STAR GROUP, L.P. - Quarter Report: 2014 December (Form 10-Q)

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-Q

(Mark One)

For the quarterly period ended December 31, 2014

OR

For the transition period from                      to                     

Commission File Number: 001-14129

STAR GAS PARTNERS, L.P.

(Exact name of registrants as specified in its charters)

(203) 328-7310

(Registrant’s telephone number, including area code)

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

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

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

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

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

At January 31, 2015, the registrant had 57,282,352 Common Units outstanding.

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STAR GAS PARTNERS, L.P. AND SUBSIDIARIES

INDEX TO FORM 10-Q

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Part I. FINANCIAL INFORMATION

Item 1. Condensed Consolidated Financial Statements

STAR GAS PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

See accompanying notes to condensed consolidated financial statements.

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STAR GAS PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

See accompanying notes to condensed consolidated financial statements.

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STAR GAS PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

See accompanying notes to condensed consolidated financial statements.

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STAR GAS PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL

See accompanying notes to condensed consolidated financial statements.

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STAR GAS PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

See accompanying notes to condensed consolidated financial statements.

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STAR GAS PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

1) Partnership Organization

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

The Partnership is organized as follows:

2) Summary of Significant Accounting Policies

Basis of Presentation

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

The financial information included herein is unaudited; however, such information reflects all adjustments (consisting solely of normal recurring adjustments), which are, in the opinion of management, necessary for the fair statement of financial condition and results for the interim periods. Due to the seasonal nature of the Partnership’s business, the results of operations and cash flows for the three month period ended December 31, 2014, and December 31, 2013, are not necessarily indicative of the results to be expected for the full year.

These interim financial statements of the Partnership have been prepared in accordance with U.S. Generally Accepted Accounting Principles (“GAAP”) for interim financial information and Rule 10-01 of Regulation S-X of the U.S. Securities and Exchange Commission and should be read in conjunction with the financial statements included in the Partnership’s Annual Report on Form 10-K for the year ended September 30, 2014.

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Comprehensive Income (Loss)

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

Recent Accounting Pronouncements

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

3) Common Unit Repurchase and Retirement

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

Under the Partnership’s second amended and restated credit agreement dated January 14, 2014, in order to repurchase Common Units we must maintain Availability (as defined in the second amended and restated credit facility agreement) of $45 million, 15.0% of the facility size of $300 million (assuming the non-seasonal aggregate commitment is outstanding) on a historical pro forma and forward-looking basis, and a fixed charge coverage ratio of not less than 1.15 measured as of the date of repurchase. The Partnership was in compliance with this covenant for all unit repurchases made during the three months ended December 31, 2014.

The following table shows repurchases under Plan III.

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

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

To hedge a substantial majority of the purchase price associated with heating oil gallons anticipated to be sold to its price-protected customers as of December 31, 2014, the Partnership had bought 12.4 million gallons of swap contracts, 5.6 million gallons of call options, 7.7 million gallons of put options and 94.1 million net gallons of synthetic calls, all in future months to match anticipated sales. To hedge the inter-month differentials for its price-protected customers, its physical inventory on hand and inventory in transit, the Partnership, as of December 31, 2014, had bought 29.6 million gallons of future contracts and sold 55.1 million gallons of future contracts. To hedge a majority of its internal fuel usage for fiscal 2015, the Partnership as of December 31, 2014, had bought 2.9 million gallons of future swap contracts.

To hedge a substantial majority of the purchase price associated with heating oil gallons anticipated to be sold to its price-protected customers as of December 31, 2013, the Partnership held 1.6 million gallons of physical inventory and had bought 10.0 million gallons of swap contracts, 4.5 million gallons of call options, 6.9 million gallons of put options and 86.0 million net gallons of synthetic calls, all in future months to match anticipated sales. To hedge the inter-month differentials for its price-protected customers, its physical inventory on hand and inventory in transit, the Partnership, as of December 31, 2013, had bought 57.6 million gallons of future contracts, had sold 76.5 million gallons of future contracts and had sold 16.3 million gallons of future swap contracts. In addition to the previously described hedging instruments, the Partnership as of December 31, 2013, had bought corresponding long and short 38.6 million net gallons of swap contracts and bought 3.9 million gallons of spread contracts (simultaneous long and short positions) to lock-in the differential between high sulfur home heating oil and ultra low sulfur diesel, which is similar in composition to ultra low sulfur home heating oil. To hedge a majority of its internal fuel usage for fiscal 2014, the Partnership as of December 31, 2013, had bought 2.4 million gallons of future swap contracts.

The Partnership’s derivative instruments are with the following counterparties: Bank of America, N.A., Bank of Montreal, Cargill, Inc., Citibank, N.A., JPMorgan Chase Bank, N.A., Key Bank, N.A., Regions Financial Corporation, Societe Generale, and Wells Fargo Bank, N.A. The Partnership assesses counterparty credit risk and considers it to be low. We maintain master netting arrangements that allow for the non-conditional offsetting of amounts receivable and payable with counterparties to help manage our risks and record derivative positions on a net basis. The Partnership generally does not receive cash collateral from its counterparties and does not restrict the use of cash collateral it maintains at counterparties. At December 31, 2014, the aggregate cash posted as collateral in the normal course of business at counterparties was $2.3 million. Positions with counterparties who are also parties to our revolving credit facility are collateralized under that facility. As of December 31, 2014, $28.7 million of hedge positions and payable amounts were secured under the credit facility.

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

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

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

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5) Inventories

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

6) Property and Equipment

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

7) Intangibles, net

Intangibles, net

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

Amortization expense for intangible assets was $3.3 million for the three months ended December 31, 2014, compared to $2.3 million for the three months ended December 31, 2013.

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8) Long-Term Debt and Bank Facility Borrowings

The second amended and restated revolving credit facility provides the Partnership with the ability to borrow up to $300 million ($450 million during the heating season of December through April of each year) for working capital purposes (subject to certain borrowing base limitations and coverage ratios), including the issuance of up to $100 million in letters of credit, and extends the maturity date to June 2017, or January 2019 if the Partnership has met the conditions of the facility termination date as defined in the agreement and as discussed further below. The Partnership can increase the facility size by $100 million without the consent of the bank group. However, the bank group is not obligated to fund the $100 million increase. If the bank group elects not to fund the increase, the Partnership can add additional lenders to the group, with the consent of the Agent, which shall not be unreasonably withheld. Obligations under the second amended and restated credit facility are guaranteed by the Partnership and its subsidiaries and are secured by liens on substantially all of the Partnership’s assets including accounts receivable, inventory, general intangibles, real property, fixtures and equipment.

All outstanding amounts owed under the second amended and restated credit facility become due and payable on the facility termination date of June 1, 2017. If the Partnership has repaid, prepaid or otherwise defeased at least $100 million of our 8.875% Senior Notes and Availability is equal to or greater than the aggregate amount required to repay the remaining outstanding 8.875% Senior Notes (“Payoff Amount”), then the facility termination date is January 14, 2019. However, after June 1, 2017, in the event that Availability is less than the Payoff Amount, the facility termination date shall be three days following such date. Notwithstanding this, all outstanding amounts are subject to acceleration upon the occurrence of events of default which the Partnership considers usual and customary for an agreement of this type, including failure to make payments under the second amended and restated credit facility, non-performance of covenants and obligations or insolvency or bankruptcy (as described in the second amended and restated credit facility).

The interest rate on the second amended and restated credit facility is LIBOR plus (i) 1.75% (if Availability, as defined in the agreement is greater than or equal to $150 million), or (ii) 2.00% (if Availability is greater than $75 million but less than $150 million), or (iii) 2.25% (if Availability is less than or equal to $75 million). The Commitment Fee on the unused portion of the facility is 0.30% per annum.

Under the second amended and restated credit facility, the Partnership is obligated to meet certain financial covenants, including the requirement to maintain at all times either Availability (borrowing base less amounts borrowed and letters of credit issued) of 12.5% of the facility size, or a fixed charge coverage ratio (as defined in the revolving credit facility agreement) of not less than 1.1, which is calculated based upon Adjusted EBITDA for the trailing twelve months. In order to make acquisitions, the Partnership must maintain Availability of $40 million on a historical pro forma and forward-looking basis. In addition, the Partnership must maintain Availability of $45 million, 15.0% of the facility size of $300 million (assuming the non-seasonal aggregate commitment is outstanding), on a historical and forward-looking basis, and a fixed charge coverage ratio of not less than 1.15 in order to pay any distributions to unitholders or repurchase Common Units. No inter-company dividends or distributions can be made (including those needed to pay interest or principle on our 8.875% Senior Notes), except to the Partnership or a wholly owned subsidiary of the Partnership, if the immediately preceding covenants have not been met. Certain restrictions are also imposed by the agreement, including restrictions on the Partnership’s ability to incur additional indebtedness, to pay distributions to unitholders, to pay inter-company dividends or distributions, make investments, grant liens, sell assets, make acquisitions and engage in certain other activities.

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At December 31, 2014, no amount was outstanding under the revolving credit facility, $28.7 million of hedge positions were secured, and $55.3 million of letters of credit were issued. At September 30, 2014, no amount was outstanding under the revolving credit facility, $14.9 million of hedge positions were secured, and $52.8 million of letters of credit were issued.

At December 31, 2014, availability was $181.7 million and the Partnership was in compliance with the fixed charge coverage ratio. At September 30, 2014, availability was $149.6 million and the Partnership was in compliance with the fixed charge coverage ratio.

9) Income Taxes

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

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

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

The current and deferred income tax expenses for the three months ended December 31, 2014, and 2013 are as follows:

As of January 1, 2015, Star Acquisitions, Inc., a wholly-owned subsidiary of the Partnership, had an estimated Federal net operating loss carry forward (“NOLs”) of approximately $6.1 million. The Federal NOLs, which will expire between 2018 and 2024, are generally available to offset any future taxable income but are also subject to annual limitations of between $1.0 million and $2.2 million.

FASB ASC 740-10-05-6 Income Taxes, Uncertain Tax Position, provides financial statement accounting guidance for uncertainty in income taxes and tax positions taken or expected to be taken in a tax return. At December 31, 2014, we had unrecognized income tax benefits totaling $0.9 million including related accrued interest and penalties of $0.03 million. These unrecognized tax benefits are primarily the result of state tax uncertainties. If recognized, these tax benefits would be recorded as a benefit to the effective tax rate.

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We believe that the total liability for unrecognized tax benefits will not materially change during the next 12 months ending December 31, 2015. Our continuing practice is to recognize interest related to income tax matters as a component of income tax expense. We file U.S. Federal income tax returns and various state and local returns. A number of years may elapse before an uncertain tax position is audited and finally resolved. For our Federal income tax returns we have four tax years subject to examination. In our major state tax jurisdictions of New York, Connecticut, Pennsylvania and New Jersey, we have four, four, four and five tax years, respectively, that are subject to examination. While it is often difficult to predict the final outcome or the timing of resolution of any particular uncertain tax position, based on our assessment of many factors including past experience and interpretation of tax law, we believe that our provision for income taxes reflect the most probable outcome. This assessment relies on estimates and assumptions and may involve a series of complex judgments about future events.

10) Supplemental Disclosure of Cash Flow Information

11) Commitments and Contingencies

At any given time the Partnership is a defendant in various legal proceedings and litigation arising in the ordinary course of business. The Partnership records a liability when it is probable that a loss has been incurred and the amount is reasonably estimable. The Partnership maintains insurance policies with insurers in amounts and with coverages and deductibles we believe are reasonable and prudent. However, the Partnership cannot assure that this insurance will be adequate to protect it from all material expenses related to potential future claims. In the opinion of management the Partnership is not a party to any litigation which, individually or in the aggregate, could reasonably be expected to have a material adverse effect on the Partnership’s results of operations, financial position or liquidity.

12) Earnings Per Limited Partner Unit

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

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

13) Subsequent Events

Quarterly Distribution Declared

In January 2015, we declared a quarterly distribution of $0.0875 per unit, or $0.35 per unit on an annualized basis, on all Common Units with respect to the first quarter of fiscal 2015, payable on February 10, 2015, to holders of record on January 30, 2015. In accordance with our Partnership Agreement, the amount of distributions in excess of the minimum quarterly distribution of $0.0675, are distributed 90% to Common Unit holders and 10% to the General Partner unit holders (until certain distribution levels are met), subject to the management incentive compensation plan. As a result, $5.0 million will be paid to the Common Unit holders, $0.1 million to the General Partner unit holders (including $0.06 million of incentive distribution as provided in our Partnership Agreement) and $0.06 million to management pursuant to the management incentive compensation plan which provides for certain members of management to receive incentive distributions that would otherwise be payable to the General Partner.

Acquisition

In January 2015, the Partnership purchased for cash the customer lists and assets of a propane dealership for approximately $1.1 million, including net working capital credits of $0.1 million.

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ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Statement Regarding Forward-Looking Disclosure

This Quarterly Report on Form 10-Q includes “forward-looking statements” which represent our expectations or beliefs concerning future events that involve risks and uncertainties, including those associated with the effect of weather conditions on our financial performance, the price and supply of the products that we sell, the consumption patterns of our customers, our ability to obtain satisfactory gross profit margins, our ability to obtain new customers and retain existing customers, our ability to make strategic acquisitions, the impact of litigation, our ability to contract for our current and future supply needs, natural gas conversions, future union relations and the outcome of current and future union negotiations, the impact of current and future governmental regulations, including environmental, health, and safety regulations, the ability to attract and retain employees, customer credit worthiness, counterparty credit worthiness, marketing plans, general economic conditions and new technology. All statements other than statements of historical facts included in this Report including, without limitation, the statements under “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and elsewhere herein, are forward-looking statements. Without limiting the foregoing, the words “believe,” “anticipate,” “plan,” “expect,” “seek,” “estimate,” and similar expressions are intended to identify forward-looking statements. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that such expectations will prove to be correct and actual results may differ materially from those projected as a result of certain risks and uncertainties. These risks and uncertainties include, but are not limited to, those set forth in this Report under the headings “Risk Factors” and “Business Strategy.” Important factors that could cause actual results to differ materially from our expectations (“Cautionary Statements”) are disclosed in this Report. All subsequent written and oral forward-looking statements attributable to the Partnership or persons acting on its behalf are expressly qualified in their entirety by the Cautionary Statements. Unless otherwise required by law, we undertake no obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise after the date of this Report.

Seasonality

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

Degree Day

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

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

Home Heating Oil Price Volatility

In recent years, the wholesale price of home heating oil has been volatile, resulting in increased consumer price sensitivity to heating costs and increased gross customer losses. As a commodity, the price of home heating oil is generally impacted by many factors, including economic and geopolitical forces. The price of home heating oil is closely linked to the price refiners pay for crude oil, which is the principal cost component of home heating oil. The volatility in the wholesale cost of home heating oil, as measured by the New York Mercantile Exchange (“NYMEX”), for the fiscal years ending September 30, 2011 through 2015, on a quarterly basis, is illustrated in the following chart (price per gallon):

Impact on Liquidity of Wholesale Product Cost Volatility

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

Weather Hedge Contract

Weather conditions have a significant impact on the demand for home heating oil and propane because customers depend on these products principally for space heating purposes. Actual weather conditions can vary substantially from year to year, significantly affecting our financial performance. To partially mitigate the adverse effect of warm weather on our cash flows, we have used weather hedging contracts for a number of years.

The Partnership entered into weather hedge contracts for the fiscal years 2015, 2016 and 2017 with Swiss Re, under which Star is entitled to receive a payment of $35,000 per heating degree-day shortfall if the total number of heating degree-days in the hedge period is less than approximately 92.5% of the ten year average (the “Payment Threshold”). The hedge covers the period from November 1 through March 31, taken as a whole, for each respective fiscal year and has a maximum payout of $12.5 million for each fiscal year.

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Per Gallon Gross Profit Margins

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

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

Derivatives

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

Acquisitions

On March 4, 2014, the Partnership completed the acquisition of Griffith Energy Services, Inc. (“Griffith”) of Columbia, Maryland, from Central Hudson Enterprises Corporation. The Partnership purchased 100% of the stock of Griffith for $97.7 million, consisting of $69.9 million paid for the long term assets and $27.8 million paid for working capital (net of $4.2 million of cash acquired). The results of Griffith are reflected in fiscal 2014 from the date of acquisition. Griffith’s results are included in the three months ended December 31, 2014, but are not included in the three months ended December 31, 2013.

On December 22, 2014, the Partnership entered into an agreement to deliver to and service certain home heating oil accounts of a company in the New York City area that was exiting the business. The agreement provides that the Partnership will make payments to the seller over the next three years, an estimated $1.0 million, based upon the Partnership’s retention of the accounts.

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Income Taxes

Net Operating Loss Carry Forwards

The Partnership and its corporate subsidiaries file Federal and state income tax returns on a calendar year. As of January 1, 2015, our Federal Net Operating Loss carry forwards (“NOLs”) were $6.1 million, subject to annual limitations of between $1.0 million and $2.2 million on the amount of such losses that can be used.

Book Versus Tax Deductions

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

Estimated Depreciation and Amortization Expense

Non-Deductible Partnership Expenses

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

Customer Attrition

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

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Gross customer gains and losses

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

During the first quarter of fiscal 2015, the Partnership gained 4,300 accounts (net), or 1.0%, of our home heating oil and propane customer base, compared to a gain of 3,000 accounts (net), or 0.8% of our home heating oil and propane customer base, in the first quarter of fiscal 2014. The improvement of 1,300 accounts was due to an increase in gross customer gains of 1,700, slightly offset by higher gross customer losses of 400. Included in the results for the first fiscal quarter of fiscal 2015 were gross customer gains (2,400) and gross customer losses (1,400) attributable to the Griffith acquisition. Excluding the results of the Griffith acquisition the base business added 3,300 accounts (net) or 300 more than the first quarter of fiscal 2014.

During the first quarter of fiscal 2015, we lost 0.6% of our home heating oil accounts to natural gas conversions versus 0.7% for the first quarter of both fiscal 2014 and fiscal 2013. Conversions to natural gas may continue as natural gas has become significantly less expensive than home heating oil on an equivalent BTU basis.

Consolidated Results of Operations

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

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Three Months Ended December 31, 2014

Compared to the Three Months Ended December 31, 2013

Volume

For the three months ended December 31, 2014, retail volume of home heating oil and propane sold increased by 3.8 million gallons, or 3.6%, to 107.5 million gallons, compared to 103.7 million gallons for the three months ended December 31, 2013. For those locations where the Partnership had existing operations during both periods, which are sometimes referred to as the “base business” (i.e., excluding acquisitions), temperatures (measured on a heating degree day basis) for the three months ended December 31, 2014 were 5.5% warmer than the three months ended December 31, 2013 and 7.4% warmer than normal, as reported by NOAA. For the twelve months ended December 31, 2014, net customer attrition for the base business was 0.8%. For various reasons, including the price per gallon of home heating oil and propane, we believe that our customers have adopted conservation measures to use less of such products. The impact of any such conservation, along with any period-to-period differences in delivery scheduling, the timing of accounts added or lost during the fiscal years, equipment efficiency and other volume variances not otherwise described, are included in the chart below under the heading “Other.” An analysis of the change in the retail volume of home heating oil and propane sold, which is based on management’s estimates, other mathematical calculations and certain assumptions, is as follows:

The Partnership has experienced a shift away from variable pricing plans to price-protected plans as customers are seeking surety of price, which may impact our per gallon margins in the future. The following chart sets forth the percentage by volume of total home heating oil sold to residential variable-price customers, residential price-protected customers and commercial/industrial/other customers for the three months ended December 31, 2014 compared to the three months ended December 31, 2013:

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Volume of other petroleum products sold increased by 10.8 million gallons, or 72.1%, to 25.8 million gallons for the three months ended December 31, 2014 compared to 15.0 million gallons for the three months ended December 31, 2013, reflecting additional volume provided by the Griffith acquisition of 12.1 million gallons.

Product Sales

For the three months ended December 31, 2014, product sales declined $28.4 million, or 6.1%, to $435.0 million, compared to $463.4 million for the three months ended December 31, 2013, as an increase in total volume of product sold of 12.3% was reduced by declines in the average selling prices for home heating oil and propane and other petroleum products. Selling prices were lower largely due to decline in the cost per gallon of home heating oil and propane and other petroleum products of 23.2%.

Installations and Services Sales

For the three months ended December 31, 2014, installations and services sales increased $7.0 million, or 12.2%, to $64.2 million, compared to $57.2 million for the three months ended December 31, 2013, due to the additional revenue from acquisitions of $6.2 million, or 10.8%, and an increase in revenue in the base business of $0.8 million, or 1.4%.

Cost of Product

For the three months ended December 31, 2014, cost of product decreased $49.3 million, or 13.8%, to $309.3 million, compared to $358.6 million for the three months ended December 31,2013, as an increase in total volume of 12.3% was reduced by a decline in the per gallon cost of home heating oil and propane and other petroleum products of 23.2%.

Gross Profit — Product

The table below calculates the Partnership’s per gallon margins and reconciles product gross profit for home heating oil and propane and other petroleum products. We believe the change in home heating oil and propane margins should be evaluated before the effects of increases or decreases in the fair value of derivative instruments, as we believe that realized per gallon margins should not include the impact of non-cash changes in the market value of hedges before the settlement of the underlying transaction. On that basis, home heating oil and propane margins for the three months ended December 31, 2014, increased by $0.1277 per gallon, or 13.1%, to $1.1006 per gallon, from $0.9729 per gallon during the three months ended December 31, 2013. In the base business, home heating oil and propane margins increased by $0.1150 per gallon to $1.0879 for the three months ended December 31, 2014. The expansion of the Partnership’s margins in the base business during the three months ended December 31, 2014 was in excess of historical averages by $0.0890 per gallon, largely due to the decline in product cost of 23.2%. Going forward, the Partnership cannot predict whether the per gallon margins achieved during the three months ended December 31, 2014 are sustainable. Product sales and cost of product include home heating oil, propane, other petroleum products and liquidated damages billings.

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For the three months ended December 31, 2014, total product gross profit increased by $21.0 million to $125.8 million, compared to $104.8 million for the three months ended December 31, 2013, due to an increase in home heating oil and propane volume sold ($3.6 million), the impact of higher home heating oil and propane margins ($13.7 million) and the additional gross profit from other petroleum products ($3.6 million). The increase in gross profit from other petroleum products was largely due to the additional sales volume provided by the Griffith acquisition.

Cost of Installations and Services

For the three months ended December 31, 2014, cost of installations and services increased by $7.2 million, or 13.6%, to $60.6 million, compared to $53.4 million for the three months ended December 31, 2013, due to a $5.1 million increase related to acquisitions and a $2.1 million increase in costs associated with our base business.

Installation costs for the three months ended December 31, 2014 increased by $2.0 million, or 10.4%, to $21.2 million, largely due to an increase from acquisitions of $1.9 million. Installation costs as a percentage of installation sales for the three months ended December 31, 2014 and the three months ended December 31, 2013 were 81.9% and 83.0%, respectively. Services expenses increased by $5.2 million to $39.4 million for the three months ended December 31, 2014, or 103.1% of services sales, versus $34.2 million, or 100.5% of services sales, for the three months ended December 31, 2013. Acquisitions accounted for $3.2 million of the increase and expenses attributable to the expansion of certain service offerings was the primary driver of a $2.0 million increase in expenses relating to the base business.

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We achieved a combined profit from services and installations of $3.5 million for the three months ended December 31, 2014, or $0.3 million less than a combined profit of $3.8 million for the three months ended December 31, 2013. While acquisitions provided $1.1 million of gross profit from services and installations activities, the Partnership saw a decline in gross profit from the base business of $1.4 million.

Management views the services and installations department on a combined basis because many overhead functions and direct expenses such as service technician time cannot be separated or precisely allocated to either services or installations billings.

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

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

During the three months ended December 31, 2013, the change in the fair value of derivative instruments resulted in a $5.5 million credit due to the expiration of certain hedged positions (a $1.8 million credit) and an increase in the market value for unexpired hedges (a $3.7 million credit).

Delivery and Branch Expenses

For the three months ended December 31, 2014, delivery and branch expenses increased $10.4 million, or 15.3%, to $78.8 million, compared to $68.4 million for the three months ended December 31, 2013, largely due to the 12.3% increase in total volume sold. Acquisitions accounted for $9.0 million of the increase and expense relating to in the base business rose by $1.4 million, or 2.0%.

On a cents per gallon basis, delivery and branch expenses for the three months ended December 31, 2014, increased $0.0105, or 1.8%, to $0.6054, compared to $0.5949 for the three months ended December 31, 2013.

Depreciation and Amortization

For the three months ended December 31, 2014, depreciation and amortization expenses increased by $1.8 million, or 41.3%, to $6.2 million, compared to $4.4 million for the three months ended December 31, 2013, primarily due to the Griffith acquisition.

General and Administrative Expenses

For the three months ended December 31, 2014, general and administrative expenses increased $0.7 million, or 12.0%, to $6.1 million, from $5.4 million for the three months ended December 31, 2013, primarily due to an increase in profit sharing expense of $0.2 million and an increase in legal and professional fees of $0.5 million.

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

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Finance Charge Income

For the three months ended December 31, 2014, finance charge income decreased $0.2 million, to $0.8 million, compared to $1.0 million for the three months ended December 31, 2013 due to lower past due balances.

Interest Expense, Net

For the three months ended December 31, 2014, net interest expense decreased $0.2 million, or 4.5%, to $3.4 million compared to $3.6 million for the three months ended December 31, 2013 due to a decline in average working capital borrowings of $26.3 million.

Amortization of Debt Issuance Costs

For the three months ended December 31, 2014, amortization of debt issuance costs was unchanged at $0.4 million from the three months ended December 31, 2013.

Income Tax Expense

For the three months ended December 31, 2014, income tax expense decreased by $2.2 million to $11.4 million, from $13.6 million for the three months ended December 31, 2013, due to the decrease in pretax income of $5.9 million. The effective tax rate was 42.2% for the three months ended December 31, 2014 compared to 41.3% for the three months ended December 31, 2013.

Net Income

For the three months ended December 31, 2014, net income decreased $3.7 million to $15.6 million, from $19.3 million for the three months ended December 31, 2013, as the decrease in pretax income of $5.9 million was greater than the decrease in income tax expense of $2.2 million.

Adjusted EBITDA

For the three months ended December 31, 2014, Adjusted EBITDA increased by $9.4 million, or 26.4%, to $45.2 million from $35.8 million for the three months ended December 31, 2013 as the impact of the Griffith acquisition and higher home heating oil and propane per gallon margins more than offset the impact of warmer weather and an increase in operating costs.

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

EBITDA and Adjusted EBITDA are calculated as follows:

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

DISCUSSION OF CASH FLOWS

We use the indirect method to prepare our Consolidated Statements of Cash Flows. Under this method, we reconcile net income to cash flows provided by operating activities by adjusting net income for those items that impact net income but may not result in actual cash receipts or payment during the period.

Operating Activities

Due to the seasonal nature of our business, cash is generally used in operations during the winter (our first and second fiscal quarters) as we require additional working capital to support the high volume of sales during this period, and cash is generally provided by operating activities during the spring and summer (our third and fourth quarters) when customer payments exceed the cost of deliveries.

During the three months ended December 31, 2014, cash used in operating activities decreased by $79.7 million to $13.4 million, when compared to $93.1 million of cash used in operating activities during the three months ended December 31, 2013, primarily due to: an $8.1 million increase in cash generated from operations, a favorable change in cash relating to accounts receivable of $63.6 million (including customer credit balances) and a decrease in cash needs to fund inventory of $7.5 million. The significant decline in the cost of liquid products resulted in a lower level of accounts receivables, higher customer credit balances and lower liquid product inventory.

Investing Activities

Our capital expenditures for the three months ended December 31, 2014 totaled $1.8 million, as we invested in computer hardware and software ($0.4 million), refurbished certain physical plants ($0.4 million), expanded our propane operations ($0.6 million) and made additions to our fleet and other equipment ($0.4 million).

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Our capital expenditures for the three months ended December 31, 2013 totaled $3.0 million, as we invested in computer hardware and software ($0.6 million), refurbished certain physical plants ($0.6 million), expanded our propane operations ($0.9 million) and made additions to our fleet and other equipment ($0.9 million).

Financing Activities

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

During the three months ended December 31, 2013, we borrowed $100.3 million under our credit facility, paid distributions of $4.7 million to our common unit holders and $0.07 million to our general partner (including $0.05 million of incentive distributions as provided in our Partnership Agreement) and repurchased 0.25 million units for $1.3 million in connection with our unit repurchase plan.

FINANCING AND SOURCES OF LIQUIDITY

Liquidity and Capital Resources

Our primary uses of liquidity are to provide funds for our working capital, capital expenditures, distributions on our units, acquisitions and unit repurchases. Our ability to provide funds for such uses depends on our future performance, which will be subject to prevailing economic, financial, business and weather conditions, the ability to pass on the full impact of high product costs to customers, the effects of high net customer attrition, conservation and other factors. Capital requirements, at least in the near term, are expected to be provided by cash flows from operating activities, cash on hand as of December 31, 2014 ($28.1 million) or a combination thereof. To the extent future capital requirements exceed cash on hand plus cash flows from operating activities, we anticipate that working capital will be financed by our revolving credit facility, as discussed below, and repaid from subsequent seasonal reductions in inventory and accounts receivable. As of December 31, 2014, we had no borrowings under our revolving credit facility and $55.3 million in letters of credit were outstanding, and our ability to borrow was reduced by $28.7 million to secure hedges with the bank group. If we require additional capital and the credit markets are receptive, we may seek to offer and sell debt securities.

Under the terms of the revolving credit facility, we must maintain at all times either Availability (borrowing base less amounts borrowed and letters of credit issued) of 12.5% of the maximum facility size or a fixed charge coverage ratio of not less than 1.1, which is calculated based upon Adjusted EBITDA for the trailing twelve month period. As December 31, 2014, Availability, as defined in the revolving credit facility agreement, was $181.7 million and we were in compliance with the fixed charge coverage ratio.

Maintenance capital expenditures for the remainder of fiscal 2015 are estimated to be approximately $4.5 million, excluding the capital requirements for leased fleet. In addition, we plan to invest an additional $2.0 million in our propane operations. Distributions for the balance of fiscal 2015, at the current quarterly level of $0.0875 per unit, would result in an aggregate of approximately $11.6 million to common unit holders, $0.3 million to our general partner (including $0.2 million of incentive distribution as provided for in our Partnership Agreement) and $0.2 million to management pursuant to the management incentive compensation plan which provides for certain members of management to receive incentive distributions that would otherwise be payable to the general partner. In addition, the Partnership’s scheduled interest payments on its Senior Notes, which are due in December 2017, amount to $5.5 million. While the Partnership is not obligated to make a minimum required contribution to its two frozen defined benefit pension plans in fiscal year 2015, it is expected that a $1.7 million pension contribution may be made before the end of fiscal 2015. In addition, we intend to continue to repurchase Common Units pursuant to our unit repurchase plan and seek attractive acquisition opportunities within the Availability constraints of our revolving credit facility and funding resources.

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Contractual Obligations and Off-Balance Sheet Arrangements

There has been no material change to Contractual Obligations and Off-Balance Sheet Arrangements since our September 30, 2014, Form 10-K disclosure and therefore, the table has not been included in this Form 10-Q.

Recent Accounting Pronouncements

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

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

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

At December 31, 2014, we had outstanding borrowings totaling $125.0 million, none of which is subject to variable interest rates.

We also use derivative financial instruments to manage our exposure to market risk related to changes in the current and future market price of home heating oil. The value of market sensitive derivative instruments is subject to change as a result of movements in market prices. Sensitivity analysis is a technique used to evaluate the impact of hypothetical market value changes. Based on a hypothetical ten percent increase in the cost of product at December 31, 2014, the fair market value of these outstanding derivatives would decrease by $(1.1) million to a negative value of $(19.5) million; and conversely a hypothetical ten percent decrease in the cost of product would increase the fair market value of these outstanding derivatives by $0.7 million to a negative value of $(17.7) million.

Item 4.

Controls and Procedures

a) Evaluation of disclosure controls and procedures.

The General Partner’s chief executive officer and its chief financial officer evaluated the effectiveness of the Partnership’s disclosure controls and procedures (as that term is defined in Rule 13a-15(e) of the Securities Exchange Act of 1934, as amended) as of December 31, 2014. Based on that evaluation, such chief executive officer and chief financial officer concluded that the Partnership’s disclosure controls and procedures were effective as of December 31, 2014 at the reasonable level of assurance. For purposes of Rule 13a-15(e), the term disclosure controls and procedures means controls and other procedures of an issuer that are designed to ensure that information required to be disclosed by the issuer in the reports that it files or submits under the Act (15 U.S.C. 78a et seq.) is recorded, processed, summarized and reported, within the time periods specified in the Commission’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Act is accumulated and communicated to the issuer’s management, including its chief executive and chief financial officer, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

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b) Change in Internal Control over Financial Reporting.

On March 4, 2014, the Partnership completed the acquisition of Griffith Energy Services, Inc. (“Griffith”). The Partnership is currently integrating Griffith into its operations. The Partnership is analyzing, evaluating and, where necessary, will implement changes in controls and procedures relating to the Griffith business as integration proceeds. As a result, this process may result in additions or changes to our internal control over financial reporting. Otherwise, there was no change in the Partnership’s internal control over financial reporting during the Partnership’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect the Partnership’s internal control over financial reporting.

c) The General Partner and the Partnership believe that a controls system, no matter how well designed and operated, cannot provide absolute assurance that the objectives of the controls system are met, and no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within a Partnership have been detected. Therefore, a control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Our disclosure controls and procedures are designed to provide such reasonable assurances of achieving our desired control objectives, and the chief executive officer and chief financial officer of our general partner have concluded, as of December 31, 2014, that our disclosure controls and procedures were effective in achieving that level of reasonable assurance.

PART II OTHER INFORMATION

Item 1.

Legal Proceedings

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

Item 1A.

Risk Factors

In addition to the other information set forth in this Report, investors should carefully review and consider the information regarding certain factors which could materially affect our business, results of operations, financial condition and cash flows set forth in Part I Item 1A. “Risk Factors” in our Fiscal 2014 Form 10-K. We may disclose changes to such factors or disclose additional factors from time to time in our future filings with the SEC.

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Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

Not applicable.

I tem 6.

Exhibits

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SIGNATURE

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