of our business strategy is to pursue select acquisitions. During fiscal 2013, the Partnership completed two acquisitions and added approximately2,000 home heating oil and propane accounts for an aggregate cost of approximately $1.4 million, reduced by working capital credits of $0.1 million. Infiscal 2012, we acquired seven retail heating oil dealers with approximately 41,000 home heating oil and propane accounts for an aggregate cost ofapproximately $39.2 million, reduced by working capital credits of $1.2 million. In fiscal 2011, we acquired four retail heating oil dealers withapproximately 8,800 home heating oil and propane accounts for an aggregate cost of approximately $9.7 million, including working capital of $1.9 million.EmployeesAs of September 30, 2013, we had 2,577 employees, of whom 747 were office, clerical and customer service personnel; 776 were equipmenttechnicians; 386 were fuel delivery drivers and mechanics; 377 were management and 291 were employed in sales. Of these employees 866 are representedby 45 different collective bargaining agreements with local chapters of labor unions. Some of these unions have union administered pension plans that havesignificant unfunded liabilities, a portion of which could be assessed to us should we withdraw from these plans. The Partnership does not expect to withdrawfrom these plans. Depending on the demands of the 2014 heating season, we anticipate that we will augment our current staffing levels from the 483employees on leave (330 of whom are represented by collective bargaining agreements with labor unions). We are currently involved in union negotiationswith three local bargaining units. We believe that our relations with both our union and non-union employees are generally satisfactory.Government RegulationsWe are subject to various federal, state and local environmental, health and safety laws and regulations. Generally, these laws impose limitations on thedischarge or emission of pollutants and establish standards for the handling of solid and hazardous wastes. These laws include the Resource Conservationand Recovery Act, the Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), the Clean Air Act, the Occupational Safetyand Health Act, the Emergency Planning and Community Right to Know Act, the Clean Water Act and comparable state statutes. CERCLA, also known asthe “Superfund” law, imposes joint and several liabilities without regard to fault or the legality of the original conduct on certain classes of persons that areconsidered to have contributed to the release or threatened release of a hazardous substance into the environment. Products stored and/or delivered by us andcertain automotive waste products generated by our fleet are hazardous substances within the meaning of CERCLA or otherwise subject to investigation andcleanup under other environmental laws and regulations. While we are currently not involved with any material CERCLA claims, and we have implementedprograms and policies designed to address potential liabilities and costs under applicable environmental laws and regulations, failure to comply with suchlaws 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 contaminationat properties that we have acquired. A number of our properties are currently undergoing remediation, in some instances funded by prior owners or operatorscontractually obligated to do so. To date, no material issues have arisen with respect to such prior owners or operators addressing such remediation, althoughthere 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 ofenvironmental 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, ordisruptions 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. Theseregulations 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 permitsthat are necessary to operate some of our facilities, some of which may be material to our operations. 10 Table of ContentsITEM 1A.RISK FACTORSYou should consider carefully the risk factors discussed below, as well as all other information, as an investment in the Partnership involves a highdegree of risk. Any of the risks described below could impair our business, financial condition and operating results, which could result in a partial or totalloss 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. Netcustomer attrition is the difference between gross customer losses and customers added through marketing efforts. Customers added through acquisitions arenot included in the calculation of gross customer gains. However, additional customers that are obtained through marketing efforts at newly acquiredbusinesses are included in these calculations. Customer attrition percentage calculations include customers added through acquisitions in the denominatorsof the calculations on a weighted average basis. Starting October 1, 2010, we have included propane customers in this calculation as several of ouracquisitions 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 toacquire 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 ourbusiness, operating results and cash available for distributions to unitholders. For additional information about customer attrition, see Item 7 “Management’sDiscussion 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 havean 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 deliveryonly. 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 yearbasis. We believe that this tends to build customer loyalty. In some instances homeowners have formed buying cooperatives that seek to purchase homeheating oil from distributors at a price lower than individual customers are otherwise able to obtain. We also compete for retail customers with suppliers ofalternative energy products, principally natural gas, propane (in the case of our home heating oil operations) and electricity. If we are unable to competeeffectively, we may lose existing customers and/or fail to acquire new customers, which would have a material adverse effect on our business, operatingresults and financial condition. 11 Table of ContentsThe following table depict our customer losses to natural gas conversions from fiscal year 2009 to fiscal year 2013. Conversions to natural gas areincreasing and we believe this may continue as natural gas has become significantly less expensive than home heating oil on an equivalent BTU basis. Inaddition, the states of New York, Connecticut and Pennsylvania are seeking to encourage homeowners to expand the use of natural gas as a heating fuelthrough 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 geographicfootprint reduces the pool of available customers from which we can gain new heating oil customers, and could have a material adverse effect on ourbusiness, 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 fromalternative energy sources. Accordingly, future growth will depend on our ability to make acquisitions on economically acceptable terms. We cannot assurethat 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 economicallyacceptable terms. Factors that may adversely affect our operating and financial results may limit our access to capital and adversely affect our ability to makeacquisitions. 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 arerequired 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. Thiscovenant 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 highproduct 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 adverselyaffected 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 afixed price of home heating oil over a fixed period. When the customer makes a purchase commitment for the next period we currently purchase optioncontracts, swaps and futures contracts for a substantial majority of the heating oil that we expect to sell to these price-protected customers. The amount ofhome heating oil volume that we hedge per price-protected customer is based upon the estimated fuel consumption per average customer, per month. If theactual usage exceeds the amount of the hedged volume on a monthly basis, we could be required to obtain additional volume at unfavorable margins. Inaddition, should actual usage in any month be less than the hedged volume, (including, for example, as a result of early terminations by fixed pricecustomers) our hedging losses could be greater. Currently, we have elected not to designate our derivative instruments as hedging instruments under FASBASC 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 thestatement of operations. 12 Table of ContentsOur risk management policies cannot eliminate all commodity risk, basis risk, or the impact of adverse market conditions which can adversely affectour financial condition, results of operations and cash available for distribution to our unitholders. In addition, any noncompliance with our riskmanagement 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 conditionsremains. For example, we change our hedged position daily in response to movements in our inventory. Any difference between the estimated future salesfrom inventory and actual sales will create a mismatch between the amount of inventory and the hedges against that inventory, and thus change thecommodity risk position that the Partnership is trying to maintain. Also, significant increases in the costs of the products we sell can materially increase ourcosts 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 tocarry inventory. Basis risk describes the inherent market price risk created when a commodity of certain grade or location is purchased, sold or exchanged ascompared to a purchase, sale or exchange of a like commodity at a different time or place. Transportation costs and timing differentials are components ofbasis risk. For example, we use the NYMEX to hedge our commodity risk with respect to pricing of energy products traded on the NYMEX. Physicaldeliveries 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 basisrisk. 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 orother 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 futuredelivery obligations. We can provide no assurance, however, that these steps will detect and/or prevent all violations of such risk management policies andprocedures, 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 andcomplexities 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. FromApril 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 inthe 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 towarm winters.Weather conditions in the Northeast and Mid-Atlantic regions in which we operate have a significant impact on the demand for home heating oilbecause our customers depend on this product principally for space heating purposes. As a result, weather conditions may materially adversely impact ourbusiness, operating results and financial condition. During the peak-heating season of October through March, sales of home heating oil and propanehistorically have represented approximately 80% of our annual oil volume. Actual weather conditions can vary substantially from year to year or from monthto month, significantly affecting our financial performance. Warmer than normal temperatures in one or more regions in which we operate can significantlydecrease the total volume we sell and the gross profit realized and, consequently, our results of operations. In fiscal years 2012 and 2002 temperatures weresignificantly warmer than normal for the areas in which we sell our products, which adversely affected the amount of net income, EBITDA and AdjustedEBITDA 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, suchweather 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 PaymentThreshold, and the heating degree-day shortfall during this period resulted in our receiving the full $12.5 million payout, which was recorded as a reductionof 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 thePayment 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 toreceive 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 theten 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 fullyor substantially offset the adverse effects of warmer weather on our business and operating results during such periods. 13 Table of ContentsWe experienced warmer than normal weather conditions in the fiscal 2012 heating season, which had an adverse effect on our fiscal 2012 results ofoperations 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 amountof 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 fiscal2012 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 hedgecontract, 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 forpayments of distributions. As a result, in April 2012, we entered into an amendment to our revolving credit facility that permitted us to continue payingdistributions to our unitholders for the period from April 1, 2012 through December 31, 2012, provided that our Availability (borrowing base less amountsborrowed 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 percommon 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 chargecoverage 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 afixed 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. Severalfactors could cause us to make significantly higher future contributions to these plans, including unfavorable investment performance, insolvency ofparticipating employers, changes in demographics and increased benefits to participants. Some of these unions have union administered pension plans thathave significant unfunded liabilities, a portion of which could be assessed to us should we withdraw from these plans. However, we do not expect to withdrawfrom these plans. At this time, we are unable to determine whether any material adverse effect on our financial condition, results of operations or liquidity willresult 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 inventoryand our vehicle fuel costs were to fail, our liquidity, operating results and financial condition could be materially adversely impacted, as we would beobligated to fulfill our operational requirement of purchasing, storing and selling home heating oil and vehicle fuel, while losing the mitigating benefits ofeconomic hedges with a failed counterparty. If one of our insurance carriers were to fail, our liquidity, results of operations and financial condition could bematerially adversely impacted, as we would have to fund any catastrophic loss. If our weather hedge counterparty were to fail, we would lose the protection ofour 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, SocieteGenerale, and Wells Fargo Bank, N.A. Our primary insurance carrier is American International Group and our weather hedge counterparty is Swiss ReFinancial 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 fiscalquarter 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 ofapproximately 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 fiscalyear. 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 expectthat the negative impact of seasonality on our third and fourth fiscal quarter operating results will continue. Thus any material reduction in the profitabilityof the first and second quarters for any reason, including warmer than normal weather, generally cannot be made up by any significant profitabilityimprovements in the results of the third and fourth quarters. 14 Table of ContentsOur 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 underour revolving credit facility which expires June 2016, $44.7 million of letters of credit issued under our revolving credit facility and availability of $164.3million 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 inborrowings 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 generalpartnership 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 eventof 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, therebyreducing 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 indebtednessand 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 assetson 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 andhedging 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 ourrevolving credit facility, we may borrow up to $250 million, which increases to $350 million during the peak winter months from December through April ofeach fiscal year. We are obligated to meet certain financial covenants under the revolving credit facility, including the requirement to maintain at all timeseither excess availability (borrowing base less amounts borrowed and letters of credit issued) of 12.5% of the revolving credit commitment then in effect or afixed 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 orshould 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 toour customers, our physical inventory and fuel we use for our vehicles. These institutions have not required an initial cash margin deposit or any mark tomarket maintenance margin for these derivatives. Any mark to market exposure is reserved against our borrowing base and can thus reduce the amountavailable to us under our revolving credit facility. The mark to market reserve against our borrowing base for these derivative instruments with our lendinggroup 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 frontcash 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 optionswhich require us to pay for these options as they expire. 15 Table of ContentsFor certain of our supply contracts, we are required to establish the purchase price in advance of receiving the physical product. This occurs at the endof 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 thecommitment 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 requiredto 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. AtDecember 31, 2013, we expect to have approximately 40 million gallons of purchase commitments and physical inventory shorted with a futures contract orswap. 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 inwholesale prices could reduce our liquidity if we failed to recalculate the balanced payments on a timely basis or if customers resist higher balancedpayments. These customers could possibly owe us more in the future than we had budgeted. Generally, customer credit balances are at their low point afterthe 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 factorsare 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 theseincreases to customers through increased retail sales prices. In an effort to retain existing accounts and attract new customers we may offer discounts, whichwill 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 arrangementswhich 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 customersattempt 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 aresult of significant decreases in the price of home heating oil following the summer of 2008, many price-protected customers attempted to renegotiate theiragreements with us in fiscal 2009. It is our policy to bill a termination fee when customers terminate their arrangement with us. We believe thatapproximately 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, negativefinancial news and/or declines in income or asset values, which could have a material negative effect on the demand for our equipment and services andcould lead to increased conservation, as we have seen certain of our customers seek lower cost providers. Any increase in existing customers or potential newcustomers seeking lower cost providers and/or increase in our rejection rate of potential accounts because of credit considerations could increase our overallrate of net customer attrition. In addition, we could experience an increase in bad debts from financially distressed customers, which would have a negativeeffect 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 customerswith our products, which include combustible liquids such as propane. As a result, we may be a defendant in legal proceedings and litigation arising in theordinary 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 noassurance that this insurance will be adequate to protect us from all material expenses related to potential future claims for remediation costs and personal andproperty damage or that these levels of insurance will be available in the future at economical prices. 16 Table of ContentsOur 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, wecould incur substantial losses because of personal injury or loss of life, severe damage to and destruction of property and equipment, and pollution or otherenvironmental 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 uponexpectations as to what our ultimate liability will be for claims based on our historical developmental factors. We evaluate on an annual basis the potentialfor changes in loss estimates with the support of qualified actuaries. As of September 30, 2013, we had approximately $51.3 million of net insurance reservesand had issued $42.5 million in letters of credit for current and future claims. The ultimate settlement of these claims could differ materially from theassumptions 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 regulatorycosts.Our business is subject to a wide range of federal and state laws and regulations related to environmental and other matters. Such laws and regulationshave become increasingly stringent over time. We may experience increased costs due to stricter pollution control requirements or liabilities resulting fromnoncompliance with operating or other regulatory permits. New regulations might adversely impact operations, including those relating to undergroundstorage and transportation of the products that we sell. In addition, there are environmental risks inherently associated with home heating oil operations, suchas the risks of accidental releases or spills. We have incurred and continue to incur costs to remediate soil and groundwater contamination at some of ourlocations. We cannot be sure that we have identified all such contamination, that we know the full extent of our obligations with respect to contamination ofwhich we are aware, or that we will not become responsible for additional contamination not yet discovered. It is possible that material costs and liabilitieswill 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 significantchanges 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 greenhousegases, in particular from the combustion of fossil fuels. It is probable that any regulatory program that caps emissions or imposes a carbon tax will increasecosts for us and our customers, which could lead to increased conservation or customers seeking lower cost alternatives. However, we cannot yet estimate thecompliance costs or business impact of potential national, regional or state greenhouse gas emissions reduction legislation, regulations or initiatives, sincesuch 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 andother heating devices, have adversely affected the demand for our products by retail customers. Future conservation measures or technological advances inheating, 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 totemporarily store our products. Any significant interruption in the service of these third-party terminals or on the common carrier pipelines used wouldadversely 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 amaterial 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 toraise 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 thistime. 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 orindirect targets. Terrorist activity may also hinder our ability to transport our products if our normal means of transportation become damaged as a result of anattack. Instability in the financial markets as a result of terrorism could also affect our ability to raise capital. Terrorist activity could likely lead to increasedvolatility in the prices of our products. 17 Table of ContentsThe impact of hurricanes and other natural disasters could cause disruptions in supply and could also reduce the demand for home heating oil whichwould 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 insupply could have a material adverse effect on our business, financial condition and results of operations, causing an increase in wholesale prices and adecrease in supply. Hurricanes and other natural disasters could also cause disruptions in the power grid, which could prevent our customers from operatingtheir home heating oil systems, thereby reducing our sales. For example, on October 29, 2012, storm Sandy made landfall in our service area, resulting inwidespread power outages that affected a number of our customers. Deliveries of home heating oil and propane were less than expected for certain of ourcustomers 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 thoseof 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 canimpact the amount of cash, if any, available for distribution to unitholders, and available to pay principal and interest on debt and the amount ofincentive 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 thatmight, without limitations, constitute breaches of fiduciary duty. Unitholders are deemed to have consented to some actions and conflicts of interestthat 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, therebylimiting 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 andreasonable to us or entering into additional contractual arrangements with any of these entities on our behalf. 18 Table of ContentsCash 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 ourperformance. 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 Losscarryforwards (“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 establishingreserves 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. Themost restrictive covenant is found in the revolving credit facility. In order to make any distributions to unitholders, we must maintain availability of 17.5% ofthe 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 theConsolidated 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 receivingany 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 withowning 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 andthen 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 (mostlydividend income from Star Acquisitions, interest income and possibly cancellation of indebtedness income) regardless of whether a cash distribution hasbeen 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 todividends received by us that we used to repurchase units. 19 Table of ContentsWe are a holding company and have no material operations or assets. Accordingly, we are dependent on distributions from our subsidiaries to serviceour 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 aredependent on cash distributions from our subsidiaries to service our debt obligations. Noteholders will not receive payments required by the notes unless oursubsidiaries are able to make distributions to us after they first comply with the restrictions on distributions under the terms of their own borrowingarrangements 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 notesor 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 otherremedy 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 toservice 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 notrequired to accumulate cash for the purpose of meeting our future obligations to our noteholders. As a result, we do not expect to accumulate significantamounts 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 ourfuture results of operation and financial condition as well as developments in the capital markets. Our general partner will determine the future use of our cashresources 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 makeacquisitions; 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 paymentson 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 revolvingcredit 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 subsidiariesover our claims as a direct or indirect equity holder in our subsidiaries and, thereby, indirect priority over noteholder claims. As a result, upon anydistribution to these creditors in a bankruptcy, liquidation or reorganization or similar proceeding relating to us or our property, these creditors will beentitled 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 tradecreditors 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 ourcreditors and noteholders may therefore receive less, ratably, than creditors of our subsidiaries. As of September 30, 2013, the notes ranked structurally juniorto $245.2 million of indebtedness and other liabilities of our subsidiaries. 20 Table of ContentsRestrictive covenants in the agreements governing our indebtedness and other financial obligations of our subsidiaries may reduce our operatingflexibility.The indenture governing our notes and the revolving credit facility agreement contain various covenants that limit our ability and the ability ofspecified 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 orthe economy in general, conduct operations or otherwise take advantage of business opportunities that may arise. The agreements also require us to maintainspecified financial ratios and satisfy other financial conditions. Our ability to meet those financial ratios and conditions can be affected by events beyondtheir 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 relevantindebtedness 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 orliquidation proceeding or proceed against the collateral, if any. If the lenders of our indebtedness or other financial obligations accelerate the repayment ofborrowings 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 controloffer to repurchase the notes at 101% of their principal amount, plus accrued and unpaid interest. The terms of our indebtedness limit our ability torepurchase the notes in those circumstances. Any of our future debt agreements may contain similar restrictions and provisions. Accordingly, we may beunable to satisfy our obligations to purchase the notes unless we are able to refinance or obtain waivers under our indebtedness. We may not have thefinancial resources to purchase the notes, particularly if a change of control event triggers a similar repurchase requirement for, or results in the accelerationof, other indebtedness. Our failure to make or consummate a change of control repurchase offer or pay the change of control purchase price when due willgive 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, $44.7million 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 thechange of control provisions under the notes. Accordingly, any event which would be a “change of control” under the senior notes would also be a “changeof control” under such other indebtedness. We are not restricted from entering into a transaction that would trigger the change of control provisions. If thesechange 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 ofany 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. 21 Table of ContentsA lowering or withdrawal of the ratings assigned to our debt securities by rating agencies may increase our future borrowing costs and reduce ouraccess 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 thatrating agency’s judgment, future circumstances relating to the basis of the rating, such as adverse changes, so warrant. Consequently, real or anticipatedchanges 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 eitherStandard & Poor’s or Moody’s Investors Service would increase the interest rate on our revolving credit facility, decrease earnings and may result in higherborrowing 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 ratinginitially assigned to the notes is subsequently lowered or withdrawn for any reason, noteholders may not be able to resell their notes without a substantialdiscount. ITEM 1B.UNRESOLVED STAFF COMMENTSNot applicable. ITEM 2.PROPERTIESWe provide services to our customers in the United States from Maine to South Carolina from 35 principal operating locations and 72 depots, 31 ofwhich 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 ownedand 1,066 service vans, the majority of which were leased. We lease our corporate headquarters in Stamford, Connecticut. Our obligations under ourrevolving 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—LITIGATIONWe 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 orproceeding. ITEM 4.MINE SAFETY DISCLOSURESNot applicable.PART II ITEM 5.MARKET FOR REGISTRANT’S UNITS AND RELATED MATTERSThe 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 fiscal2013 and 2012 quarters indicated. SGU – Common Unit Price Range Distributions Declared High Low per Unit FiscalYear2013 FiscalYear2012 FiscalYear2013 FiscalYear2012 FiscalYear2013 FiscalYear2012 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. 22 Table of ContentsPartnership Distribution ProvisionsWe are required to make distributions in an amount equal to our Available Cash, as defined in our Partnership Agreement, no more than 45 days afterthe end of each fiscal quarter, to holders of record on the applicable record dates. Available Cash, as defined in our Partnership Agreement, generally meansall 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 itsreasonable discretion for future cash requirements. These reserves are established for the proper conduct of our business, including the payment of debtprincipal and interest, for minimum quarterly distributions during the next four quarters and to comply with applicable laws and the terms of any debtagreements or other agreement to which we are subject. The Board of Directors of our general partner reviews the level of Available Cash each quarter basedupon 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 mostrestrictive covenant is found in the Partnership’s revolving credit facility. Under the terms of our revolving credit facility, the Partnership must maintainAvailability of $61.3 million, 17.5% of the maximum facility size of $350 million (assuming a seasonal advance of $100 million is outstanding) on ahistorical 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 orrepurchase 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 respectof the fourth quarter of fiscal 2013 payable on November 14, 2013 to holders of record on November 12, 2013. In accordance with our PartnershipAgreement, the amount of distributions in excess of the minimum quarterly distribution of $0.0675, are distributed 90% to the holders of common units and10% 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 millionto management pursuant to the management incentive compensation plan which provides for certain members of management to receive incentivedistributions that would otherwise be payable to the general partner.Common Unit Repurchase Plans and RetirementSince July 21, 2009 (the start of the Plan I common units repurchase program) to November 30, 2013 (the current Plan III common units repurchaseprogram 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 priceof $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 forrepurchase 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 forrepurchase 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 Boardauthorized an additional 1.9 million common units to be repurchased under its Plan III common unit repurchase plan. The authorized common unitrepurchases may be made from time-to-time in the open market, in privately negotiated transactions or in such other manner deemed appropriate bymanagement. There is no guarantee of the exact number of units that will be purchased under the program and the Partnership may discontinue purchases atany 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 privatetransaction. The Partnership’s repurchase activities take into account SEC safe harbor rules and guidance for issuer repurchases. All of the common unitspurchased 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 sizeof $350 million (assuming a seasonal advance of $100 million is outstanding) on a historical pro forma and forward-looking basis, and a fixed chargecoverage ratio of not less than 1.15 in order to repurchase common units. 23 Table of Contents(in thousands, except per unit amounts) Period Total Number of UnitsPurchased as Part of aPublicly Announced Plan orProgram Average PricePaid per Unit (a) Maximum Number of Unitsthat May Yet Be PurchasedUnder 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. 24 Table of ContentsITEM 6.SELECTED HISTORICAL FINANCIAL AND OPERATING DATAThe selected financial data as of September 30, 2013 and 2012, and for the years ended September 30, 2013, 2012 and 2011 is derived from thefinancial statements of the Partnership included elsewhere in this Report. The selected financial data as of September 30, 2011, 2010 and 2009 and for theyears ended September 30, 2010 and 2009 is derived from financial statements of the Partnership not included in this Report. See Item 7. Management’sDiscussion 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, incometaxes, 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 SignificantAccounting 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 Note17. Earnings Per Limited Partner Units, of the condensed consolidated financial statements. 25 Table of Contents(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 ofderivatives, gain or loss on debt redemption, goodwill impairment, and other non-cash and non-operating charges) are non-GAAP financial measuresthat are used as supplemental financial measures by management and external users of our financial statements, such as investors, commercial banksand 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 petroleumproducts 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 itslimitations as an analytical tool, should not be considered in isolation and should be viewed in conjunction with measurements that are computed inaccordance 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 EBITDAand 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 AtmosphericAdministration (“NOAA”). 26 Table of ContentsITEM 7.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONSStatement Regarding Forward-Looking DisclosureThis Annual Report on Form 10-K includes “forward-looking statements” which represent our expectations or beliefs concerning future events thatinvolve risks and uncertainties, including those associated with the effect of weather conditions on our financial performance, the price and supply of theproducts that we sell, the consumption patterns of our customers, our ability to obtain satisfactory gross profit margins, our ability to obtain new customersand retain existing customers, our ability to make strategic acquisitions, the impact of litigation, our ability to contract for our current and future supplyneeds, natural gas conversions, future union relations and the outcome of current and future union negotiations, the impact of current and futuregovernmental 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 factsincluded in this Report including, without limitation, the statements under “Management’s Discussion and Analysis of Financial Condition and Results ofOperations” 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 suchforward-looking statements are reasonable, we can give no assurance that such expectations will prove to be correct and actual results may differ materiallyfrom 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 Reportunder 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 personsacting on its behalf are expressly qualified in their entirety by the Cautionary Statements. Unless otherwise required by law, we undertake no obligation toupdate or revise any forward-looking statements, whether as a result of new information, future events or otherwise after the date of this Report.OverviewThe following is a discussion of our historical financial condition and results of our operations and should be read in conjunction with the descriptionof our business and the historical financial and operating data and notes thereto included elsewhere in this Report.SeasonalityThe following matters should be considered in analyzing our financial results. Our fiscal year ends on September 30. All references to quarters andyears respectively in this document are to the fiscal quarters and years unless otherwise noted. The seasonal nature of our business has resulted, on averageduring 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 volumein 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 Juneand September. In addition, sales volume typically fluctuates from year to year in response to variations in weather, wholesale energy prices and other factors.Degree DayA “degree day” is an industry measurement of temperature designed to evaluate energy demand and consumption. Degree days are based on how farthe average daily temperature departs from 65°F. Each degree of temperature above 65°F is counted as one cooling degree day, and each degree oftemperature 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 amonthly 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 NationalWeather 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 datacovers the years from 1981 to 2010. Our calculations of normal weather are based on these published 30 year averages for heating degree days, weighted byvolume for the locations where we have existing operations. 27 Table of ContentsHome Heating Oil Price VolatilityIn recent years, the wholesale price of home heating oil has been volatile, resulting in increased consumer price sensitivity to heating costs andincreased gross customer losses. As a commodity, the price of home heating oil is generally impacted by many factors, including economic and geopoliticalforces. 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. Thevolatility in the wholesale cost of home heating oil, as measured by the New York Mercantile Exchange (“NYMEX”) price per gallon for the fiscal yearsending September 30, 2009, through 2013, on a quarterly basis, is illustrated in the following chart: Fiscal 2013 Fiscal 2012 Fiscal 2011 Fiscal 2010 Fiscal 2009 Quarter Ended Low High Low High Low High Low High Low High December 31 $2.90 $3.26 $2.72 $3.17 $2.19 $2.54 $1.78 $2.12 $1.20 $2.85 March 31 2.86 3.24 2.99 3.32 2.49 3.09 1.89 2.20 1.13 1.63 June 30 2.74 3.09 2.53 3.25 2.75 3.32 1.87 2.35 1.31 1.86 September 30 2.87 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 VolatilityOur liquidity is adversely impacted in times of increasing wholesale product costs, as we must use more cash to fund our hedging requirements and aportion of the increased levels of accounts receivable and inventory. Our liquidity is also adversely impacted at times by sudden and sharp decreases inwholesale product costs due to the increased margin requirements for futures contracts and collateral requirements for options and swaps that we use tomanage market risks.Impact of Warm Weather on Operating Results; Weather Hedge Contract—Fiscal Year 2012Weather conditions have a significant impact on the demand for home heating oil and propane because customers depend on these productsprincipally for heating purposes. Actual weather conditions can vary substantially from year to year, significantly affecting our financial performance. Topartially 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, weentered 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 numberof heating degree-days in the period covered less than 92.5% of the ten year average, the Payment Threshold. The hedge covered the period fromNovember 1, 2011 through March 31, 2012, taken as a whole. Due to the abnormally warm weather conditions that fiscal year, the hedge resulted in amaximum 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 andwas collected in April 2012.Weather Hedge Contract—Fiscal Years 2013, 2014 and 2015In July 2012, the Partnership entered into a weather hedge contract for the fiscal years 2013, 2014 and 2015, with Swiss Re Financial ProductsCorporation, 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 theperiod 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, takenas 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 underits weather hedge contract during fiscal 2013.Per Gallon Gross Profit MarginsWe 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 fairvalue of derivative instruments (as we believe that realized per gallon margins should not include the impact of non-cash changes in the market value ofhedges 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 fixedprice for home heating oil over a fixed period of time, generally twelve months (“price-protected” customers). When these price-protected customers agree topurchase home heating oil from us for the next heating season, we purchase option contracts, swaps and futures contracts for a substantial majority of theheating 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 theestimated 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, ourhedging losses could be greater, thus reducing expected margins. 28(1) Table of ContentsDerivativesFASB ASC 815-10-05 Derivatives and Hedging requires that derivative instruments be recorded at fair value and included in the consolidated balancesheet as assets or liabilities. To the extent derivative instruments designated as cash flow hedges are effective, as defined under this guidance, changes in fairvalue are recognized in other comprehensive income until the forecasted hedged item is recognized in earnings. We have elected not to designate ourderivative instruments as hedging instruments under this guidance, and as a result, the changes in fair value of the derivative instruments are recognized inour statement of operations. Therefore, we experience volatility in earnings as outstanding derivative instruments are marked to market and non-cash gainsand 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 onderivative instruments can be significant to our overall results. However, we ultimately expect those gains and losses to be offset by the cost of product whenpurchased.New York State Ultra Low Sulfur Fuel Oil RegulationOn 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 homeheating 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 lowsulfur 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 tradeonly the high sulfur home heating oil hedge contract through March 31, 2013. Effective as of April 1, 2013, the NYMEX contract specifications werechanged 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 ninemonth 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 Statecustomers while a contract was not directly available to hedge on the NYMEX. The Partnership hedged the purchases of ultra low sulfur home heating oilfrom 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 theNYMEX 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 heatingoil 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 theNYMEX 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 inthe 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 TaxesNet Operating Loss Carry ForwardsThe Partnership and its corporate subsidiaries file Federal and State income tax returns on a calendar year. As of December 31, 2012, our Federal NetOperating 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 suchlosses that can be used.Book Versus Tax DeductionsThe 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 ourcorporate subsidiaries are required to pay. The amount of depreciation and amortization that we deduct for book (i.e., financial reporting) purposes will differfrom the amount that our subsidiaries can deduct for tax purposes. The table below compares the estimated depreciation and amortization for book purposesto the amount that our subsidiaries expect to deduct for tax purposes based on currently owned assets. Our subsidiaries file their tax returns based on acalendar 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 29 Table of ContentsNon-Deductible Partnership ExpensesThe Partnership incurs certain expenses at the Partnership level that are not deductible for Federal or state income tax purposes by our corporatesubsidiaries. As a result, our effective tax rate could differ from the statutory rate that would be applicable if such expenses were deductible.Storm SandyOn October 29, 2012, the storm known as “Sandy” made landfall in our service area, resulting in widespread power outages for a number of ourcustomers. In addition, certain third-party terminals where we purchase and store liquid product were closed for a short period of time due to damagesustained from the storm or by the loss of power. During the period subsequent to the storm, our operations and systems functioned without any meaningfuldisruptions.Deliveries of home heating oil and propane were less than expected for certain of our customers who were without power for several weeks subsequentto storm Sandy. However, since our operations were able to provide uninterrupted service to current and new customers, our sales of diesel fuel increasedduring 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 ofderivatives, gain or loss on debt redemption, goodwill impairment, and other non-cash and non-operating charges) are non-GAAP financial measures that areused as supplemental financial measures by management and external users of our financial statements, such as investors, commercial banks and researchanalysts, 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 petroleumproducts, 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 itslimitations as an analytical tool, should not be considered in isolation and should be viewed in conjunction with measurements that are computed inaccordance 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 EBITDAand 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 AttritionWe measure net customer attrition on an ongoing basis for our full service residential and commercial home heating oil and propane customers. Netcustomer attrition is the difference between gross customer losses and customers added through marketing efforts. Customers added through acquisitions arenot included in the calculation of gross customer gains. However, additional customers that are obtained through marketing efforts or lost at newly acquiredbusinesses are included in these calculations. Customer attrition percentage calculations include customers added through acquisitions in the denominatorsof the calculations on a weighted average basis. Gross customer losses are the result of a number of factors, including price competition, move-outs, creditlosses 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 signingup the new homeowner, the “move in” is treated as a gain. 30 Table of ContentsGross 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 of21,000 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 anincrease 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 asmarketing 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 fiscal2011. Conversions to natural gas have been increasing, and we believe this may continue as natural gas has become significantly less expensive than homeheating oil on an equivalent BTU basis. In addition, the states of New York, Connecticut and Pennsylvania are seeking to encourage homeowners to expandthe use of natural gas as a heating fuel through legislation and regulatory efforts.Consolidated Results of OperationsThe following is a discussion of the consolidated results of operations of the Partnership and its subsidiaries, and should be read in conjunction withthe historical Financial and Operating Data and Notes thereto included elsewhere in this Annual Report. 31 Table of ContentsFiscal Year Ended September 30, 2013Compared to the Fiscal Year Ended September 30, 2012VolumeFor 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 to277.2 million gallons for fiscal 2012. For those locations where the Partnership had existing operations during both periods, which are sometimes referred toas the “base business” (i.e., excluding acquisitions), temperatures (measured on a heating degree day basis) for fiscal 2013, were 22.3% colder than fiscal2012, but 4.1% warmer than normal, as reported by the National Oceanic and Atmospheric Administration (“NOAA”). For the twelve months endedSeptember 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 ofhome heating oil and propane over the last several years, we believe that our customers are adopting conservation measures to use less product. The impact ofconservation, along with any period-to-period differences in delivery scheduling, the timing of accounts added or lost during the fiscal years, equipmentefficiency 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 heatingoil and propane were less than expected for certain of our customers who were without power for several weeks subsequent to this storm. The home heatingoil 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 homeheating 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 Oiland 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 milliongallons 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 homeheating oil wholesale sales.Product SalesFor 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 intotal volume of 16.2%.Installation and Service SalesFor 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 toadditional revenue from acquisitions of $5.6 million and an increase in the base business of $15.2 million largely attributable to Sandy-related service andinstallation billings and the additional billings associated with 22.3% colder temperatures. 32 Table of ContentsCost of ProductFor 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 intotal volume of 16.2%.Gross Profit—ProductThe table below calculates the Partnership’s per gallon margins and reconciles product gross profit for home heating oil and propane and otherpetroleum products. We believe the change in home heating oil and propane margins should be evaluated before the effects of increases or decreases in thefair 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 ofhedges before the settlement of the underlying transaction. On that basis, home heating oil and propane margins for fiscal 2013, increased by $0.0234 pergallon, 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) PerGallon Amount(in millions) PerGallon 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(inmillions) PerGallon Amount(inmillions) PerGallon 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(inmillions) Amount(inmillions) 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 increasein 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 grossprofit from other petroleum products ($3.5 million).Cost of Installations and ServiceFor 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 theadditional 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 profitfrom 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 serviceand installation department on a combined basis because many overhead functions and direct expenses such as service technician time cannot be separatedor precisely allocated to either service or installation billings. 33 Table of Contents(Increase) / Decrease in the Fair Value of Derivative InstrumentsDuring fiscal 2013, the change in the fair value of derivative instruments resulted in a $6.8 million charge due to the expiration of certain hedgedpositions (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 hedgedpositions (a $7.4 million credit) a decrease in market value for unexpired (a $1.1 million credit).Delivery and Branch ExpensesFor 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 toan 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 millionand 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 weatherhedge 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 branchexpenses 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 werespread over a larger volume base in fiscal 2013.Depreciation and AmortizationFor fiscal 2013, depreciation and amortization expenses increased by $0.9 million, or 5.5%, to $17.3 million, compared to $16.4 million for fiscal2012.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 $1.2million 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 ExpensesFor 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 lowerlegal 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 thisamount is payable when the Partnership achieves Adjusted EBITDA of at least 70% of the amount budgeted. The dollar amount of the profit sharing pool issubject to increases and decreases in line with increases and decreases in Adjusted EBITDA.Finance Charge IncomeFor 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, thePartnership shortened the time period before billing finance charges which drove this increase.Interest Expense, NetFor 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 anincrease in average working capital borrowings of $5.9 million.Amortization of Debt Issuance CostsFor 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 ExpenseFor 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 incomeof $7.3 million. 34 Table of ContentsNet IncomeFor 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 millionwas greater than the increase in income tax expense of $3.3 million.Adjusted EBITDAFor 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 homeheating oil and propane per gallon margins, acquisitions, and the favorable impact of the storm Sandy on motor fuel sales and service and installationrevenue 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 nosimilar 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 alternativeto cash flow (as a measure of liquidity or ability to service debt obligations), but provides additional information for evaluating our ability to paydistributions.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 ofderivatives, gain or loss on debt redemption, goodwill impairment, and other non-cash and non-operating charges) are non-GAAP financial measuresthat are used as supplemental financial measures by management and external users of our financial statements, such as investors, commercial banksand 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 petroleumproducts, 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. 35 Table of ContentsThe method of calculating Adjusted EBITDA may not be consistent with that of other companies and each of EBITDA and Adjusted EBITDA has itslimitations as an analytical tool, should not be considered in isolation and should be viewed in conjunction with measurements that are computed inaccordance 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 andEBITDA 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 SignificantAccounting Policies Reclassification, operating income, EBITDA and Adjusted EBITDA have been revised but net income has not changed. 36 Table of ContentsFiscal Year Ended September 30, 2012Compared to the Fiscal Year Ended September 30, 2011VolumeFor 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 to355.6 million gallons for fiscal 2011. For those locations where the Partnership had existing operations during both periods, which are sometimes referred toas the “base business” (i.e., excluding acquisitions), temperatures (measured on a heating degree day basis) for fiscal 2012 were 21.4% warmer than fiscal2011 and 21.7% warmer than normal, as reported by the National Oceanic and Atmospheric Administration (“NOAA”). In the New York City MetropolitanArea, 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 warmestcomparable period. For fiscal 2012, net customer attrition for the base business was 5.4%. Due to various reasons including the significant increase in theprice per gallon of home heating oil and propane over the last several years, we believe that some of our customers have been adopting conservationmeasures to use less of such products. The impact of any such conservation, along with any period-to-period differences in delivery scheduling, equipmentefficiency and other volume variances not otherwise described, are included in the chart under the heading “Other.” We believe the unseasonably warmweather for fiscal 2012 generally magnified the conditions and opportunities for conservation. The timing of accounts added or lost during the fiscal yearcould also impact the fiscal year comparison. An analysis of the change in the retail volume of home heating oil and propane, which is based onmanagement’s estimates, sampling and other mathematical calculations and certain assumptions, is found below: (in millions of gallons) Heating Oiland 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 milliongallons for fiscal 2011, as the additional volume from acquisitions was partially offset by a decline in the base business primarily due to the warmertemperatures.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 SalesFor 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 of17.1% 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 SalesFor 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 theadditional 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 customerattrition. 37 Table of ContentsCost of ProductFor 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 totalvolume of 17.1% more than offset the impact of higher per gallon wholesale product costs of $0.4465, or 16.8%.Gross Profit—ProductThe table below calculates the Partnership’s per gallon margins and reconciles product gross profit for home heating oil and propane and otherpetroleum products. We believe the change in home heating oil and propane margins should be evaluated before the effects of increases or decreases in thefair 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 ofhedges before the settlement of the underlying transaction. On that basis, home heating oil and propane margins for fiscal 2012 increased by $0.0180 pergallon, 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) PerGallon Amount(in millions) PerGallon 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(inmillions) PerGallon Amount(in millions) PerGallon 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(inmillions) 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 ofhigher home heating oil and propane margins ($5.0 million) and the additional gross profit from other petroleum products ($2.8 million) was more than offsetby 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, or16.8% in fiscal 2012 versus fiscal 2011. If wholesale product costs continue to escalate, our ability to maintain and/or expand margins may be diminishedand our profitability may be adversely impacted.Cost of Installations and ServiceFor 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 costsin our base business. Net customer attrition, the impact of 21.4 % warmer weather and the Partnership’s efforts at reducing operating costs were the principalcauses 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 profitfrom 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 inservice expenses in the base business. Management views the service and installation department on a combined basis because many overhead functions anddirect expenses such as service technician time cannot be separated or precisely allocated to either service or installation billings. 38 Table of Contents(Increase) Decrease in the Fair Value of Derivative InstrumentsDuring fiscal 2012, the change in the fair value of derivative instruments resulted in a $8.5 million credit due to the expiration of certain hedgedpositions (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 hedgedpositions (a $4.9 million credit) and a decrease in market value for unexpired hedges (a $7.5 million charge).Delivery and Branch ExpensesFor 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 theadditional expense from acquisitions of $12.9 million was more than offset by a $12.5 million credit recorded under the Partnership’s weather hedge contractalong 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, lowerinsurance expense and lower bad debt expense. In addition, in response to the warmer weather in the fiscal 2012 heating season, management reducedexpenses 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 2012increased $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 asvehicle 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 AmortizationFor fiscal 2012, depreciation and amortization expenses decreased by $1.5 million, or 8.3% to $16.4 million, compared to $17.9 million for fiscal2011.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 waspartially offset by a decrease of $0.4 million related to fleet assets which became fully depreciated in fiscal 2011 and fiscal 2012. Amortization expenserelating 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 livesand trade names acquired with twenty year lives.General and Administrative ExpensesFor 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 anincrease 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 $1.6million.The Partnership accrues approximately 6% of adjusted EBITDA as defined in its profit sharing plan for distribution to its employees, and this amount ispayable when the Partnership achieves adjusted EBITDA of at least 70% of the amount budgeted. The dollar amount of the profit sharing pool is subject toincreases and decreases in line with increases and decreases in adjusted EBITDA.Finance Charge IncomeFor 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 accountsreceivable balances.Interest Expense, NetFor 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 tolower 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 $2.7million, 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. InNovember 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 Notesdue 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%. 39 Table of ContentsAmortization of Debt Issuance CostsFor 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 reductionwas 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 revolvingcredit facility termination date from July 2012 to June 2016.Loss on Redemption of DebtIn 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 at99.350% 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 our10.25% Senior Notes due 2013, at an average price of $101.70 per $100 of principal plus accrued interest, with the remainder used for general Partnershippurposes. 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 ExpenseFor 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 pretaxincome 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 inexpenses at the partnership level in 2012 compared to 2011 that are not deductible on our corporate tax returns.Net IncomeFor 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 millionwas less than the decrease in income tax expense of $6.1 million.Adjusted EBITDAFor 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 customerattrition and other reductions in home heating oil and propane volume more than offset an increase in Adjusted EBITDA provided by fiscal 2012 and 2011acquisitions, an increase in home heating oil and propane per gallon gross profit margins, $12.5 million recorded under the Partnership’s weather hedgecontract 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 alternativeto cash flow (as a measure of liquidity or ability to service debt obligations), but provides additional information for evaluating our ability to paydistributions.EBITDA and Adjusted EBITDA are calculated as follows: 40 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 ofderivatives, gain or loss on debt redemption, goodwill impairment, and other non-cash and non-operating charges) are non-GAAP financial measuresthat are used as supplemental financial measures by management and external users of our financial statements, such as investors, commercial banksand 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 petroleumproducts 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 itslimitations as an analytical tool, should not be considered in isolation and should be viewed in conjunction with measurements that are computed inaccordance 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 andEBITDA 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 SignificantAccounting Policies Reclassification, operating income, EBITDA and Adjusted EBITDA have been revised but net income has not changed. 41 Table of ContentsDISCUSSION OF CASH FLOWSWe use the indirect method to prepare our Consolidated Statements of Cash Flows. Under this method, we reconcile net income to cash flows providedby operating activities by adjusting net income for those items that impact net income but may not result in actual cash receipts or payment during theperiod.Operating ActivitiesDue to the seasonal nature of our business, cash is generally used in operations during the winter (our first and second fiscal quarters) as we requireadditional working capital to support the high volume of sales during this period, and cash is generally provided by operating activities during the springand 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 cashprovided by operating activities during fiscal 2012, as a favorable change in cash generated from operations of $9.5 million and increases in accruals forinsurance, 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 fundaccounts 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 infiscal 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 customercredit 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 $34.1million. 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 changeresulted 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 fiscal2011 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 tofinance 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 higherselling 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 collectedfrom our budget payment plan customers also favorably impacted the year to year comparison by $13.7 million, as sales for fiscal 2012 were less thanexpected due to the warm weather and when compared to fiscal 2011. Changes in per gallon inventory values and quantities drove a favorable change in cashneeds 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 cashand 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 ActivitiesOur capital expenditures for fiscal 2013 totaled $6.0 million, as we invested in computer hardware and software ($1.9 million), refurbished certainphysical plants ($1.2 million), expanded our propane operations ($1.9 million) and made additions to our fleet and other equipment ($1.0 million). We alsocompleted 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 andreduced 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 physicalplants ($0.8 million), expanded our propane operations ($1.4 million) and made additions to our fleet and other equipment ($1.8 million). We also completedfive 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 inworking capital.Financing ActivitiesDuring 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 ourPartnership 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 $19.3million to our common unit holders, $0.2 million to our general partner (including $0.1 million of incentive distributions as provided in our PartnershipAgreement) and repurchased 4.0 million units for $19.6 million in connection with our unit repurchase plan. 42 Table of ContentsFINANCING AND SOURCES OF LIQUIDITYLiquidity and Capital ResourcesOur primary uses of liquidity are to provide funds for our working capital, capital expenditures, distributions on our units, acquisitions and unitrepurchases. Our ability to provide funds for such uses depends on our future performance, which will be subject to prevailing economic, financial, businessand weather conditions, the ability to pass on the full impact of high product costs to customers, the effects of high net customer attrition, conservation andother factors. Capital requirements, at least in the near term, are expected to be provided by cash flows from operating activities, cash on hand as ofSeptember 30, 2013 ($85.1 million) or a combination thereof. To the extent future capital requirements exceed cash on hand plus cash flows from operatingactivities, we anticipate that working capital will be financed by our revolving credit facility, as discussed below, and repaid from subsequent seasonalreductions in inventory and accounts receivable. If we require additional capital and the credit markets are receptive, we may seek to offer and sell debt orequity 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 duringthe heating season from November through April of each year) for working capital purposes (subject to certain borrowing base limitations and coverageratios), 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 bankgroup. 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 additionallenders to the group, with the consent of the Agent, which shall not be unreasonably withheld. Obligations under the revolving credit facility are guaranteedby 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 wereoutstanding 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 ofcredit 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 EBITDAfor the trailing twelve month period. As of September 30, 2013, Availability, as defined in the revolving credit facility agreement, was $164.3 million and wewere 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 leasedfleet. In addition, we plan to invest an estimated $1.5 million in our propane operations. Paying distributions during fiscal 2014 at the current quarterly levelof $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 incentivecompensation plan which provides for certain members of management to receive incentive distributions that would otherwise be payable to the generalpartner. For fiscal 2014, the Partnership’s scheduled interest payments on its Senior Notes, which are due in November 2017, amount to $11.1 million. Basedupon the funding requirements of the Pension Protection Act, and certain actuarial assumptions, we estimate that the Partnership will be required to makecash contributions to its frozen defined benefit pension obligations totaling approximately $6.1 million over the next five fiscal years. In addition, we willcontinue to repurchase common units pursuant to our unit repurchase plan and seek attractive acquisition opportunities within the Availability constraints ofour revolving credit facility and funding resources.Partnership Distribution ProvisionsOn 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 withrespect to the fourth quarter of fiscal 2013 payable on November 14, 2013 to holders of record on November 8, 2013. In accordance with our PartnershipAgreement, the amount of distributions in excess of the minimum quarterly distribution of $0.0675, are distributed 90% to the holders of common units and10% 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 ourPartnership Agreement) and $0.05 million to management pursuant to the management incentive compensation plan, which provides for certain members ofmanagement 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 ofAvailable Cash) 43 Table of ContentsContractual Obligations and Off-Balance Sheet ArrangementsWe 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-cancelablepurchase obligations are obligations we incur during the normal course of business, based on projected needs. The Partnership had no capital leaseobligations 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 predictthe 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 and2016 2017 and2018 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 andstatement 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 onthe 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 PronouncementsIn 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 morelikely 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 theeffect of those arrangements on its financial position. The amendments require added disclosures about financial instruments and derivative instruments thatare either (1) offset in accordance with other GAAP or (2) subject to an enforceable master netting arrangement or similar agreement, regardless of whetherthey 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. Theadoption 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 impacton our disclosures. 44 Table of ContentsCritical Accounting EstimatesThe preparation of financial statements in conformity with Generally Accepted Accounting Principles requires management to establish accountingpolicies and make estimates and assumptions that affect reported amounts of assets and liabilities at the date of the Consolidated Financial Statements. ThePartnership evaluates its policies and estimates on an on-going basis. A change in any of these critical accounting estimates could have a material effect onthe results of operations. The Partnership’s Consolidated Financial Statements may differ based upon different estimates and assumptions. The Partnership’scritical 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 ourcritical accounting policies and estimates:Goodwill and Other Intangible AssetsWe calculate amortization using the straight-line method over periods ranging from five to twenty years for intangible assets with finite useful livesbased on historical statistics. We use amortization methods and determine asset values based on our best estimates using reasonable and supportableassumptions and projections. For significant acquisitions we may engage a third party valuation firm to assist in the valuation of intangible assets of thatacquisition. We assess the useful lives of intangible assets based on the estimated period over which we will receive benefit from such intangible assets suchas 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 fiscal2013 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 involvemanagement’s estimates of future cash flows, market trends and other factors to determine the fair value of the reporting unit, which includes the goodwill tobe 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 determinedto 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 basedon this analysis that there was no goodwill impairment as of August 31, 2013. The preparation of this analysis was based upon management’s estimates andassumptions, and future impairment calculations would be affected by actual results that are materially different from projected amounts. To provide for asensitivity of the discount rates and transaction multiples used, ranges of high and low values are employed in the analysis, with the low values examined toensure 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 marginsor 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 animpact 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 todetermine 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 MarketApproach (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 basedon discounted cash flows. The Partnership’s discount rate was calculated based on the weighted average cost of capital, using inputs of comparablecompanies in the same industry. The Partnership’s conclusion of the fair value of the reporting unit was supported based on a sensitivity analysis performedusing 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 securitiesare actively traded in public markets. A financial multiple range was calculated and applied to the financial metrics of the Partnership. The Partnership’sconclusion 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 comparablebusinesses. A transaction multiple was calculated and applied to the financial metrics of the Partnership. In addition, a transaction occurring after the analysisdate, but before the fiscal year-end was reviewed, and the Partnership’s conclusion of value was supported based on the calculations of these transactionmultiples.In addition, the Partnership performs a reasonableness check of its concluded value for its sole reporting unit by reconciling the results of the goodwillanalysis with its market capitalization. 45 Table of ContentsIntangible assets with finite lives must be assessed for impairment whenever changes in circumstances indicate that the assets may be impaired. Theassessment for impairment requires estimates of future cash flows related to the intangible asset. To the extent the carrying value of the assets exceeds itsfuture undiscounted cash flows, an impairment loss is recorded based on the fair value of the asset.Depreciation of Property and EquipmentDepreciation is calculated using the straight-line method based on the estimated useful lives of the assets ranging from 1 to 30 years. Net property andequipment was $51.3 million at September 30, 2013. If the remaining estimated useful lives of these assets were shortened by one year, we estimate thatdepreciation for fiscal 2013 would have increased by approximately $1.5 million.Fair Values of DerivativesFASB ASC 815-10-05, Derivatives and Hedging, requires that derivative instruments be recorded at fair value and included in the consolidatedbalance sheet as assets or liabilities. The Partnership has elected not to designate its derivative instruments as hedging instruments under this guidance, andthe 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 theminternally using established index prices and other sources. These values are based upon, among other things, future prices, volatility, time-to-maturity valueand credit risk. The estimate of fair value we report in our financial statements changes as these estimates are revised to reflect actual results, changes inmarket conditions, or other factors, many of which are beyond our control.Defined Benefit ObligationsFASB ASC 715-10-05, Compensation-Retirement Benefits, requires an employer to (i) measure the funded status of a defined benefit postretirementplan 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 orliability in its statement of financial position and (iii) to recognize changes in that funded status in the year which the changes occur through comprehensiveincome.This standard requires the Partnership to make assumptions as to the expected long-term rate of return that could be achieved on defined benefit planassets and discount rates to determine the present value of the plans’ pension obligations. The Partnership evaluates these critical assumptions at leastannually.The discount rate enables the Partnership to state expected future cash flows at a present value on the measurement date. The rate is required torepresent the market rate for high-quality fixed income investments. A lower discount rate increases the present value of benefit obligations and increasespension expense in the following fiscal year. A 25 basis point decrease in the discount rate used for fiscal 2013 would have increased pension expense byapproximately $0.1 million and would have increased the pension liability by another $2.0 million. The discount rate used to determine net periodic pensionexpense 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 whosecash 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 ourexpected 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’sinvestment advisors. The long-term rate of return assumption used for determining net periodic pension expense for fiscal 2013 was 7.00% and 7.75% forfiscal 2012. A further 25 basis point decrease in the expected return on assets would have increased pension expense in fiscal 2013 by approximately $0.1million. 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 assetsassumption 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 arerecognized.In addition, we participate in a number of trustee-managed multi-employer pension and health and welfare plans for employees covered undercollective bargaining agreements. The Partnership makes timely contributions as required by the plans. Several factors could result in potentially higherfuture contributions to these plans, including unfavorable investment performance, insolvency of participating employers, changes in demographics, andincreased benefits to participants. 46 Table of ContentsAllowance for Doubtful AccountsThe allowance for doubtful accounts is the Partnership’s best estimate of the amount of trade receivables that may not be collectible. The allowance isdetermined at an aggregate level (as opposed to account by account) by grouping accounts based on the type of account and its receivable aging. Theallowance is based on both quantitative and qualitative factors, including historical loss experience, historical collection patterns, overdue status, agingtrends, and current economic conditions. The Partnership has an established process to periodically review current and past due trade receivable balances todetermine the adequacy of the allowance. No single statistic or measurement determines the adequacy of the allowance. The total allowance reflectsmanagement’s estimate of losses inherent in its trade receivables at the balance sheet date. Different assumptions or changes in economic conditions couldresult in material changes to the allowance for doubtful accounts.Insurance ReservesWe currently self-insure a portion of workers’ compensation, auto and general liability claims. We establish reserves based upon expectations as towhat our ultimate liability may be for outstanding claims using developmental factors based upon historical claim experience, supplemented by a third-partyactuary. We periodically evaluate the potential for changes in loss estimates with the support of qualified actuaries. As of September 30, 2013, we hadapproximately $51.3 million of insurance reserves. The ultimate resolution of these claims could differ materially from the assumptions used to calculate thereserves, which could have a material adverse effect on results of operations. ITEM 7A.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKWe 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 interestrates.We regularly use derivative financial instruments to manage our exposure to market risk related to changes in the current and future market price ofhome heating oil. The value of market sensitive derivative instruments is subject to change as a result of movements in market prices. Sensitivity analysis is atechnique used to evaluate the impact of hypothetical market value changes. Based on a hypothetical ten percent increase in the cost of product atSeptember 30, 2013, the potential impact on our hedging activity would be to increase the fair market value of these outstanding derivatives by $14.1million 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 valueof these outstanding derivatives by $6.0 million to a negative fair market value of $(9.4) million. ITEM 8.FINANCIAL STATEMENTS AND SUPPLEMENTARY DATAThe financial statements and financial statement schedules referred to in the index contained on page F-1 of this report are incorporated herein byreference. ITEM 9.CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURENONE 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 controlsand 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 thatevaluation, such principal executive officer and principal financial officer concluded that the Partnership’s disclosure controls and procedures were effectiveas of September 30, 2013 at the reasonable level of assurance. For purposes of Rule 13a-15(e), the term disclosure controls and procedures means controlsand 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 underthe 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 anissuer in the reports that it files or submits under the Act is accumulated and communicated to the issuer’s management, including its principal executive andprincipal financial officer, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. 47 Table of Contents(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 inExchange Act Rules 13a-15(f) under the Securities Exchange Act of 1934, as amended. Under the supervision of management and with the participation ofour management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internalcontrol over financial reporting based on the framework in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizationsof the Treadway Commission, September 1992. Based on our evaluation of internal Control over financial reporting, our management concluded that ourinternal control over financial reporting was effective as of September 30, 2013. The effectiveness of our internal control over financial reporting as ofSeptember 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 materiallyaffected, 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 assurancethat 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, ifany, within the Partnership have been detected. Therefore, a control system, no matter how well conceived and operated, can provide only reasonable, notabsolute, assurance that the objectives of the control system are met. Our disclosure controls and procedures are designed to provide such reasonableassurances of achieving our desired control objectives, and the principal executive officer and principal financial officer of our general partner haveconcluded, as of September 30, 2013, that our disclosure controls and procedures were effective in achieving that level of reasonable assurance. ITEM 9B.OTHER INFORMATIONNot applicable.PART III ITEM 10.DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCEPartnership ManagementOur general partner is Kestrel Heat. The Board of Directors of Kestrel Heat is appointed by its sole member, Kestrel, which is a private equityinvestment 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 orelect the directors of the general partner. The Board of Directors (sometimes referred to as the “Board”) of Kestrel Heat has adopted a set of PartnershipGovernance Guidelines in accordance with the requirements of the New York Stock Exchange. A copy of these Guidelines is available on our website atwww.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 andoutstanding 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 totake into account the interests of parties other than the limited partners in resolving conflict of interest, thereby limiting such fiduciary duty. Notwithstandingany 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 theextent 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 formanaging or operating the Partnership. 48 Table of ContentsDirectors and Executive Officers of the General PartnerDirectors are appointed for an indefinite term, subject to the discretion of Kestrel. The following table shows certain information for directors andexecutive officers of the general partner as of November 30, 2013: Name Age PositionPaul A. Vermylen, Jr. 66 Chairman, DirectorSteven J. Goldman 53 President, Chief Executive Officer and DirectorRichard F. Ambury 56 Chief Financial Officer, Executive Vice President, Treasurer and SecretaryRichard G. Oakley 53 Vice President and ControllerHenry D. Babcock 73 DirectorC. Scott Baxter 52 DirectorDaniel P. Donovan 67 DirectorBryan H. Lawrence 71 DirectorSheldon B. Lubar 84 DirectorWilliam P. Nicoletti 68 Director Audit Committee memberPaul 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 hasserved as its President and as a manager since July 2005. Mr. Vermylen had been employed since 1971, serving in various capacities, including as a VicePresident of Citibank N.A. and Vice President-Finance of Commonwealth Oil Refining Co. Inc. Mr. Vermylen served as Chief Financial Officer of Meenan OilCo., L.P. (“Meenan”) from 1982 until 1992 and as President of Meenan until 2001, when we acquired Meenan. Since 2001, Mr. Vermylen has pursued privateinvestment opportunities. Mr. Vermylen serves as a director of certain non-public companies in the energy industry in which Kestrel holds equity interestsincluding Downeast LNG, Inc. and Moneta Energy Services Ltd. Mr. Vermylen is a graduate of Georgetown University and has an M.B.A. from ColumbiaUniversity.Mr. Vermylen’s substantial experience in the home heating oil industry and his leadership skills and experience as an executive officer of Meenan, amongother 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 ofKestrel Heat since October 29, 2013. From May 1, 2010 to September 30, 2013, Mr. Goldman was Executive Vice President and Chief Operating Officer ofKestrel Heat, and was Senior Vice President of Operations from April 1, 2007 until April 30, 2010. Mr. Goldman was Vice President of Operations of PetroHoldings, 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 alsoheld various positions within the management of companies in industrial engineering and those with international operations. Mr. Goldman is a graduate ofthe 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 theBoard 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 andSecretary 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 wasVice President of Star Gas Propane, L.P. From February 1996 to March 1999, Mr. Ambury served as Vice President—Finance of Star Gas Corporation, apredecessor general partner. Mr. Ambury was employed by Petroleum Heat and Power Co., Inc. from June 1983 through February 1996, where he served invarious accounting/finance capacities. From 1979 to 1983, Mr. Ambury was employed by a predecessor firm of KPMG, a public accounting firm. Mr. Amburyhas 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 heldvarious 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, aprivately 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 ranan 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 fromColumbia University. He is President of The Caumsett Foundation, Inc. 49(1)(1) (1)(1) Table of ContentsMr. Babcock’s significant experience in capital markets, corporate finance and venture capital, among other factors, led the Board to conclude that he shouldserve 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 energyinvestment banking firm, and manages their Houston office. Prior to joining Petrie Partners in 2013, Mr. Baxter was Managing Partner of Baxter EnergyPartners, a corporate energy M&A advisory firm which he founded. He previously held positions including Head of the Americas for J.P. Morgan’s globalenergy group, Managing Director in the global energy group at Citigroup (Salomon Brothers) and head of the energy group for Houlihan Lokey. Mr. Baxterhas 25 years of energy investment banking experience and has been a primary advisor in executing over $150 billion in corporate energy M&A, restructuringand private equity financing transactions. Mr. Baxter has also rendered over 30 independent fairness opinions for boards spanning the upstream to MLPsectors in the energy industry. Mr. Baxter holds a B.S. degree in Economics from Weber State University where he graduated cum laude, and received anMBA degree from the University of Chicago Graduate School of Business. Mr. Baxter has served as an adjunct professor of finance at Columbia University’sGraduate 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 concludethat 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 fromMay 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. Donovanwas also the Chief Operating Officer of Kestrel Heat. Mr. Donovan was the President and Chief Operating Officer of a predecessor general partner, Star GasLLC (“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 heatingoil segment. Mr. Donovan held various management positions with Meenan Oil Co. LP, from January 1980 to May 2004, including Vice President andGeneral Manager from 1998 to 2004. Mr. Donovan worked for Mobil Oil Corp. from 1971 to 1980. His last position with Mobil was President and GeneralManager 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 andreceived 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 thehome 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 afounder and senior manager of Yorktown, the manager of the Yorktown group of investment partnerships, which make investments in companies engaged inthe energy industry. The Yorktown partnerships were formerly affiliated with the investment firm of Dillon, Read & Co. Inc., where Mr. Lawrence wasemployed beginning in 1966, serving as a Managing Director until the merger of Dillon Read with SBC Warburg in September 1997. Mr. Lawrence alsoserves as a director of Approach Resources, Inc., Crosstex Energy, Inc., Hallador Petroleum Company (each a United States publicly traded company), WinstarResources 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 theBoard 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 Chairmanof the board of Lubar & Co. Incorporated, a private investment and venture capital firm he founded, since 1977. He was Chairman of the board of ChristianaCompanies, Inc., a logistics and manufacturing company, from 1987 until its merger with Weatherford International in 1995. Mr. Lubar had also beenChairman of Total Logistics, Inc., a logistics and manufacturing company until its acquisition in 2005 by SuperValu Inc. He has served as a director ofCrosstex Energy, Inc. from January 2004 until October 2012; Approach Resources, Inc. since June 2007, Crosstex Energy GP, LLC, the general partner ofCrosstex 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 honoraryDoctor 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 concludethat he should serve as a director of Kestrel Heat. 50 Table of ContentsWilliam 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 StarGas 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 GasCorporation from November 1995 until March 1999. Since February 1, 2009, he has been a Managing Director of Parkman Whaling LLC, a Houston, Texasbased energy investment banking firm. Previously, he was Managing Director of Nicoletti & Company, Inc., a private investment banking firm. Mr. Nicolettiwas formerly a senior officer and head of Energy Investment Banking for E. F. Hutton & Company, Inc., PaineWebber Incorporated and McDonaldInvestments, 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 andcorporate governance matters, among other factors, led the Board to conclude that he should serve as a director of Kestrel Heat.Director IndependenceSection 303A of the New York Stock Exchange listed company manual provides that limited partnerships are not required to have a majority ofindependent 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 highernumber as may be necessary to comply with the applicable federal securities law requirements. For the purposes of this policy, “independent director” has themeaning set forth in Section 10A(m) of the Securities Exchange Act of 1934, as amended, any applicable stock exchange rules and the rules and regulationspromulgated 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 DirectorsDuring fiscal 2013, the Board of Directors of Kestrel Heat met four times. All directors attended each meeting except for one meeting in which onedirector did not attend.Committees of the Board of DirectorsKestrel Heat’s Board of Directors has one standing committee, the Audit Committee. Its members are appointed by the Board of Directors for a one-yearterm and until their respective successors are elected. The NYSE corporate governance standards do not require limited partnerships to have a Nominating orCompensation Committee.Audit CommitteeWilliam P. Nicoletti, Henry D. Babcock and C. Scott Baxter have been appointed to serve on the Audit Committee, which has adopted an AuditCommittee 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 financialreporting of the Partnership, selects and engages the Partnership’s independent registered public accountants and approves all non-audit engagements of theindependent 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 StockExchange and SEC independence requirements for service on the Audit Committee. The Board of Directors has determined that Messrs. Nicoletti, Babcockand Baxter are independent directors in that they do not have any material relationships with the Partnership (either directly, or as a partner, shareholder orofficer of an organization that has a relationship with the Partnership) and they otherwise meet the independence requirements of the NYSE and the SEC. ThePartnership’s Board of Directors has also determined that at least one member of the Audit Committee, Mr. Nicoletti, meets the SEC criteria of an “auditcommittee 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 PartnerThe general partner does not receive any management fee or other compensation for its management of the Partnership. The general partner isreimbursed for all expenses incurred on behalf of the Partnership, including the cost of compensation, which is properly allocable to the Partnership. ThePartnership Agreement provides that the general partner shall determine the expenses that are allocable to the Partnership in any reasonable mannerdetermined by the general partner in its sole discretion. In addition, the general partner and its affiliates may provide services to the Partnership for which areasonable fee would be charged as determined by the general partner. There were no reimbursements in fiscal year 2013. 51 Table of ContentsAdoption of Code of Business Conduct and EthicsThe Partnership has adopted a written Code of Business Conduct and Ethics that applies to the Partnership’s officers, directors and employees. A copyof 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, bycontacting Investor Relations, (203) 328-7310.Section 16(a) Beneficial Ownership Reporting ComplianceBased on copies of reports furnished to us, we believe that during fiscal year 2013, all reporting persons complied with the Section 16(a) filingrequirements applicable to them.Non-Management Directors and Interested Party CommunicationsThe 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 StarGas Partners, L.P., 2187 Atlantic Street, Stamford, CT 06902. ITEM 11.EXECUTIVE COMPENSATIONCompensation Discussion and AnalysisThe Partnership’s Amended and Restated Agreement of Limited Partnership provides that the general partner of the Partnership, Kestrel Heat, shallconduct, direct and manage all activities of the Partnership. The limited liability company agreement of the general partner provides that the business of thegeneral 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 theinterest and for the benefit of the Partnership’s unitholders. Among the Board’s responsibilities is to regularly evaluate the performance and to approve thecompensation of the Chief Executive Officer and, with the advice of the Chief Executive Officer, regularly evaluate the performance and approve thecompensation 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 theChairman of the general partner and the majority of the Board are not employees, the Board determined that it has adequate independence to act in thecapacity of a Compensation Committee to establish and review the compensation of the Partnership’s executive officers and directors. The Board iscomprised of Paul A. Vermylen Jr. (Chairman), Steven J. Goldman (President and Chief Executive Officer), Daniel P. Donovan, Henry D. Babcock, C. ScottBaxter, 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 financialofficer (“CFO”) during fiscal 2013 and the two other most highly compensated executive officers serving at September 30, 2013 (there being no otherexecutive officers who earned more than $100,000 during fiscal 2013) are referred to as the “named executive officers” and are included in the ExecutiveCompensation Table.In this Compensation Discussion and Analysis, we address the compensation paid or awarded to Messrs. Donovan, Ambury, Goldman, and Oakley. Werefer 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 PoliciesThe primary objectives of the Partnership’s compensation program, including compensation of the named executive officers, are to attract and retainhighly qualified officers, employees and directors and to reward individual contributions to our success. The Board of Directors considers the followingpolicies 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 andnon-financial achievements; • compensation levels should be competitive to ensure that we will be able to attract, motivate and retain highly qualified executiveofficers; and • compensation should be related to improving unitholder value over time. 52 Table of ContentsCompensation MethodologyThe elements of the Partnership’s compensation program for named executive officers are intended to provide a total incentive package designed todrive performance and reward contributions in support of business strategies at the Partnership and operating unit level. Subject to the terms of employmentagreements 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 settingcompensation based on the policies discussed above under “Compensation Philosophy and Policies” , we reviewed the compensation paid to officersholding similar positions at our peer group companies to obtain a general understanding of the reasonableness of base salaries and other compensationpayable to our named executive officers. Our peer group of companies was comprised of the following companies: Amerigas Partners, L.P., Suburban PropanePartners, L.P., Ferrellgas Partners, L.P. and Global Partners, L.P. We chose these companies because they are master limited partnerships that are engaged inthe retail distribution of energy products like the Partnership.Elements of Executive CompensationFor 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 eachexecutive officer varies depending on their position. The base salary for each executive officer is the only fixed component of compensation. All othercompensation, 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 theCEO, CFO and COO, approximately 50% of the annual compensation is in the form of base salary and approximately 50% is from the discretionary profitsharing allocation. For the Vice President- Controller, approximately 65% of the annual compensation is in the form of base salary and 35% is from thediscretionary profit sharing allocations. In addition, during fiscal 2013, an aggregate of $118,542 was paid to the named executive officers under the terms ofthe Partnership’s management incentive compensation plan and represented a small portion of the executive compensation that was paid to these officers. Inthe future, the amounts payable to the named executive officers under the management incentive compensation plan should increase, if the Partnership issuccessful 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 uponeach executive officer’s individual performance and our overall performance. A goal of the compensation program is to provide executive officers with areasonable level of security through base salary and benefits, while rewarding them through incentive compensation to achieve business objectives andcreate unitholder value over time. As a result, officers with lower overall compensation levels will tend to have a higher percentage of base compensation. Webelieve that each of our compensation components is important in achieving this goal. Base salaries provide executives with a base level of monthly incomeand security. Annual discretionary profit sharing allocations and long-term incentive awards provide an incentive to our executives to achieve businessobjectives that increase our financial performance, which creates unitholder value through continuity of, and increases in, distributions and increases in themarket 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 SalaryThe 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 startingpoint is the historical compensation levels that the Partnership has paid to officers performing similar functions over the past few years. We also consider thelevel of experience and accomplishments of individual candidates and general labor market conditions, including the availability of candidates to fill aparticular position. When we make adjustments to the base salaries of existing named executive officers, we review the individual’s performance, the valueeach named executive officer brings to us and general labor market conditions. 53 Table of ContentsElements of individual performance considered, among others, without any specific weight given to each element, include business-relatedaccomplishments during the year, difficulty and scope of responsibilities, effective leadership, experience, expected future contributions to the Partnershipand difficulty of replacement. While base salary provides a base level of compensation intended to be competitive with the external market, the base salaryfor each named executive officer is determined on a subjective basis after consideration of these factors and is not based on target percentiles or other formalcriteria. Although we believe that base salaries for our named executive officers are generally competitive with the external market, we do not usebenchmarking as a fixed criterion to determine base compensation. Rather, after subjectively setting base salaries based on the above factors, we review thecompensation paid to officers holding similar positions at our peer group companies to obtain a general understanding of the reasonableness of base salariesand other compensation payable to our named executive officers. The Partnership also takes into account geographic differences for similar positions in theNew York Metropolitan area. While cost of living is considered in determining annual increases, the Partnership does not typically provide full cost of livingadjustments 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 AllocationsThe Partnership maintains a profit sharing pool for employees, including named executive officers, which in fiscal 2013 was equal to approximately6.0% of the Partnership’s earnings before income taxes, depreciation and amortization, excluding items affecting comparability (“adjusted EBITDA”). Theannual discretionary profit sharing allocations paid to the named executive officers are payable from this pool. The size of the pool fluctuates based uponupward or downwards changes in adjusted EBITDA. The amount of cash paid to the named executive officers under the plan is based on the targetpercentages of overall compensation described above under the caption “Elements of Executive Compensation.” Depending upon the size of the profitsharing 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 ourCEO 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 2013of 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 indeveloping his recommendations for profit sharing amounts. Based on such assessment, our CEO submits recommendations to the Board of Directors for theannual profit sharing amounts to be paid to our named executive officers, for the Board’s review and approval. Similarly, the Chairman assesses the CEO’scontribution toward meeting the Partnership’s goals based upon the above factors, and recommends to the Board of Directors a profit sharing allocation forthe 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 allocationsbased upon the factors discussed above.Management Incentive Compensation PlanIn 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 unitotherwise 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 thePartnership Agreement), less expenses and applicable taxes. 54 Table of ContentsThe Partnership believes that the Plan provides a long-term incentive to its participants because it encourages the Partnership’s management toincrease the Partnership’s available cash for distributions in order to trigger the incentive distributions that are only payable if distributions from availablecash exceeds certain target distribution levels, with higher percentages of incentive distributions triggered by higher levels of distributions. Such increasesare not sustainable on a consistent basis without long-term improvements in the Partnership’s operations. In addition, under certain Plan amendments thatwere adopted in 2012, the participation points of existing plan participants will vest and become irrevocable over a four year (three years for the CEO) periodstarting 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 personalinterest 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 2013Compensation Decisions—Management Incentive Compensation Plan.” The amount paid in Incentive Distributions is governed by the partnershipagreement and the calculation of Available Cash. Available Cash from Operating Surplus (as defined in our partnership agreement) is distributed to theholders 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 distributionof $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 ofthe 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 minimumquarterly 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 targetdistribution of $0.1125; andFinally, 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 ofcash reserves established by the Board of Directors of our general partner in its reasonable discretion for future cash requirements. These reserves areestablished for the proper conduct of our business, including acquisitions, the payment of debt principal and interest and for distributions during the nextfour 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 ofour 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 Distributionsthat are payable to plan participants. For accounting purposes, amounts payable to management under this Plan will be treated as compensation and willreduce both EBITDA and net income but not adjusted EBITDA. Kestrel Heat has also agreed to contribute to the Partnership, as a contribution to capital, anamount equal to the Gains Interest payable to participants in the Plan by the Partnership. The Partnership is not required to reimburse Kestrel Heat foramounts 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 fromtime 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 paymentswill 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 hasbeen amended and restated in its entirety. Under the Plan Amendments, the number and identity of the Plan participants and their participation interests inthe 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 thedeath 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 anemployee or consultant of the Partnership. Following the termination of such positions, a participant’s vested percentage shall be equal to 20% for each fullor 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 thePartnership’s chief executive officer).The Partnership distributed approximately $165,059 in Incentive Distributions under the Plan during fiscal 2013, including payments to the namedexecutive officers of approximately $118,542. With regard to the Gains Interest, Kestrel Heat has not given any indication that it will sell its general partnerunits within the next twelve months. Thus the Plan’s value attributable to the Gains Interest currently cannot be determined. 55 Table of ContentsRetirement and Health BenefitsThe Partnership offers a health and welfare and retirement program to all eligible employees. The named executive officers are generally eligible for thesame programs on the same basis as other employees of the Partnership. The Partnership maintains a tax-qualified 401(k) retirement plan that provideseligible employees with an opportunity to save for retirement on a tax advantaged basis. Under the Partnership’s 401(k) plan, subject to IRS limitations, eachparticipant 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 yearsof 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 compensationand 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 certainexecutive officers. The present value of accumulated benefits under these frozen defined benefit pension plans for certain executive officers is provided in thetable labeled, Pension Plans Pursuant to Which Named Executive Officers Have an Accumulated Benefit But Are Not Currently Accruing Benefits.Fiscal 2013 Compensation DecisionsFor fiscal 2013, the foregoing elements of compensation were applied as follows:Base SalaryThe following table sets forth each named executive officer’s base salary as of October 1, 2013 and the percentage increase in his base salary overOctober 1, 2012. The current base salaries for our named executive officers were determined during fiscal 2013, based upon the factors discussed under thecaption “Base Salary .” Mr. Donovan retired from his position as President and Chief Executive Officer effective as of September 30, 2013 so he is notincluded 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, 2013Annual Discretionary Profit Sharing AllocationBased on the annual performance reviews for the Partnership’s CEO and named executive officers, the Board approved annual profit sharingallocations as reflected in the “Summary Compensation Table” and notes thereto. For fiscal 2013 the profit sharing amounts reflected in the SummaryCompensation Table are 22%, 47%, 54%, and 52% higher than fiscal 2012 for Messrs. Donovan, Ambury, Goldman and Oakley, respectively. One of thePartnership’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 percentageincrease 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 theprior year, margin management and expense control. In addition, the Partnership’s net customer attrition was reduced to 3.3%, the lowest level achieved overthe last five years. Net customer attrition for the preceding four years averaged 5.3%. The Partnership has also launched several initiatives to increaserevenues other than through the sale of home heating oil and organically expanded its presence in the distribution of propane during fiscal 2013. At thebeginning of fiscal 2013, management faced many challenges as a result of the major East Coast storm, Sandy, and effectively reallocated resources to servicethe 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 PlanIn 2012 under the Plan Amendments adopted by the Board, the number and identity of the Plan participants and their participation points were frozenat the current levels in order to more closely align the interests of Plan participants and unitholders and to give Plan participants a continuing personalinterest in the success of the Partnership. 56 Table of ContentsThe number of participation points that were previously awarded to the named executive officers was based on the length of service and level ofresponsibility of the named executive and the Partnership’s desire to retain the named executive, in order to promote the long-term best interest of thePartnership. 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 morethan 25 years service with the Partnership and lesser awards were granted to the remaining participants, based upon their level of responsibility and length ofservice, 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 BenefitsThere were no changes to the retirement and health benefits applicable to the named executive officers in fiscal 2013.Employment Contracts and Severance AgreementsAgreement with Daniel P. DonovanThe Partnership entered into an employment agreement on November 8, 2010 with Mr. Donovan effective as of June 1, 2010. Mr. Donovan’semployment agreement was for a term of three years unless otherwise terminated in accordance with the employment agreement. Mr. Donovan served asPresident and Chief Executive Officer of the Partnership and its subsidiaries. The employment agreement provided for one year’s salary as severance ifMr. Donovan’s employment was terminated without cause or by Mr. Donovan for good reason. Mr. Donovan retired as the President and Chief ExecutiveOfficer 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 notreceive 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 aconsultant to us for a two year period for which he will receive consulting fees of $250,000 per annum.Agreement with Richard F. AmburyThe Partnership entered into an employment agreement with Mr. Ambury effective as of April 28, 2008. Mr. Ambury will serve as Chief FinancialOfficer and Treasurer of the Partnership and its subsidiaries. The employment agreement provides for one year’s salary as severance if Mr. Ambury’semployment is terminated without cause or by Mr. Ambury for good reason.Agreement with Steven J. GoldmanEffective October 1, 2013, Steven J. Goldman was appointed the President and Chief Executive Officer of the Partnership. Mr. Goldman entered into athree year employment agreement with the Partnership, effective as of October 1, 2013, under which his salary will be $360,000 per annum. Under hisemployment agreement, if Mr. Goldman is terminated for reasons other than cause or if he terminates his employment for good reason, Mr. Goldman will beentitled to one year’s salary as severance.Agreement with Richard G. OakleyEffective November 2, 2009, the Partnership entered into an agreement with Mr. Richard G. Oakley pursuant to which Mr. Oakley will continue to beemployed 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 otherthan cause. 57 Table of ContentsChange In Control AgreementsWe have entered into a Change In Control Agreement with Mr. Goldman, Chief Executive Officer and Mr. Ambury, Chief Financial Officer. Under theterms 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 toa 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 profitsharing during the three years preceding the year of such termination. The term change in control means the present equity owners of Kestrel and theiraffiliates 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 orother 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 andtheir 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 havereceived a payment of $1,520,400.Indemnification AgreementsWe have entered into an indemnification agreement with each of our directors and senior executives. These agreements provide for us to, among otherthings, indemnify such persons against certain liabilities that may arise by reason of their status or service as directors or officers, to advance their expensesincurred 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 policywe choose, in our discretion, to maintain. These indemnification agreements are intended to provide indemnification rights to the fullest extent permittedunder applicable indemnification rights statutes in the State of Delaware and are in addition to any other rights such person may have under our partnershipagreement and the operating agreement of our general partner, and applicable law. We believe these indemnification agreements enhance our ability toattract and retain knowledgeable and experienced executives and independent, non-management directors.Board of Directors ReportThe Board of Directors of the general partner of the Partnership does not have a separate compensation committee. Executive compensation isdetermined 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 annualreport on Form 10-K. Based on that review and discussion, the Board of Directors recommends that the Compensation Discussion and Analysis be included inthe Partnership’s annual report on Form 10-K for the year ended September 30, 2013.Paul A. Vermylen, Jr.Steven J. GoldmanHenry D. BabcockC. Scott BaxterDaniel P. DonovanBryan H. LawrenceSheldon B. LubarWilliam P. Nicoletti 58 Table of ContentsExecutive Compensation TableThe following table sets forth the annual salary compensation, bonus and all other compensation awards earned and accrued by the named executiveofficers in the fiscal year. Summary Compensation Table Name and Principal Position FiscalYear Salary Bonus UnitAwards OptionAwards Non-EquityIncentivePlanComp.(2) Change inPensionValue andNonqualifiedDeferredComp.Earnings (3) All OtherComp.(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 ExecutiveVice President and Chief Operating Officer.(2)Payable pursuant to the Partnership’s profit sharing pool, which is described under “Compensation Discussion and Analysis – Profit SharingAllocation.”(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 theMeenan defined benefit pension plan, where participants are not accruing additional benefits. Mr. Ambury also participated in a tax-qualifiedsupplemental employee retirement plan which prior to being frozen in 1997, represented contributions to an employee plan to compensate for areduction 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 supplementalemployee 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 ManagementIncentiveCompensationPlan Company Match andCore Contribution to401(K) Plan VacationPayout Contributions toNonqualified DeferredCompensation Plan Car Allowance orMonetary Value forPersonal Use ofCompany OwnedVehicle 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 $37,660 59 Table of ContentsGrants of Plan-Based Awards All OtherStocksAwards:Number ofShares of All OtherOptionAwards:Number ofSecurities Exercise orBase Price ofOption GrantDate FairValue ofStock and Estimated Future PayoutsEquity Incentive Plan Awards (1) Estimated Future PayoutsUnder Equity Incentive Plan Name Grant Date(1) Threshold($) Target ($)(2) Maximum($) Threshold(#) Target(#) Maximum(#) Stock orUnits (#) UnderlyingOptions (#) Awards($/Sh) OptionAwards 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 terminatethe 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 namedexecutive officers for fiscal 2013.Outstanding Equity Awards at Fiscal Year-EndNoneOption Exercises and Stock VestedNonePension Plans Pursuant to Which Named Executive Officers Have an Accumulated Benefit But Are Not Currently Accruing Benefits Name Plan Name Number of YearsCredited Service Present Value ofAccumulated Benefit Payments DuringLast 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 EmployeeRetirement 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 areduction in certain benefits prior to 1997. Mr. Goldman was not a participant in any of these plans. Each year, the name executive officer’s accumulatedbenefits are actuarially calculated generally based on the credited years of service and each employee’s compensation at the time the plan was frozen. Thepresent value of these amounts are the present value of a single life annuity generally payable at later or normal retirement age, adjusted for changes indiscount rates and government mandated mortality tables. See note 12. Employee Benefit Plans, to the Partnership’s consolidated financial statements, for thematerial assumptions applied in quantifying the present value of the accumulated benefits of these frozen plans. 60 Table of ContentsNonqualified 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. InApril 2011, the Board of Directors approved a deferred compensation arrangement to be funded by amounts which would have been payable toMr. 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 himwill 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 TerminationIf Mr. Goldman’s employment is terminated by the Partnership for reasons other than for cause or if Mr. Goldman terminates his employment for goodreason, 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 aboveunder “Change in Control Agreements.” For 12 months following the termination of his employment, Mr. Goldman is prohibited from competing with thePartnership 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 beentitled 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 thePartnership 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 monthsfollowing the termination of his employment, Mr. Oakley is prohibited from competing with the Partnership or from becoming involved either as anemployee, 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 paymentwas 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 onlybe 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 twelvemonths following the termination of their employment. Potential Payments Potential PaymentsFollowing 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 $— 61 Table of ContentsCompensation of Directors Director Compensation Table Name FeesEarnedor Paidin Cash UnitAwards OptionAwards Non-EquityIncentivePlanCompensation Change inPensionValue andNonqualifiedDeferredCompensationEarnings (6) All OtherCompensation (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 compensationtable.(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 benefitsunder the frozen plan. The change in the pension value reflects normal non-cash adjustments resulting from changes in discount rates and governmentmandated 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 andstarted 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 theAudit Committee receives an annual fee of $20,000 while other Audit Committee members receive an annual fee of $10,000. Each member of the AuditCommittee 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 MANAGEMENTThe 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. 62 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 sharebeneficial 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 TRANSACTIONSThe Partnership has a written conflict of interest policy and procedure that requires all officers, directors and employees to report to senior corporatemanagement or the board of directors, all personal, financial or family interest in transactions that involve the individual and the Partnership. In addition, thePartnership Governance Guidelines provide that any monetary arrangement between a director and his or her affiliates (including any member of a director’simmediate 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 isreimbursed for all expenses incurred on behalf of the Partnership, including the cost of compensation, which is properly allocable to the Partnership. ThePartnership’s Partnership Agreement provides that the general partner shall determine the expenses that are allocable to the Partnership in any reasonablemanner determined by the general partner in its sole discretion. In addition, the general partner and its affiliates may provide services to the Partnership forwhich 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, Lawrenceand Lubar are also members of the board of managers of Kestrel and, either directly or through affiliated entities, own equity interests in Kestrel. Kestrel ownsall of the issued and outstanding membership interests of Kestrel Heat and KM2.Policies Regarding Transactions with Related PersonsOur Code of Business Conduct and Ethics, Partnership Governance Guidelines and Partnership Agreement set forth policies and procedures withrespect to transactions with persons affiliated with the Partnership and the resolution of conflicts of interest, which taken together provide the Partnershipwith 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 ofregulation 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. 63 Table of ContentsOur Partnership Governance Guidelines provide that any monetary arrangement between a director and his or her affiliates (including any member of adirector’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 employeesand 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, theBoard intends to utilize the procedures set forth in the Partnership Agreement for the review and approval of potential conflicts of interest. Our PartnershipAgreement 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 inrespect of such conflict of interest shall be permitted and deemed approved by all partners, and shall not constitute a breach of the Partnership Agreement, ofany 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 thePartnership 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 suchconflict of interest or resolution is (i) approved by a committee of independent directors (the “Conflicts Committee”), (ii) on terms no less favorable to thePartnership than those generally being provided to or available from unrelated third parties or (iii) fair to the Partnership, taking into account the totality ofthe 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 thePartnership 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 orappropriate under the circumstances. ITEM 14.PRINCIPAL ACCOUNTANT FEES AND SERVICESThe following table represents the aggregate fees for professional audit services rendered by KPMG LLP including fees for the audit of thePartnership’s annual financial statements for the fiscal years 2013 and 2012, and for fees billed and accrued for other services rendered by KPMG LLP (inthousands). 2013 2012 Audit Fees $1,495 $1,487 Tax Fees 496 322 Total Fees $1,991 $1,809 Audit fees were for professional services rendered in connection with audits and quarterly reviews of the consolidated financial statements of thePartnership. The fiscal 2012 amount includes $114,000 in audit fees, for services provided in fiscal 2011 but not paid until fiscal 2012, and for thecomfort letter initiated in connection with a potential debt offering. 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 Directorsconsiders and pre-approves any audit and non-audit services to be performed by the Partnership’s independent accountants. The Audit Committee hasdelegated to its chairman, an independent member of the Partnership’s Board of Directors, the authority to grant pre-approvals of non-audit services providedthat 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 thatwere not pre-approved. 64 ,(1)(2)(1)(2) Table of ContentsPART IV ITEM 15.EXHIBITS AND FINANCIAL STATEMENT SCHEDULES1. 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 ExhibitNumber Incorp byRef. 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 PetroHoldings, 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 andRBS. 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) 65 Table of Contents101.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 theCommission 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 theCommission 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 theCommission 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. 66 Table of ContentsSIGNATUREPursuant 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 theundersigned 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 OfficerPursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons in the capacities and on thedate indicated: Signature Title Date/s/ Steven J. GoldmanSteven J. Goldman President and Chief Executive Officerand Director Kestrel Heat, LLC December 11, 2013/s/ Richard F. AmburyRichard F. Ambury Chief Financial Officer(Principal Financial Officer)Kestrel Heat, LLC December 11, 2013/s/ Richard G. OakleyRichard 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 Boardand Director Kestrel Heat, LLC December 11, 2013/s/ Henry D. BabcockHenry D. Babcock DirectorKestrel Heat, LLC December 11, 2013/s/ C. Scott BaxterC. Scott Baxter DirectorKestrel Heat, LLC December 11, 2013/s/ Daniel P. DonovanDaniel P. Donovan DirectorKestrel Heat, LLC December 11, 2013/s/ Bryan H. LawrenceBryan H. Lawrence DirectorKestrel Heat, LLC December 11, 2013/s/ Sheldon B. LubarSheldon B. Lubar DirectorKestrel Heat, LLC December 11, 2013/s/ William P. NicolettiWilliam P. Nicoletti DirectorKestrel Heat, LLC December 11, 2013 67 Table of ContentsSTAR GAS PARTNERS, L.P. AND SUBSIDIARIESINDEX TO CONSOLIDATED FINANCIAL STATEMENTSAND FINANCIAL STATEMENT SCHEDULE PagePart 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 financialstatements or the notes therein. F-1 Table of ContentsReport of Independent Registered Public Accounting FirmThe 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 thethree-year period ended September 30, 2013. In connection with our audits of the consolidated financial statements, we have also audited the financialstatement schedules I and II listed in the accompanying index. We also have audited the Partnership’s internal control over financial reporting as ofSeptember 30, 2013, based on criteria established in Internal Control – Integrated Framework (1992) issued by the Committee of Sponsoring Organizationsof the Treadway Commission (COSO). The Partnership’s management is responsible for these consolidated financial statements and financial statementschedules, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financialreporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion onthese consolidated financial statements and financial statement schedules and an opinion on the Partnership’s internal control over financial reporting basedon our audits.We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standardsrequire that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement andwhether effective internal control over financial reporting was maintained in all material respects. Our audits of the consolidated financial statementsincluded examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles usedand significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financialreporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing andevaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures aswe 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 financialreporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’sinternal 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 asnecessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of thecompany are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assuranceregarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on thefinancial statements.Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of anyevaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degreeof 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 periodended September 30, 2013, in conformity with U.S. generally accepted accounting principles. In addition, in our opinion, the related financial statementschedules I and II listed in the accompanying index, when considered in relation to the basic consolidated financial statements taken as a whole, presentfairly, in all material respects, the information set forth therein. Also in our opinion, Star Gas Partners, L.P. and Subsidiaries maintained, in all materialrespects, effective internal control over financial reporting as of September 30, 2013, based on criteria established in Internal Control – IntegratedFramework (1992) issued by COSO./s/ KPMG LLPStamford, ConnecticutDecember 11, 2013 F-2 Table of ContentsSTAR GAS PARTNERS, L.P. AND SUBSIDIARIESCONSOLIDATED 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. F-3 Table of ContentsSTAR GAS PARTNERS, L.P. AND SUBSIDIARIESCONSOLIDATED 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. F-4 Table of ContentsSTAR GAS PARTNERS, L.P. AND SUBSIDIARIESCONSOLIDATED 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 Table of ContentsSTAR GAS PARTNERS, L.P. AND SUBSIDIARIESCONSOLIDATED STATEMENTS OF PARTNERS’ CAPITALYears Ended September 30, 2013, 2012 and 2011 Number of Units (in thousands) Common GeneralPartner Common GeneralPartner Accum. OtherComprehensiveIncome (Loss) TotalPartners’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. F-6 Table of ContentsSTAR GAS PARTNERS, L.P. AND SUBSIDIARIESCONSOLIDATED 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. F-7 Table of ContentsSTAR GAS PARTNERS, L.P. AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS1) Partnership OrganizationStar Gas Partners, L.P. (“Star Gas Partners,” the “Partnership,” “we,” “us,” or “our”) is a home heating oil and propane distributor and services providerwith one reportable operating segment that principally provides services to residential and commercial customers to heat their homes and buildings. Star GasPartners 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”). TheBoard of Directors of Kestrel Heat (the “Board”) is appointed by its sole member, Kestrel Energy Partners, LLC, a Delaware limited liabilitycompany (“Kestrel”). • The Partnership’s operations are conducted through Petro Holdings, Inc. and its subsidiaries (“Petro”). Petro is a Minnesota corporation that is anindirect 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-serviceresidential and commercial home heating oil and propane customers. Petro also sold home heating oil, gasoline and diesel fuel to approximately54,000 customers on a delivery only basis. In addition, Petro installed, maintained, and repaired heating and air conditioning equipment for itscustomers, 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 andseverally with the Partnership, of its $125 million (excluding discount) 8.875% Senior Notes outstanding at September 30, 2013, that are due2017. The Partnership is dependent on distributions, including inter-company interest payments from its subsidiaries, to service the Partnership’sdebt obligations. The distributions from the Partnership’s subsidiaries are not guaranteed and are subject to certain loan restrictions. Star GasFinance Company has nominal assets and conducts no business operations. (See Note 11—Long-Term Debt and Bank Facility Borrowings)2) Summary of Significant Accounting PoliciesBasis of PresentationThe Consolidated Financial Statements include the accounts of Star Gas Partners, L.P. and its subsidiaries. All material intercompany items andtransactions have been eliminated in consolidation.ReclassificationThe accompanying September 30, 2012 and 2011 consolidated statements of operations have been revised from their previous presentation toreclassify finance charge income of $4,393 and $4,814, respectively and present it separately as an element of operating income. Previously, finance chargeincome was included in the caption interest income in the consolidated statements of operations. This reclassification was made in order to conform withcommon industry practice regarding the reporting of finance charge income in operating income, and had no impact on net income, financial position, andcash 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 IncomeComprehensive 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. F-8 Table of ContentsUse of EstimatesThe preparation of financial statements in accordance with accounting principles generally accepted in the United States of America requiresmanagement to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities atthe date of the financial statements and the reported amounts of revenue and expenses during the reporting period. Actual results could differ from thoseestimates.Revenue RecognitionSales 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 conditioningequipment are recognized at the time of installation. Revenue from repairs and maintenance service is recognized upon completion of the service. Paymentsreceived from customers for equipment service contracts are deferred and amortized into income over the terms of the respective service contracts, on astraight-line basis, which generally do not exceed one year. To the extent that the Partnership anticipates that future costs for fulfilling its contractualobligations under its service maintenance contracts will exceed the amount of deferred revenue currently attributable to these contracts, the Partnershiprecognizes a loss in current period earnings equal to the amount that anticipated future costs exceed related deferred revenues.Cost of ProductCost of product includes the cost of heating oil, diesel, propane, kerosene, heavy oil, gasoline, throughput costs, barging costs, option costs, andrealized gains/losses on closed derivative positions for product sales.Cost of Installations and ServiceCost of installations and service includes equipment and material costs, wages and benefits for equipment technicians, dispatchers and other supportpersonnel, subcontractor expenses, commissions and vehicle related costs.Delivery and Branch ExpensesDelivery 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, andoperational support.General and Administrative ExpensesGeneral 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 AccountsAccounts receivables from customers are recorded at the invoiced amounts. Finance charges may be applied to trade receivables that are more than 30days 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 isdetermined at an aggregate level by grouping accounts based on the type of account and its receivable aging. The allowance is based on both quantitativeand qualitative factors, including historical loss experience, historical collection patterns, overdue status, aging trends, and current economic conditions. ThePartnership has an established process to periodically review current and past due trade receivable balances to determine the adequacy of the allowance. Nosingle statistic or measurement determines the adequacy of the allowance. The total allowance reflects management’s estimate of losses inherent in its tradereceivables at the balance sheet date. Different assumptions or changes in economic conditions could result in material changes to the allowance for doubtfulaccounts.Allocation of Net IncomeNet income for partners’ capital and statement of operations is allocated to the general partner and the limited partners in accordance with theirrespective ownership percentages, after giving effect to cash distributions paid to the general partner in excess of its ownership interest, if any. F-9 Table of ContentsNet Income per Limited Partner UnitIncome per limited partner unit is computed in accordance with the Financial Accounting Standards Board (“FASB”) Accounting StandardsCodification (“ASC”) 260-10-05 Earnings Per Share, Master Limited Partnerships (EITF 03-06), by dividing the limited partners’ interest in net income bythe weighted average number of limited partner units outstanding. The pro forma nature of the allocation required by this standard provides that in anyaccounting period where the Partnership’s aggregate net income exceeds its aggregate distribution for such period, the Partnership is required to present netincome per limited partner unit as if all of the earnings for the periods were distributed, regardless of whether those earnings would actually be distributedduring a particular period from an economic or practical perspective. This allocation does not impact the Partnership’s overall net income or other financialresults. However, for periods in which the Partnership’s aggregate net income exceeds its aggregate distributions for such period, it will have the impact ofreducing the earnings per limited partner unit, as the calculation according to this standard results in a theoretical increased allocation of undistributedearnings to the general partner. In accounting periods where aggregate net income does not exceed aggregate distributions for such period, this standard doesnot 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 PayableThe carrying amount of cash, accounts receivable, notes receivable, revolving credit facility borrowings, and accounts payable approximates fair valuebecause of the short maturity of these instruments.Cash EquivalentsThe Partnership considers all highly liquid investments with an original maturity of three months or less, when purchased, to be cash equivalents.InventoriesLiquid 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 EquipmentProperty and equipment are stated at cost. Depreciation is computed over the estimated useful lives of the depreciable assets using the straight-linemethod.Goodwill and Intangible AssetsGoodwill 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 inaccordance with this standard, intangible assets with finite useful lives are amortized over their respective estimated useful lives to their estimated residualvalues, and reviewed for impairment. The Partnership performs its annual impairment review during its fiscal fourth quarter or more frequently if events orcircumstances 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 astraight-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, tradenames 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 astraight-line basis, which are generally five years.Business CombinationsThe Partnership uses the acquisition method of accounting in accordance with FASB ASC 805 Business Combinations. The acquisition method ofaccounting requires the Partnership to use significant estimates and assumptions, including fair value estimates, as of the business combination date, and torefine those estimates as necessary during the measurement period (defined as the period, not to exceed one year, in which the amounts recognized for abusiness combination may be adjusted). Each acquired company’s operating results are included in the Partnership’s consolidated financial statementsstarting on the date of acquisition. The purchase price is equivalent to the fair value of consideration transferred. Tangible and identifiable intangible assetsacquired and liabilities assumed as of the date of acquisition are recorded at the acquisition date fair value. The separately identifiable intangible assetsgenerally are comprised of customer lists, trade names and covenants not to compete. Goodwill is recognized for the excess of the purchase price over the netfair value of assets acquired and liabilities assumed. F-10 Table of ContentsCosts that are incurred to complete the business combination such as investment banking, legal and other professional fees are not considered part ofconsideration transferred, and are charged to general and administrative expense as they are incurred. For any given acquisition, certain contingentconsideration may be identified. Estimates of the fair value of liability or asset classified contingent consideration are included under the acquisition methodas 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 AssetsThe 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 ofsuch assets may not be recoverable. The Partnership determines whether the carrying values of such assets are recoverable over their remaining estimatedlives through undiscounted future cash flow analysis. If such a review should indicate that the carrying amount of the assets is not recoverable, thePartnership will reduce the carrying amount of such assets to fair value.Deferred ChargesDeferred 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 ExpensesAdvertising and direct mail costs are expensed as they are incurred. Advertising and direct mail expenses were $10.5 million, $9.6 million, and $9.5million, in 2013, 2012, and 2011, respectively and are recorded in delivery and branch expenses.Customer Credit BalancesCustomer credit balances represent payments received in advance from customers pursuant to a balanced payment plan (whereby customers pay on afixed monthly basis) and the payments made have exceeded the charges for liquid product and other services.Environmental CostsCosts associated with managing hazardous substances and pollution are expensed on a current basis. Accruals are made for costs associated with theremediation of environmental pollution when it becomes probable that a liability has been incurred and the amount can be reasonably estimated.Insurance ReservesThe 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 liabilitymay be for outstanding claims using developmental factors based upon historical claim experience, including frequency, severity, demographic factors andother actuarial assumptions, supplemented with support from qualified actuaries.Income TaxesThe Partnership is a master limited partnership and is not subject to tax at the entity level for Federal and State income tax purposes. Rather, incomeand losses of the Partnership are allocated directly to the individual partners (the Partnership’s corporate subsidiaries are subject to tax at the entity level forfederal and state income tax purposes). While the Partnership will generate non-qualifying Master Limited Partnership revenue through its corporatesubsidiaries, distributions from the corporate subsidiaries to the Partnership are generally included in the determination of qualified Master LimitedPartnership income. All or a portion of the distributions received by the Partnership from the corporate subsidiaries could be a dividend or capital gain to thepartners.The accompanying financial statements are reported on a fiscal year, however, the Partnership and its Corporate subsidiaries file Federal and Stateincome 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 incometaxes. For corporate subsidiaries of the Partnership, a consolidated Federal income tax return is filed. Deferred tax assets and liabilities are recognized for thefuture tax consequences attributable to differences between the financial statement carrying amount of assets and liabilities and their respective tax bases andoperating loss carry-forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years inwhich those temporary differences are expected to be recovered or settled. A valuation allowance is recognized if, based on the weight of available evidenceincluding historical tax losses, it is more likely than not that some or all of deferred tax assets will not be realized. F-11 Table of ContentsSales, Use and Value Added TaxesTaxes are assessed by various governmental authorities on many different types of transactions. Sales reported for product, installation and serviceexcludes taxes.Derivatives and HedgingFASB ASC 815-10-05 Derivatives and Hedging, requires that derivative instruments be recorded at fair value and included in the consolidated balancesheet as assets or liabilities. The Partnership has elected not to designate its derivative instruments as hedging instruments under this guidance, and thechanges in fair value of the derivative instruments are recognized in our statement of operations.Weather Hedge ContractTo partially mitigate the adverse effect of warm weather on cash flows, the Partnership has used weather hedge contracts for a number of years. Weatherhedge 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 overthe 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 FinancialProducts 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 throughMarch 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 PronouncementsIn 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 morelikely 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 theeffect of those arrangements on its financial position. The amendments require added disclosures about financial instruments and derivative instruments thatare either (1) offset in accordance with other GAAP or (2) subject to an enforceable master netting arrangement or similar agreement, regardless of whetherthey 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. Theadoption 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 impacton our disclosures.3) Quarterly Distribution of Available CashThe Partnership agreement provides that beginning October 1, 2008, minimum quarterly distributions on the common units will start accruing at therate 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 usbefore 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 themanner 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 cashreserves 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. F-12 Table of ContentsAvailable 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 minimumquarterly 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 distributionof $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 thePartnership 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 mustmaintain 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 anydistributions 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 RetirementIn fiscal 2010, the Partnership concluded its Plan I common units repurchase program and retired at an average price paid of $4.04 per unit, all7.5 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, all7.25 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 Boardauthorized an additional 1.9 million common units to be repurchased under its Plan III common unit repurchase plan. The authorized common unitrepurchases may be made from time-to-time in the open market, in privately negotiated transactions or in such other manner deemed appropriate bymanagement. There is no guarantee of the exact number of units that will be purchased under the program and the Partnership may discontinue purchases atany 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 privatetransaction. The Partnership’s repurchase activities take into account SEC safe harbor rules and guidance for issuer repurchases. All of the common unitspurchased in the repurchase program will be retired. F-13 Table of ContentsThe Partnership must maintain Availability (as defined in the revolving credit facility agreement) of $61.3 million, 17.5% of the maximum facility sizeof $350 million (assuming a seasonal advance of $100 million is outstanding) on a historical pro forma and forward-looking basis, and a fixed chargecoverage ratio of not less than 1.15 in order to repurchase common units. (in thousands, except per unit amounts) Period Total Number of UnitsPurchased as Part of aPublicly Announced Planor Program Average PricePaid per Unit (a) Maximum Numberof Units that MayYet Be PurchasedUnder the Program Plan III - Number of units authorized 4,894 Private transaction - Number of unitsauthorized (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 2013total 310 $4.36 4,697 Plan III - Third quarter fiscal year 2013total (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 2013total 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 MeasurementsThe Partnership uses derivative instruments such as futures, options, and swap agreements, in order to mitigate exposure to market risk associated withthe 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 ofSeptember 30, 2013, the Partnership held 2.4 million gallons of physical inventory and had bought 6.0 million gallons of swap contracts with a notionalvalue 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 $0.02million, 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 syntheticcalls 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-monthdifferentials for its price-protected customers, its physical inventory on hand and inventory in transit, the Partnership, as of September 30, 2013, had bought17.4 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 futurecontracts 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 notionalvalue 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, thePartnership as of September 30, 2013, had bought corresponding long and short 28.2 million net gallons of swap contracts with a notional value of $83.8million 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, hadbought 3.2 million gallons of future swap contracts with a notional value of $9.0 million and a fair value of $0.05 million. F-14 Table of ContentsTo hedge a substantial majority of the purchase price associated with heating oil gallons anticipated to be sold to its price-protected customers as ofSeptember 30, 2012, the Partnership held 3.3 million gallons of physical inventory and had bought 7.1 million gallons of swap contracts with a notionalvalue 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 $0.1million, 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 syntheticcalls 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-monthdifferentials for its price-protected customers, its physical inventory on hand and inventory in transit, the Partnership, as of September 30, 2012, had bought22.6 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 futurecontracts 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 notionalvalue 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 anda 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 milliongallons 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., JPMorganChase Bank, N.A., Key Bank, N.A., Regions Financial Corporation, Societe Generale, and Wells Fargo Bank, N.A. The Partnership assesses counterpartycredit risk and maintains master netting arrangements with counterparties to help manage the risks, and record derivative positions on a net basis. ThePartnership considers counterparty credit risk to be low. At September 30, 2013, the aggregate cash posted as collateral in the normal course of business atcounterparties was $1.1 million. Positions with counterparties who are also parties to our revolving credit facility are collateralized under that facility. As ofSeptember 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 atfair value and included in the consolidated balance sheet as assets or liabilities, along with qualitative disclosures regarding the derivative activity. To theextent derivative instruments designated as cash flow hedges are effective and the standard’s documentation requirements have been met, changes in fairvalue are recognized in other comprehensive income until the underlying hedged item is recognized in earnings. The Partnership has elected not to designateits derivative instruments as hedging instruments under this standard and the change in fair value of the derivative instruments is recognized in our statementof operations in the line item (Increase) decrease in the fair value of derivative instruments. Depending on the risk being hedged, realized gains and losses arerecorded 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 inmeasuring 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 inwhich little or no market data exists, therefore requiring an entity to develop its own assumptions. The Partnership’s Level 1 derivative assets and liabilitiesrepresent the fair value of commodity contracts used in its hedging activities that are identical and traded in active markets. The Partnership’s Level 2derivative assets and liabilities represent the fair value of commodity contracts used in its hedging activities that are valued using either directly or indirectlyobservable 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 Level2 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 Level2 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 contractsopen 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 theNYMEX published market prices and other inputs, including such factors as present value, volatility and duration. F-15 Table of ContentsThe Partnership had no assets or liabilities that are measured at fair value on a nonrecurring basis subsequent to their initial recognition. ThePartnership’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 Designatedas Hedging InstrumentsUnder FASB ASC 815-10 Balance Sheet Location Total Quoted Prices inActive Markets forIdentical AssetsLevel 1 Significant OtherObservable InputsLevel 2 SignificantUnobservableInputsLevel 3 Asset Derivatives at September 30, 2013 Commodity contracts Fair asset and fair liability valueof 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 valueof 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 valueof 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 valueof 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 NotDesignated as HedgingInstruments UnderFASB ASC 815-10 Location of (Gain) orLoss Recognized inIncome 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 ofderivative instruments $6,775 $(8,549) $2,567 (a)Represents realized closed positions and includes the cost of options as they expire. F-16 Table of Contents6) InventoriesThe 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 (inthousands): 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 tofully 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 66provided approximately 19%, 11%, 9% and 9% respectively, of our petroleum product purchases. During fiscal 2012, Global Companies LLC providedapproximately 24% of our petroleum product purchases. No other single supplier provided more than 10% of our petroleum product supply during fiscal2012, however, JPMorgan Ventures Energy Corporation and NIC Holding Corp. (Northville Industries) each provided approximately 9%.7) Property and EquipmentThe 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 CombinationsDuring fiscal 2013, the Partnership acquired two heating oil dealers for an aggregate purchase price of approximately $1.4 million. The gross purchaseprice 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 operatingresults of these two acquisitions have been included in the Partnership’s consolidated financial statements since the date of acquisition, and are not materialto the Partnership’s financial condition, results of operations, or cash flows. The fair values of the assets acquired and liabilities assumed are comprisedprimarily 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. Thegross 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 $1.9million. F-17 Table of Contents9) Goodwill and Other Intangible AssetsGoodwillUnder FASB ASC 350-10-05 Intangibles-Goodwill and Other, goodwill impairment if any, needs to be determined if the net book value of a reportingunit 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 excessof 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 annualimpairment review, whereby the total enterprise value as indicated by the Income Approach and Market Approach (consisting of the Market Comparable andMarket 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 wasdetermined 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 byactual results that are materially different from projected amounts. To provide for a sensitivity of the discount rates and transaction multiples used, ranges ofhigh 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 causethe 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, netIntangible assets subject to amortization consist of the following (in thousands): September 30, 2013 2012 GrossCarryingAmount Accum.Amortization Net GrossCarryingAmount 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, and2011, respectively. Total estimated annual amortization expense related to intangible assets subject to amortization, for the year ended September 30, 2014and 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 F-18 Table of Contents10) Accrued Expenses and Other Current LiabilitiesThe 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 BorrowingsThe Partnership’s debt is as follows (in thousands): September 30, 2013 2012 CarryingAmount Fair Value (a) CarryingAmount 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 theSecurities Act of 1933, and in February 2011, were exchanged for substantially identical public notes registered with the Securities and ExchangeCommission. These public notes mature in December 2017 and accrue interest at an annual rate of 8.875% requiring semi-annual interest payments onJune 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 notespermit restricted payments after passing certain financial tests. The Partnership can incur debt up to $100 million for acquisitions and can also payrestricted 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 comprisedof fifteen banks. The amended and restated revolving credit facility expires in June 2016. In November 2011, the Partnership exercised the provisionunder this agreement to expand the facility by an additional $50 million. Under this agreement, the Partnership may borrow up to $250 million ($350million during the heating season from December to April each year) for working capital purposes (subject to certain borrowing base limitations andcoverage ratios) and may issue up to $100 million in letters of credit. The Partnership can increase the facility size by $100 million without the consentof 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 Partnershipcan add additional lenders to the group, with the consent of the agent (as appointed in the revolving credit facility agreement), which shall not beunreasonably withheld.Obligations under the revolving credit facility are guaranteed by the Partnership and its subsidiaries and are secured by liens on substantially all of thePartnership’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). TheCommitment 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 ordistributions, make investments, grant liens, sell assets, make acquisitions and engage in certain other activities. F-19 Table of ContentsThe Partnership is obligated to meet certain financial covenants under the amended and restated revolving credit facility, including the requirement tomaintain at all times either Availability (borrowing base less amounts borrowed and letters of credit issued) of $43.8 million, 12.5% of the maximum facilitysize, 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 AdjustedEBITDA for the trailing twelve months. In order to make acquisitions, the Partnership must maintain Availability of $40 million on a historical pro forma andforward-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 notless 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. AtSeptember 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-companydividends or distributions (including those needed to pay interest or principal on the 8.875% senior notes), except to the Partnership or a wholly ownedsubsidiary of the Partnership, if the relevant covenant described above has not been met. The occurrence of an event of default or an acceleration under theamended and restated revolving credit facility would result in the Partnership’s inability to obtain further borrowings under that facility, which couldadversely 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 payinterest or pay down debt. An acceleration under the amended and restated revolving credit facility would result in a default under the Partnership’s otherfunded debt.At September 30, 2013, availability was $164.3 million, the restricted net assets totaled approximately $375 million and the Partnership was incompliance with the fixed charge coverage ratio. Restricted net assets are assets in the Partnership’s subsidiaries the distribution or transfer of which to StarGas Partners, L.P. are subject to limitations under its revolving credit facility. At September 30, 2012, availability was $179.2 million, the restricted net assetstotaled 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 commonunits representing limited partnership interests, partnership securities and debt securities; which may be secured or unsecured senior debt securities or securedor 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 followingtable (in thousands): 2014 $— 2015 $— 2016 $— 2017 $— 2018 $125,000 Thereafter $— F-20 Table of Contents12) Employee Benefit PlansDefined Contribution PlansThe Partnership has two 401(k) plans that cover eligible non-union and union employees. Subject to IRS limitations, the 401(k) plans provide for eachparticipant to contribute from 0% to 60% of compensation. For most participants, the Partnership generally can make a 4% (to a maximum of 5.5% forparticipants 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 aparticipant’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 matchingcontribution and/or an annual employer discretionary profit sharing contribution. The Partnership’s aggregate contributions to the 401(k) plans during fiscal2013, 2012, and 2011, were $4.9 million, $4.5 million, and $4.7 million, respectively.Management Incentive Compensation PlanThe Partnership has a Management Incentive Compensation Plan. The long-term compensation structure is intended to align the employee’sperformance with the long-term performance of our unitholders. Under the Plan, employees who participate shall be entitled to receive a pro rata share of anamount in cash equal to: • 50% of the distributions (“Incentive Distributions”) of Available Cash in excess of the minimum quarterly distribution of $0.0675 per unitotherwise 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 thePartnership 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 2013Compensation Decisions—Management Incentive Compensation Plan.” The amount paid in Incentive Distributions is governed by the PartnershipAgreement 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 planparticipants. For accounting purposes, amounts payable to management under this Plan will be treated as compensation and will reduce net income. KestrelHeat 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 bythe 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 fromtime 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 paymentswill 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 Directorsreserves the right to adjust the amount of Incentive Distributions to be allocated to the Bonus Pool if in its judgment extenuating circumstances warrantadjustment 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, $277,000during fiscal 2012, and $261,000 during fiscal 2011. Included in these amounts for fiscal 2013, 2012, and 2011, were distributions under the managementincentive compensation plan of $165,000, $138,000 and $130,000, respectively, of which named executive officers received approximately $119,000 duringfiscal 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 itwill sell its general partner units within the next twelve months. Thus the Plan’s value attributable to the Gains Interest currently cannot be determined. F-21 Table of ContentsMultiemployer Pension PlansWe contribute to various multiemployer union administered pension plans under the terms of collective bargaining agreements that provide for suchplans for covered union-represented employees. The risks of participating in these multiemployer plans are different from single-employer plans in that assetscontributed are pooled and may be used to provide benefits to employees of other participating employers. If a participating employer stops contributing tothe plan, the remaining participating employers may be required to bear the unfunded obligations of the plan. If we choose to stop participating in amultiemployer plan, we may be required to pay a withdrawal liability based on the underfunded status of the plan. However, cessation of participation in amultiemployer 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 and2011. The EIN/Pension Plan Number column provides the Employer Identification Number (“EIN”) and the three-digit plan number. The most recent PensionProtection 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 arecertified 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 80percent funded, and plans in the green zone are at least 80 percent funded. The FIP/RP Status Pending/Implemented column indicates plans for which afinancial improvement plan (“FIP”) or a rehabilitation plan (“RP”) is either pending or has been implemented. Certain plans have been aggregated in the AllOther 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 plancontributions from all employers for 2013, 2012 and 2011, as disclosed in the respective plan’s Form 5500. The collective bargaining agreements of theseplans require contributions based on the hours worked and there are no minimum contributions required. Pension Protection ActZone Status FIP / RP Status Partnership Contributions (in thousands) Pension Fund EIN/ Pension PlanNumber 2013 2012 Pending /Implemented 2013 2012 2011 SurchargeImposed Expiration Date ofCollective-BargainingAgreement New England Teamsters & TruckingIndustry 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 TotalContributions $8,018 $7,237 $6,930 Defined Benefit PlansThe 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 benefitobligations, and the amounts recognized in other comprehensive income and accumulated other comprehensive income at the dates indicated using ameasurement date of September 30 (in thousands): F-22 Table of ContentsDebit / (Credit) Net PeriodicPensionCost inIncomeStatement Cash FairValue ofPensionPlanAssets ProjectedBenefitObligation OtherComprehensive(Income) / Loss Gross PensionRelatedAccumulatedOtherComprehensiveIncome 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) F-23 Table of ContentsAt 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 othercomprehensive income will be recognized and amortized into net periodic pension costs as an actuarial loss in future years. The estimated amount that willbe 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 planassets 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, historicalreturns on the types of assets held, and the current economic environment. The Partnership revised its return on plan assets assumption to 5.75% per annumeffective 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. Thediscount rate used by the Partnership in determining pension expense and pension obligations reflects the yield of high quality (AA or better rating by arecognized 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 maximizereturn within reasonable and prudent levels of risk in order to minimize contributions and charges to the profit and loss statement, and to control costs ofadministering 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 havebeen 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 ConcentrationPercentage 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 yearsthereafter will aggregate approximately $21.2 million. F-24 Table of Contents13) Income TaxesIncome 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 usingcurrent 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 F-25 Table of ContentsAs of the calendar tax year ended December 31, 2012, Star Acquisitions, a wholly-owned subsidiary of the Partnership, had a Federal net operating losscarry forward (“NOLs”) of approximately $10.6 million. The Federal NOLs, which will expire between 2018 and 2024, are generally available to offset anyfuture 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 andtax 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 includingrelated accrued interest and penalties of $0.1 million. These unrecognized tax benefits are primarily the result of State tax uncertainties. If recognized, thesetax 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. Ourcontinuing practice is to recognize interest and penalties related to income tax matters as a component of income tax expense. We file U.S. Federal incometax 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 Federalincome tax returns we have four tax years subject to examination. In our major state tax jurisdictions of New York, Connecticut, Pennsylvania and NewJersey, 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 thetiming 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 aseries of complex judgments about future events.14) Lease CommitmentsThe Partnership has entered into certain operating leases for office space, trucks and other equipment. The future minimum rental commitments atSeptember 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. F-26 Table of Contents15) 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 debtpremium 10.25% $103 $94 $52 Decrease in net debt premium attributable to redemption of debt $— $— $247 16) Commitments and ContingenciesThe Partnership’s operations are subject to all operating hazards and risks normally incidental to handling, storing and transporting and otherwiseproviding 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 invarious legal proceedings and litigation arising in the ordinary course of business. The Partnership maintains insurance policies with insurers in amounts andwith coverages and deductibles we believe are reasonable and prudent. However, the Partnership cannot assure that this insurance will be adequate to protectit 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 futureat economical prices. In the opinion of management the Partnership is not a party to any litigation which, individually or in the aggregate, could reasonablybe expected to have a material adverse effect on the Partnership’s results of operations, financial position or liquidity.17) Earnings Per Limited Partner UnitsThe following table presents the net income allocation and per unit data in accordance with FASB ASC 260-10-45-60 Earnings per Share, MasterLimited 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 FASBASC 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 perFASB 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 contractualparticipation rights of the security to share in earnings, regardless of whether those earnings would actually be distributed during a particular period froman economic or practical perspective. This allocation does not impact the Partnership’s overall net income or other financial results. F-27 Table of Contents18) 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 netlosses 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 EventsQuarterly Distribution DeclaredOn 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 respectof the fourth quarter of fiscal 2013 payable on November 14, 2013 to holders of record on November 12, 2013. In accordance with our PartnershipAgreement, the amount of distributions in excess of the minimum quarterly distribution of $0.0675, are distributed 90% to the holders of common units and10% 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 $0.05million to management pursuant to the management incentive compensation plan which provides for certain members of management to receive incentivedistributions that would otherwise be payable to the general partner.Common Units Repurchased and RetiredIn accordance with the Plan III common unit repurchase program, during the first two months of fiscal 2014 the Partnership repurchased and retired250 thousand common units at an average price paid of $5.20 per unit. F-28 Table of ContentsSchedule ISTAR 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. F-29 Table of ContentsSchedule ISTAR 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 F-30 Table of ContentsSchedule ISTAR 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 F-31 Table of ContentsSTAR GAS PARTNERS, L.P. AND SUBSIDIARIES Schedule IIVALUATION AND QUALIFYING ACCOUNTSYears Ended September 30, 2013, 2012 and 2011(in thousands) Year Description Balance atBeginningof Year Chargedto Costs &Expenses OtherChangesAdd (Deduct) Balance atEnd of Year 2013 Allowance for doubtful accounts $6,886 $6,481 $(5,439) $7,928 2012 Allowance for doubtful accounts $9,530 $6,017 $(8,661) $6,886 2011 Allowance for doubtful accounts $5,443 $10,388 $(6,301) $9,530 Bad debts written off (net of recoveries). F-32(a)(a)(a)(a) Exhibit 21Partnership SubsidiariesA.P. Woodson Company—District of ColumbiaCFS LLC —PennsylvaniaC. Hoffberger Company —MarylandChampion Energy Corporation—DelawareChampion Oil Company —ConnecticutColumbia Petroleum Transportation, LLC—DelawareHoffman Fuel Company of Bridgeport —DelawareHoffman Fuel Company of Danbury—DelawareHoffman Fuel Company of Stamford —DelawareJ.J. Skelton Oil Company —PennsylvaniaLewis Oil Company, Inc. —New YorkMarex Corporation—MarylandMeenan Holdings of New York, Inc.—New YorkMeenan Oil Co., Inc.—DelawareMeenan Oil Co., L.P.—DelawareMinnwhale, LLC .—New YorkOrtep of Pennsylvania, Inc.—PennsylvaniaPetro Holdings, Inc.—MinnesotaPetro Plumbing Corporation—New JerseyPetro, Inc.—DelawarePetroleum Heat and Power Co., Inc.—MinnesotaRegionOil Plumbing, Heating and Cooling Co., Inc.—New JerseyRichland Partners, LLC—PennsylvaniaRye Fuel Company —DelawareStar Gas Finance Company—DelawareStar Acquisitions, Inc.—MinnesotaTG&E Service Company, Inc.—Florida Exhibit 23.1Consent of Independent Registered Public Accounting FirmThe Partnersof Star Gas Partners, L.P.:We consent to the incorporation by reference in the registration statement (No. 333-175247) on Form S-3 of Star Gas Partners, L.P. of our report datedDecember 11, 2013, with respect to the consolidated balance sheets of Star Gas Partners, L.P. (“the Partnership”) as of September 30, 2013 and 2012, and therelated consolidated statements of operations, comprehensive income, partners’ capital and cash flows for each of the years in the three-year period endedSeptember 30, 2013, the related financial statement schedules, and the effectiveness of internal control over financial reporting as of September, 30, 2013,which report appears in the September 30, 2013 annual report on Form 10-K of Star Gas Partners, L.P./s/ KPMGStamford, ConnecticutDecember 11, 2013 Exhibit 31.1CERTIFICATIONSI, Steven J. Goldman, certify that: 1.I have reviewed this annual report on Form 10-K of Star Gas Partners, L.P. (“Registrant”); 2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make thestatements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by thisreport; 3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects thefinancial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined inExchange Act Rules 13a-15(e) and 15d-15(e)) and internal controls over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: (a)designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, toensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within thoseentities, particularly during the period in which this report is being prepared; (b)designed such internal controls over financial reporting, or caused such internal controls over financial reporting to be designed under oursupervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements forexternal purposes in accordance with generally accepted accounting principles; (c)evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about theeffectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (d)disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recentfiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materiallyaffect, the registrant’s internal control over financial reporting; and 5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to theregistrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): (a)all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonablylikely to adversely affect the registrant’s ability to record, process, summarize and report financial information and; (b)any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controlover financial reporting.Date: December 11, 2013 /s/ Steven J. GoldmanSteven J. GoldmanPresident and Chief Executive OfficerStar Gas Partners, L.P. Exhibit 31.2CERTIFICATIONSI, Richard F. Ambury, certify that: 1.I have reviewed this annual report on Form 10-K of Star Gas Partners, L.P. (“Registrant”); 2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make thestatements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by thisreport; 3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects thefinancial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4.The registrants’ other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined inExchange Act Rules 13a-15(e) and 15d-15(e)) and internal controls over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: (a)designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, toensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within thoseentities, particularly during the period in which this report is being prepared; (b)designed such internal controls over financial reporting, or caused such internal controls over financial reporting to be designed under oursupervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements forexternal purposes in accordance with generally accepted accounting principles; (c)evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about theeffectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (d)disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recentfiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materiallyaffect, the registrant’s internal control over financial reporting; and 5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to theregistrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): (c)all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonablylikely to adversely affect the registrant’s ability to record, process, summarize and report financial information and; (d)any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controlover financial reporting.Date: December 11, 2013 /S/ RICHARD F. AMBURYRichard F. AmburyChief Financial OfficerStar Gas Partners, L.P. Exhibit 32.1CERTIFICATION PURSUANT TO18 U.S.C. SECTION 1350AS ADOPTED PURSUANT TO SECTION 906OF THE SARBANES-OXLEY ACT OF 2002In connection with the Annual Report of Star Gas Partners, L.P. (the “Partnership”) on Form 10-K for the year ended September 30, 2013 as filed withthe Securities and Exchange Commission on the date hereof (the “Report”), I, Steven J. Goldman, President and Chief Executive Officer of the Partnership,certify to my knowledge pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, following due inquiry, Ibelieve that: (1)The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and (2)The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of thePartnership.A signed original of this written statement required by Section 906 has been provided to Star Gas Partners, L.P. and will be retained by Star GasPartners, L.P. and furnished to the Securities and Exchange Commission or its staff upon request. STAR GAS PARTNERS, L.P.By: KESTREL HEAT, LLC (General Partner) Date: December 11, 2013 By: /s/ Steven J. Goldman Steven J. GoldmanPresident and Chief Executive OfficerStar Gas Partners, L.P. Exhibit 32.2CERTIFICATION PURSUANT TO18 U.S.C. SECTION 1350AS ADOPTED PURSUANT TOSECTION 906 OF THE SARBANES-OXLEY ACT OF 2002In connection with the Annual Report of Star Gas Partners, L.P. (the “Partnership”) on Form 10-K for the year ended September 30, 2013 as filed withthe Securities and Exchange Commission on the date hereof (the “Report”), I, Richard F. Ambury, Chief Financial Officer of the Partnership, certify to myknowledge pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, following due inquiry, I believe that: (1)The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and (2)The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of thePartnership.A signed original of this written statement required by Section 906 has been provided to Star Gas Partners, L.P. and will be retained by Star GasPartners, L.P. and furnished to the Securities and Exchange Commission or its staff upon request. STAR GAS PARTNERS, L.P.By: KESTREL HEAT, LLC (General Partner) Date: December 11, 2013 By: /S/ RICHARD F. AMBURY Richard F. AmburyChief Financial OfficerStar Gas Partners, L.P.
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