UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
FORM 10-K
(Mark One)
x | ANNUAL REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended September 30, 20052006
OR
¨ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
Commission File Number: 001-14129
Commission File Number: 333-103873
STAR GAS PARTNERS, L.P.
STAR GAS FINANCE COMPANY
(Exact name of registrants as specified in its charters)
Delaware
| 06-1437793
| |
Delaware | 75-3094991 | |
(State or other jurisdiction of
| (I.R.S. Employer Identification No.) |
2187 Atlantic Street, Stamford, Connecticut | 06902 | |
(Address of principal executive office) | (Zip Code) |
(203) 328-7310
(Registrants’ telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each class | Name of each exchange on which registered | |
Common Units | New York Stock Exchange | |
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨ No x.
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No x
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨
No x
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer (as definedor a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Act)Act (check one).x
Large accelerated filer ¨ | Accelerated filer x | Non-accelerated filer ¨ |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x
The aggregate market value of Star Gas Partners, L.P. Common Units held by non-affiliates of Star Gas Partners, L.P. on March 31, 20052006 was approximately $102,477,000.$89,627,000. As of December 8, 2005,14, 2006, the registrants had units and shares outstanding for each of the issuers’ classes of common stock as follows:
Star Gas Partners, L.P. | Common Units | |||
Star Gas Partners, L.P. | ||||
General Partner Units | 325,729 | |||
Star Gas Finance Company | Common Shares | 100 |
Documents Incorporated by Reference: None
20052006 FORM 10-K ANNUAL REPORT
Page | ||||
PART I | ||||
�� | ||||
Item 1. | 3 | |||
Item 1A. | ||||
Item 1B. | ||||
Item 2. | ||||
Item 3. | ||||
Item 4. | ||||
PART II | ||||
Item 5. | ||||
Item 6. | ||||
Item 7. | Management’s Discussion and Analysis of Financial Condition and Results of Operations | |||
Item 7A. | ||||
Item 8. | ||||
Item 9. | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure | |||
Item 9A. | ||||
Item 9B. | ||||
PART III | ||||
Item 10. | ||||
Item 11. | ||||
Item 12. | Security Ownership of Certain Beneficial Owners and Management | |||
Item 13. | ||||
Item 14. | ||||
PART IV | ||||
Item 15. |
ITEM 1. | BUSINESS |
Statement Regarding Forward-Looking Disclosure
This Annual Report on Form 10-K includes “forward-looking statements” which represent our expectations or beliefs concerning future events that involve risks and uncertainties, including those associated with the recapitalization, the effect of weather conditions, on our financial performance, the price and supply of home heating oil, the consumption patterns of our customers, our ability to obtain satisfactory gross profit margins, our ability to obtain new accounts and retain existing accounts, our ability to effect strategic acquisitions or redeploy assets, the ultimate disposition of Excess Proceeds from the sale of the propane segment, the impact of litigation, the continuing impact of the business process redesign project at the heating oil segment and our ability to address issues related to that project, our ability to contract for our future supply needs, natural gas conversions, future union relations and outcome of current and future union negotiations, the impact of current and future environmental, health, and safety regulations, customer credit worthiness, and marketing plans. 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. 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 have been 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 under the heading “Risk Factors,”Factors” and “Business Initiatives and Strategy,” and “Business Outlook Fiscal 2006.Strategy.” Without limiting the foregoing, the words “believe”, “anticipate”, “plan”, “expect”, “seek”, “estimate” and similar expressions are intended to identify forward-looking statements. Important factors that could cause actual results to differ materially from our expectations (“Cautionary Statements”) are disclosed in this Annual Report on Form 10-K. 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.
Structure
Star Gas Partners, L.P. (“Star Gas” Partners”, the “Partnership,”“Partnership”, “we,” “us,”“us” or “our,”“our”) is a home heating oil distributor and services provider. Star Gas Partners is a master limited partnership, which at September 30, 20052006 had outstanding 32.275.8 million common units (NYSE: “SGU” representing an 88.8%99.6% limited partner interest in Star Gas) and 3.4 million senior subordinated units (NYSE: “SGH” representing a 9.4% limited partner interest in Star Gas). Additional Partnership interests include 0.3 million junior subordinated units (representing a 0.9% limited partner interest)Gas Partners) and 0.3 million general partner units (representing a 0.9%an 0.4% general partner interest)interest in Star Gas Partners).
The Partnership is organized as follows:
• | Star Gas Finance Company is a |
We were formerly engaged in the retail distribution of propane and related supplies and equipment to residential and commercial customers in the Midwest and Northeast regions of the United States, Florida and Georgia (the “propane segment”). In December 2004, we completed the sale of all of our interests in the propane segment to Inergy Propane, LLC (“Inergy”) for a purchase price of $481.3 million. We recorded a gain on this sale of approximately $157 million.
We file annual, quarterly, current and other reports and information with the SEC. These filings can be viewed and downloaded from the Internet at the SEC’s website at www.sec.gov. In addition, these SEC filings are available at no cost as soon as reasonably practicable after the filing thereof on our website at www.star-gas.com/Edgar.cfm. These reports are also available to be read and copied at the SEC’s public reference room located at Judiciary Plaza, 450 5th100 F Street, N.W.N.E., Washington, D.C. 20549. The public may obtain information on the operation of the public reference room by calling the SEC at 1-800-SEC-0330. You may also obtain copies of these filings and other information at the offices of the New York Stock Exchange located at 11 Wall Street, New York, New York 10005.
SummaryRecapitalization
Effective as of Significant Events and Developments
Sale of propane segment
In December 2004 we completed the sale of our propane segment to Inergy for a cash purchase price of $481.3 million and recognized a gain of approximately $157 million from the sale after closing costs of approximately $14 million. $311 million of the proceeds from the sale were used to repurchase senior secured notes and first mortgage notes of the heating oil segment and propane segment, together with associated prepayment premiums, accrued interest and the amounts then outstanding under the propane segment’s working capital facility. Our propane segment represented approximately 24% and 20% of our total revenue in fiscal 2004 and 2003, respectively, and 64% of our operating income in each of fiscal 2004 and 2003, respectively. The historical results of the propane segment are reflected as discontinued operations in our consolidated financial statements.
New Credit Facility
On December 17, 2004 we executed a new $260 million revolving credit facility with a group of lenders led by J.P. Morgan Chase Bank, N.A. This new facility provides us the ability to borrow up to $260 million for working capital purposes (subject to certain borrowing base limitations and coverage ratios) and replaced the heating oil segment’s existing $235 million credit facility. Fees and expenses totaling approximately $8.0 million were incurred in connection with consummating the new facility. On November 3, 2005, the revolving credit facility was amended to increase the facility size by $50 million to $310 million for the peak winter months from December through March of each year. Obligations under the new revolving credit facility are secured by liens on substantially all of the assets ofApril 28, 2006, the Partnership the heating oil segment andcompleted its subsidiaries.
Unitholder Suit
In October 2004, a purported class action lawsuit was filed against the Partnership and various subsidiaries and current and former officers and directors. Subsequently, 16 additional class action complaints alleging the same or substantially similar claims were filed in the same district court. The complaints generally allege that the Partnership violated sections 10(b) and 20(a) of the Securities Exchange Act of 1934, as amended. The court has consolidated the class action complaints and appointed a lead plaintiff. On September 23, 2005 we filed motionsrecapitalization pursuant to dismiss. Plaintiffs replied to these motions on November 23, 2005 and we expect to file our reply briefs on or about December 20, 2005. In the interim, discovery in the matter remains stayed. We intend to continue to defend against this purported class action lawsuit vigorously.
Goodwill Write-down
During the second quarter of fiscal 2005, we incurred a non-cash goodwill impairment charge of $67 million at the heating oil segment as a result of triggering events that occurred during the second quarter of fiscal 2005. These triggering events included a significant decline in our unit price and the determination that operating results for fiscal year 2005 would be significantly lower than previously expected.
MLP Notes
In accordance with the terms of the indenture relating to the Partnership’s 10 1/4% Senior Notes (“MLP Notes”), we are permitted, within 360 daysa unit purchase agreement dated as of the sale, to apply the net proceeds (the “Net Proceeds”) of the sale of the propane segment either to reduce indebtedness (and reduce any related commitment) ofDecember 5, 2005, as amended, by and among, the Partnership, or of a restricted subsidiary, or to make an investment in assets or capital expenditures useful to the business of the Partnership or any of its subsidiaries as in effect on the issue date of the MLP Notes (the “Issue Date”) or any business related, ancillary or complementary to any of the businesses of the Partnership on the Issue Date (each a “Permitted Use” and collectively the “Permitted Uses”). To the extent any Net Proceeds that are not so applied exceed $10 million (“Excess Proceeds”), the indenture requires us to make an offer to all holders of MLP Notes to purchase for cash that number of MLP Notes that may be purchased with Excess Proceeds at a purchase price equal to 100% of the principal amount of the MLP Notes plus accrued and unpaid interest to the date of purchase. At September 30, 2005, Excess Proceeds totaled $93.2 million. As of December 2, 2005 all Excess Proceeds were applied toward a Permitted Use. See “Recapitalization” below and “Risk Factors—If our use of the net proceeds from the sale of the propane segment does not comply with the terms of the Indenture for the MLP Notes we may be subject to liability to the note holders, which could have a material adverse effect on us.”
Departure of Chairman and CEO
On March 7, 2005 (“the Termination Date”), Star Gas LLC and Mr. Irik P. Sevin entered into a letter agreement and(the former general release (the “Agreement”). In accordance with the Agreement, Mr. Sevin resigned from employment as the Chairman and Chief Executive Officer and President of Star Gas LLC (and its subsidiaries) under the employment agreement between Mr. Sevin and Star Gas LLC dated as of September 30, 2001. In addition, under terms of the Agreement Mr. Sevin transferred his member interests in Star Gas LLC to a voting trust of which Mr. Sevin is one of three trustees. Under the terms of the voting trust, those interests will be voted in accordance with the decision of a majority of the trustees. Pursuant to the Agreement, Mr. Sevin is entitled to an annual consulting fee totaling $395,000 for a period of five years following the Termination Date. In addition, the Agreement provides for Mr. Sevin to receive a retirement benefit equal to $350,000 per year for a 13-year period beginning with the month following the five-year anniversary of the Termination Date. At March 31, 2005, we recorded a liability for $4.2 million, which represents the present value of the cost of the Agreement.
Home Heating Oil Price Volatility
The wholesale price of heating oil, like any other market commodity, is generally set by the economic forces of supply and demand. Rapid global expansion is fueling an ever-increasing demand for oil. Home heating oil prices are closely linked to the price refiners pay for crude oil because crude oil is the principal cost component of home heating oil. Crude oil is bought and sold in the international marketplace and as such is subject to the economic forces of supply and demand worldwide. The United States imports more than 60% of the petroleum products it consumes. The wholesale cost of home heating oil as measured by the New York Mercantile Exchange (“Nymex”) at September 30, 2005, 2004 and 2003 was $2.06, $1.39 and $0.78, respectively
The current marketplace for petroleum products including home heating oil has been extremely volatile. In a volatile market even small changes in supply or demand can dramatically affect prices. The changes we have seen this past year and continue to experience have been significant. Heating oil prices are subject to price fluctuations if demand rises sharply because of excessively cold weather and/or disruptions at refineries and instability in key oil producing regions. Ultimately these increases in wholesale prices are, in most instances, borne by our customers. Because of these high prices we have experienced increased attrition in our customer base and a decrease in heating oil volume sold per customer (“conservation”). For fiscal 2005, over 75% of our revenue is attributable to the retail sale and delivery of home heating oil. About half of our retail sales of home heating oil are to customers who agree to pay a fixed or maximum price per gallon for each delivery over the next 12 months (“protected price” customers). The remaining retail sales are to customers that pay a variable price based principally on the daily spot price plus our profit margin.
We mitigate our exposure to our price protected customers in a volatile market by hedging our fixed and maximum price sales through the purchase of exchange traded options and futures, and over the counter options and swaps, and we mitigate our exposure to variable priced customers, in most instances, by passing through higher home heating oil costs directly to such customers.
Customer Attrition
We experienced net customer attrition of 7.1% in fiscal 2005. This compares to net attrition of 6.4% and 1.5% in fiscal 2004 and 2003, respectively. This increase in net customer attrition over the past two years can be attributed to: (i) a combination of the effect of our premium service/premium price strategy during a period when customer price sensitivity increased due to high energy prices; (ii) our decision in fiscal 2005 to maintain reasonable profit margins going forward in spite of competitors aggressive pricing tactics; (iii) the lag effect of customer attrition related to service and delivery problems experienced by customers in prior fiscal years; (iv) continued customer dissatisfaction with the centralization of customer care; and (v) tightened customer credit standards. For the period from October 1 to November 30, 2004, we gained 530 accounts (net)partner), or 0.1% of our home heating oil customer base as compared to the period from October 1 to November 30, 2005 in which we lost 4,315 accounts (net), or 0.9% of our customer base.
Recapitalization
On December 2, 2005 the board of directors of Star Gas LLC approved a strategic recapitalization of Star Gas Partners that, if approved by unitholders and completed, would result in a reduction in the outstanding amount of our 10 1/4% Senior Notes due 2013 (“Senior Notes”), of between approximately $87 million and $100 million.
The recapitalization includes a commitment by Kestrel Energy Partners, LLC (or “Kestrel”) and its affiliates to purchase $15 million of new equity capital and provide a standby commitment in a $35 million rights offering to our common unitholders, at a price of $2.00 per common unit. We would utilize the $50 million in new equity financing, together with an additional $10 million to $23.1 million from operations, to repurchase at least $60 million in face amount of our Senior Notes and, at our option, up to approximately $73.1 million of Senior Notes. In addition, certain noteholders have agreed to convert approximately $26.9 million in face amount of such notes into newly issued common units at a conversion price of $2.00 per unit in connection with the closing of the recapitalization.
We have entered into agreements with the holders of approximately 94% in principal amount of our Senior Notes which provide that: the noteholders commit to, and will, tender their Senior Notes at par (i) for a pro rata portion of $60 million or, at our option, up to approximately $73.1 million in cash, (ii) in exchange for approximately 13,434,000 new common units at a conversion price of $2.00 per unit (which new units would be acquired by exchanging approximately $26.9 million in face amount of Senior Notes) and (iii) in exchange for new notes representing the remaining face amount of the tendered notes. The principle terms of the new senior notes such as the term and interest rate are the same as the Senior Notes. The closing of the tender offer is conditioned upon the closing of the transactions under the Kestrel unit purchase agreement, which is discussed below. Upon closing the transaction we will incur a gain or loss on the exchange of Senior Notes for common units based on the difference between the $2.00 per unit conversion price and the fair value per unit represented by the per unit price in the open market on the conversion date.
Subject to and until the transaction closing, the noteholders have agreed not to accelerate indebtedness due under the senior notes or initiate any litigation or proceeding with respect to the Senior Notes. The noteholders have further agreed to: waive any default under the indenture; not to tender the Senior Notes in the change of control offer which will be required to be made following the closing of the transactions under the unit purchase agreement with Kestrel; and to consent to certain amendments to the existing indenture. The agreement with the noteholders further provides for the termination of its provisions in the event that the Kestrel unit purchase agreement is no longer in effect. The understandings and agreements contemplated by these transactions will terminate if the transaction does not close prior to April 30, 2006.
We believe the proposed recapitalization would substantially strengthen our balance sheet and thereby assist us in meeting our liquidity and capital requirements, which we believe would improve our future financial performance and as a result enhance unitholder value. In addition to enhancing unitholder value, we believe we will be able to operate more efficiently going forward with less long-term debt.
As part of the recapitalization transaction, we have entered into a definitive unit purchase agreement with Kestrel and its affiliates, which provides for, among other things: the receipt by us of $50 million in new equity financing through the issuance to Kestrel’s affiliates of 7,500,000 common units at $2.00 per unit for an aggregate of $15 million and the issuance of an additional 17,500,000 common units in a rights offering to our common unitholders at an exercise price of $2.00 per unit for an aggregate of $35 million. The rights will be non-transferable, and an affiliate of Kestrel has agreed to buy any common units not subscribed for in the rights offering. Under the terms of the unit purchase agreement,wholly-owned subsidiaries, Kestrel Heat LLC, or Kestrel Heat, a wholly owned subsidiary of Kestrel, will become our(the new general partnerpartner) and Star GasKM2, LLC, our current general partner, will receive no consideration for its removal as general partner.
In addition, the unit purchase agreement provides for the adoption of a second amended and restated agreement ofDelaware limited partnership that will, among other matters:
The recapitalization is subject to certain closing conditions including the approval of our unitholders, approval of the lenders under our revolving credit facility, and the successful completion of the tender offer for our Senior Notes.
As a result of the challenging financial and operating conditions that we have experienced since fiscal 2004, we have not been able to generate sufficient available cash from operations to pay the minimum quarterly distribution of $0.575 per unit on our partnership securities. These conditions led to the suspension of distributions on our senior subordinated units, junior subordinated units and general partner units on July 29, 2004 and to the suspension of distributions on the common units on October 18, 2004.
We believe that the proposed amendments to our partnership agreement will simplify our capital structure, provide internally generated funds for future investment and align the minimum quarterly distribution more closely with the levels of available cash from operations that we expect to generate in the future.
Kestrel is a private equity investment firm formed by Yorktown Energy Partners VI, L.P., Paul A. Vermylen, Jr. and other investors. Yorktown Energy Partners VI, L.P. is a New York-based private equity investment partnership, which makes investments in companies engaged in the energy industry. Yorktown affiliates and Mr. Vermylen were investors in Meenan Oil Co. L.P. from 1983 to 2001, during which time Mr. Vermylen served as President of Meenan. Meenan was sold to us in 2001.
It is possible that the units purchased as part of the recapitalization transaction or units purchased by one or more than one 5% unitholders would trigger an IRC Section 382 limitation relating to certain net operating loss carryforwards. An ownership change occurs for purposes of Section 382 when there is a direct or indirect sale or exchange of more than 50% by one or more than one 5% shareholders. If an ownership change has occurred in accordance with Section 382, future limitations in the utilization of net operating losses could be significant. It is possible that the Partnership’s subsidiary, Star/Petro, Inc., will not be able to use any of its currently existing net income tax loss carryforwards in the future.
Consolidated Financial Statements)
Business Overview
As of September 30, 20052006 we serviced approximately 480,000430,000 home heating oil customers from locations in the Northeast and Mid-Atlantic regions. We believe we are the largest retail distributor of home heating oil in the United States. In addition to selling home heating oil, we install, maintain and repair heating and air conditioning equipment. To a limited extent, we also market other petroleum products including diesel fuel and gasoline to approximately 10,000 commercial customers. During fiscal 2005, the2006, total sales in the heating oil segment were comprised of approximately 75% from sales of home heating oil; 15% from the installation and repair of heating equipment; and 10% 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 heating oil business, and are intended to maximize customer satisfaction and loyalty. We also regularly provide various incentives to obtain and retain customers. We have consolidated our heating oil operations under two primary brand names, Petro and Meenan.
In fiscal 2005,2006, sales to residential customers represented 84%85% of the retail heating oil gallons sold and 92% of heating oil gross profits.
We have operations and markets in the following states:
Massachusetts | New | |||||
|
|
| ||||
| ||||||
Rhode Island | ||||||
Fairfield | Suffolk | Dutchess | Providence | |||
New Haven | Norfolk | Ulster | Kent | |||
Middlesex | Essex | Orange | Washington | |||
Litchfield | Bristol | Westchester | Newport | |||
Hartford | Middlesex | Putnam | Bristol | |||
Barnstable | Nassau | |||||
| ||||||
| ||||||
Suffolk | ||||||
Baltimore | Worcester | Queens | Loudoun | |||
Harford | Kings | Prince William | ||||
Cecil | Richmond | Fauquier | ||||
Anne Arundel | Salem | New York | Stafford | |||
Carroll | Gloucester | Arlington | ||||
Howard | Camden | Fairfax | ||||
Montgomery | Burlington | Philadelphia | ||||
Prince George’s | Ocean | Bucks | Washington, D.C. | |||
Calvert | ||||||
Monmouth | Montgomery | |||||
Charles | Somerset | Chester | ||||
Frederick | Middlesex | Lehigh | ||||
Mercer | Northampton | |||||
Hunterdon | Berks | |||||
Union | Monroe | |||||
Hudson | Dauphin | |||||
Bergen | Cumberland | |||||
Essex | York | |||||
Passaic | ||||||
Sussex | ||||||
Morris | ||||||
Warren |
Industry Characteristics
HeatingHome heating oil is primarily used for residential and commercial heating purposes, and it isas a significant source of fuel used to heat businessesresidences and residencesbusinesses in the New England and Mid-Atlantic regions. According to the U.S. Department of Energy—Energy Information Administration, 2001 Residential Energy Consumption Survey (the latest survey published), these regions account for approximately 77% of the households in the United States where heating oil is the main space-heating fuel. Approximatelyfuel and 31% 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. In addition, weatherWeather conditions have a significant impact on demand for home heating oil as we have seen in fiscal 2006 and fiscal 2002 when temperatures were significantly warmer than normal for the areas in which we sell home heating purposes.
oil.
The retail home heating oil industry is mature, with total market demand expected to decline slightly in the foreseeable future.future due to conversions to natural gas. We have lost an average of 1.0% of our customers per year over the last five years due to conversions to natural gas. Therefore, our ability to grow within the industry is dependent on our ability to acquirethe acquisition of other retail distributors as well as the success of our marketing programs designed to attract and retain customers to help offset customer losses. We believe that the home heating oil industry is relatively stable and predictable due principally to the non-discretionary nature of home heating oil use. Accordingly, the demand for home heating oil has historically been relatively unaffected by general economic conditions but has been affected by weather conditions and most recently a very volatile commodity market. It is common practice in the home heating oil distribution industry to price products to customers based on a per gallon margin over wholesale costs. As a result, we believe distributors such as ourselves generally seek to maintain their margins by passing wholesale price increases through to customers, thus insulating themselves from the volatility in wholesale heating oil prices. However, during periods of significant fluctuationsvolatility in wholesale prices, which currently exists and occurred throughoutover the last three fiscal 2005,years, distributors may be unable or unwilling to pass the entire product cost increases or decreases through to customers. In these cases, significant increases or decreases in per gallon margins may result. In addition, theThe timing of cost pass-throughs can also significantly affect margins. The retail home heating oil industry is highly fragmented, characterized by a large number of relatively small, independently owned and operated local distributors. In addition, theSome dealers provide full service, like ourselves, and others offer delivery only on a cash on delivery basis. The industry is becoming more complex and costly due to increasing environmental regulations.
regulations, working capital requirements and the need to hedge. We purchase derivative instruments (futures, options and swaps) in order to hedge a substantial majority of the heating oil volume we expect to sell to protected-price customers that have renewed their price plans, mitigating our exposure to changing commodity prices.
Business initiativesInitiatives and strategyStrategy
Prior to the fiscal 2004 winter heating season, we attempted to develop a competitive advantage in customer service through a business process redesign project and, as part of that effort, centralized our heating equipment service and oil dispatch functions and engaged a centralized customer care center to fulfill our telephone requirements for a majority of our home heating oil customers. We experienced significant difficulties in advancing this initiative, during fiscal 2004 and 2005, which adversely impacted ourthe customer base and costs. To date, the customers’ experience has been below the level associated with other premium service providers and below the level of service provided by the heating oil segment in prior years which we believe contributed to increased customer attrition in fiscal years 2004, 2005 and 2005 The savings from this initiative were less than expected and the costs to operate under the centralized format were greater than originally estimated.
2006.
We believe we have identified the problems associated with the past centralization efforts and continue to address these issues by structuringissues. Our goal is to reestablish a more traditional customer service model in which the majority of the customer service calls will be handled locally in each district with minimal reliance on a centralized call center into work groups that parallel Petro’s district structure, adding customer service specialists atcenter. We initiated this change with a test in several districts to measure the district level, providing continuous in-house training atimpact on retention of customers as well as to get a better understanding of what our local needs would be. Based on the customer care center, and establishing a general managerresults of customer retention. In addition,these tests, we have begun answeringto move forward more aggressively with our return to a more localized customer calls locally in two districts. We are continuing our initiative of moving toward decentralization of our operations to maximize contact at the local level, while continuing to assess the efficiency of certain centralized operations. The general manager of customer retention reports directly to the President and Chief Operating Officer of the Partnership. Despite these efforts, we continued to experience high net attrition rates in fiscal 2005, and we expect that high net attrition rates may continue through fiscal 2006 and perhaps beyond. Even to the extent that the rate of attrition can be reduced, the current reduced customer base will adversely impact net income in the future.
The quantitative factors we use to measure the effectiveness of our customer care center and field operations – such as customer satisfaction scores, telephone waiting times and abandonment rates at the customer care center, oil delivery run-outs and heating equipment repair and maintenance response times – have improved meaningfully during fiscal 2005, as compared to the same period in fiscal 2004.
We implemented a series of cost reduction initiatives in fiscal 2005 including facility consolidations, the reduction of non-essential personnel and the reduction and re-evaluation of certain marketing programs. We believe this will be an ongoing process as we continue to review our operating expenses. We believe operating expenses were reduced by approximately $10.0 million, on an annualized basis, in 2005. A portion of these expense reductions were realized during fiscal 2005 and the remainder will be realized in fiscal 2006. In addition, a wage freeze has been implemented for senior management in fiscal 2006.
service model.
Going forward, our strategy is to increase unit-holder value through (i) internal growth,reduced net customer attrition, (ii) operational efficiencies and productivity improvements, and (iii) increased market share through strategic and disciplined acquisitionsthe acquisition of localother heating oil distributors or the possible expansion into other energy or petroleum-related businesses.
Customers and (iv) strategic recapitalization of our long-term debt.
We believe opportunities exist to add customers internally in order to help offset customer losses through strategic marketing programs designed to retain existing customers and attract new customers through renewed focus on our sales and marketing efforts, with strong local and regional direction combined with employee incentive programs. We utilize advertising campaigns such as radio advertisements, billboards, newsprint, and telephone directory advertisements to increase brand recognition. We also engage in direct marketing campaigns and advertising on the Internet.
We intend to continue to merge operations and functions where overlaps exist and intend to divest and/or redeploy under-performing operations and assets. In addition, we do not intend to reduce our retail prices to unreasonably low levels to customers, and intend to retain our profit margins in spite of our competitors’ aggressive pricing tactics.
We plan to expand our customer base through strategic and disciplined acquisitions of localOur home heating oil distributors. We intend to focus on acquisitions that can be efficiently operated individually or combined with our existing operations. Under the terms of our revolving credit facility, we were restricted from making any acquisitions prior to June 17, 2005. Thereafter there are limitations on the size of individual acquisitions and an annual limitation on total acquisitions. In addition, there are certain financial tests that must be satisfied before an acquisition can be consummated. We may not be able to satisfy these tests with our current levels of debt and interest expense.
On December 2, 2005 the board of directors of Star Gas approved a strategic recapitalization of the Partnership. The recapitalization includes a commitment Kestrel and its affiliates to purchase $15 million of new equity capital and provide a standby commitment in a $35 million rights offering to our common unitholders, at a price of $2.00 per common unit. The recapitalization is subject to certain closing conditions including the approval of our unitholders, approval of the lenders under our revolving credit facility, and the successful completion of the tender offer for our senior notes. See “Recapitalization.”
We would utilize the $50 million in new equity financing, together with an additional $10 million up to $23.1 million from operations, to repurchase at least $60 million in face amount of our senior notes and at our option, up to $73.1 million of senior notes. In addition, certain noteholders have agreed to convert approximately $26.9 million in face amount of such notes into 13,434,000 newly issued common units.
We believe the proposed recapitalization would substantially strengthen our balance sheet and thereby assist us in meeting our liquidity and capital requirements, which we believe will improve our future financial performance and as a result enhance unitholder value. In addition to enhancing unitholder value, we believe we will be able to operate more efficiently going forward with less long-term debt.
Customers
Our customer base is comprised of three typesresidential customers (95%) and commercial customers (5%). Our residential customer receives small deliveries on average of 170 gallons per delivery and our commercial accounts receive larger deliveries on average of 425 gallons. Typically, we make four to six deliveries per customer per year. Deliveries are scheduled based on each customer’s historical consumption pattern and prevailing weather conditions. Currently, 96% of our deliveries are scheduled automatically and 4 % of our home heating oil customer base call from time to time to schedule a delivery. Our practice is to bill customers promptly after delivery. We also offer a budget 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 and 30% of our residential home heating oil customers have elected this option.
We offer several pricing alternatives to our customers. Our variable residential protectedpricing program allows the price to float with the home heating oil market and commercial/industrial. The residential variable customer generally has the highestmove up or down in response to market changes and other factors. In addition, we
offer price protection programs, which establish a fixed or a maximum per gallon gross profit margin.
During fiscal 2005, approximately 86%price that the customer would pay over the following 12-month period. At September 30, 2006, 41 % of our total home heating oil sales were madecustomer base had a price protection plan as compared to homeowners, with the remainder to industrial, commercial and institutional customers. 38 % at September 30. 2005.
Sales to residential customers ordinarily generate higher margins than sales to other customer groups, such as commercial customers. Due to the greater price sensitivity of residential protected price customers, the per gallon margins realized from these customers generally are less than variable priced residential customers. Commercial/industrial customers are characterized as large volume users and contribute the lowest perPer gallon margin. Grossgross profit margins can also vary by geographic region. Accordingly, per gallon gross profit margins could vary significantly from year to year in a period of identical sales volumes.
For fiscal 2004 and fiscal 2005, approximately 43% and 48%, respectively, of home heating oil sold was to customers who had agreements establishing a fixed or maximum price per gallon that they would pay for home heating oil over the following 12-month period. This percentage could increase or decrease during fiscal 2006 based upon market conditions. The fixed or maximum price per gallon at which home heating oil is sold to these protected price customers is generally renegotiated based on current market conditions before the beginning of each heating season. In addition during the fourth quarter of fiscal 2005, and to date in fiscal 2006 we decided not to reduce our retail prices (including those prices included in our protected price contracts) to customers in order to maintain our product margins in spite of our competitors aggressive pricing tactics. At September 30, 2005, 37.5% of our home heating oil customers had a price protection plan compared to 47.7% at September 30, 2004.
Customers that have not yet renewed their price protected program for the next season could switch to a competitor and customer attrition in the future could increase. We purchase derivative instruments (futures, options, collars and swaps) in order to hedge a substantial majority of the heating oil we expect to sell to protected price customers that have renewed their price plans for the following twelve months, mitigating our exposure to changing commodity prices.
As of September 30, 2005, approximately 93% of our home heating oil customers received their home heating oil under an automatic delivery system without the customer having to make an affirmative purchase decision. These deliveries are scheduled based upon
each customer’s historical consumption patterns and prevailing weather conditions. We deliver home heating oil approximately six times during the year to the average customer. Our practice is to bill customers promptly after delivery. Approximately 36% of our customers are on a budget payment plan, whereby their estimated annual oil purchases and service contract are paid for in a series of equal monthly payments.
Approximately 7% of our home heating oil customers consist of accounts that from time to time call to schedule a delivery rather than receiving a delivery on an automatic basis. These accounts actively manage their consumption and are referred to as “will call” customers. We believe that we have experienced a decline in home heating oil volume sales to these will call customers. This decline may be due to conservation or their decision to purchase all or a portion of their heating oil requirements from another dealer.
We experienced annual net customer attrition of approximately 7.1% in fiscal 2005. The net customer attrition rate in fiscal 2005 was higher than the rate experienced in fiscal 2004 (6.4%), and higher than that experienced in the preceding several years. For fiscal 2003, before the full implementation of the business process redesign project and before the increase in the wholesale price of home heating oil, we experienced annual net customer attrition of 1.5%. Net customer attrition for the fiscal years’ 2005 and 2004 resulted from: (i) a combination of the effect of our premium service/premium price strategy when customer price sensitivity increased due to high energy prices; (ii) our decision in fiscal 2005 to maintain reasonable profit margins going forward in spite of competitors aggressive pricing tactics; (iii) the lag effect of customer attrition related to service and delivery problems experienced by customers in prior fiscal years; (iv) continued customer dissatisfaction with the centralization of customer care; and (v) tightened customer credit standards. For the period from October 1 to November 30, 2004, we gained 530 accounts (net) or 0.1% of our home heating oil customer base as compared to the period from October 1 to November 30, 2005 in which we lost 4,315 accounts (net) or 0.9% of our customer base.
Customer Attrition
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 net customer attrition. For fiscal 2004 and 2005, gross customer losses were approximately 19.5% and 20.0%, respectively, and gross customer gains were approximately 13.1% and 12.9%, respectively. The gain of a new customer does not fully compensate for the loss of an existing customer during the first year because of the expenses that are incurred to acquire a new customer and the higher attrition rate associated with new customers. It costs on average $500 to acquire a new customer.
Gross customer losses are the result of a number of factors, including move-outs, price competition, move outs, service issues and service issues.
credit losses. When a customer moves out of an existing home we count the “move out” as a loss. Ifloss and if we are successful in signing up the new homeowner, the “move in” is treated as a gain.
For fiscal 2004 and 2005, move outs were 6.4% and 6.9%, respectively,2006, we lost 29,600 accounts (net) or 6.6% of our home heating oil customer base, and the move ins were 3.6% and 3.2%, respectively,as compared to fiscal 2005 in which we lost 35,100 accounts (net) or 7.1% of our home heating oil customer base.
In fiscal 2004, we lost 33,100 accounts (net) or 6.4% of our home heating oil customer base. (See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Customer Attrition)
Suppliers and Supply Arrangements
We purchase fuelhome heating oil for delivery in either barge, pipeline or truckload quantities, and have contracts with overapproximately 100 terminals for the right to temporarily store heating oil at facilities we do not own. Purchases are made under supply contracts or on the spot market. We enter into market price based contracts for a substantial majority of our petroleum requirements with eight different suppliers, the majority of which have significant domestic sources for their product, and many of which have been suppliers to thehome heating oil segment for over ten years. Our current contract suppliers are: BP North America, Citgo Petroleum Corporation, Global Companies, Inland Fuels Terminals, Inc., Mieco,requirements. During fiscal 2006, Sunoco Inc., NIC Holding Corp., Sprague Energy and Sunoco, Inc.Global Companies provided 21.4%, 16.8% and 12.3% respectively, of our product purchases. Aside from these three suppliers, no single supplier provided more than 10% of our product supply during fiscal 2006. Supply contracts typically have terms of 6 to 12 months. All of the supply contracts provide for maximum and in certain cases minimum quantities and require advance payment.quantities. In prior years our supply contracts provided us with two-to-three-day credit terms. Since last year our suppliers are now requiring pre-payment. In mostall cases, the supply contracts do not establish in advance the price of fuel oil. This price is based upon spota published market pricesindex price at the time of delivery plus a differential of up to $.045 per gallon.an agreed upon differential. We believe that our policy of contracting for the majority of our anticipated supply needs with diverse and reliable sources will enable us to obtain sufficient product should unforeseen shortages develop in worldwide supplies. We believe that relations with current suppliers are satisfactory.
Derivatives
We purchaseuse derivative instruments including commodity swaps and options, traded on the over-the-counter financial markets, and futures and options traded on the New York Mercantile Exchange in order to mitigate our exposure to market risk and hedge the cash flow variability associated with the purchase of home heating oil inventory held for resale to our protected price customers, and in some cases physical inventory on hand, inventory in transit and in transit.purchase commitments. At September 30, 20052006 we had outstanding derivative instruments with the following banks or brokers: Wachovia Bank, NA, Fimat, BP North America Petroleum, Cargill, LaSalle Bank, NA, Morgan Stanley, JPMorgan Chase Bank, NA, Morgan Stanley Dean Witter, BP NorthSociete Generale, Citibank, N.A., and Bank of America, PetroleumN.A.
SFAS No. 133,Accounting for Derivative Instruments and Fimat.Hedging Activities (“SFAS 133”), established accounting and reporting standards requiring that derivative instruments be recorded at fair value and included in the consolidated balance sheet as assets or liabilities. To the extent derivative instruments designated as cash flow hedges are effective and SFAS 133 documentation requirements are met, changes in fair value are recognized in other comprehensive income until the forecasted hedged item is recognized in earnings. Currently, none of our derivative instruments qualify for hedge accounting treatment because we have not met the documentation requirements of SFAS 133. Therefore, we could experience great volatility in earnings as these currently outstanding derivative instruments are marked to market. While we largely expect our realized derivative gains and losses to be offset by increases or decreases in the value of our physical purchases, we will experience volatility in reported earnings due to the recording of unrealized gains and losses on our derivative instruments that do not qualify for hedge accounting for the periods in which we hold such derivative instruments prior to their maturity. The Partnership is currently evaluating whether to elect hedge accounting for future periods.
Home Heating Oil Price Volatility
The wholesale price of home heating oil has been extremely volatile over the last three fiscal years and has resulted in increased consumer price sensitivity to heating costs and increased net customer attrition. Like any other market commodity, the price of home heating oil is generally set by various economic and geopolitical forces. Rapid global economic expansion is fueling an ever-increasing demand for oil. 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. Crude oil is bought and sold in the international marketplace and as such is significantly affected by the economic forces of worldwide supply and demand. The volatility in home heating oil wholesale cost, as measured by the New York Mercantile Exchange (“Nymex”) for fiscal 2006, 2005 and 2004 by quarter, is illustrated by the following chart:
Fiscal 2006 | Fiscal 2005 | Fiscal 2004 | ||||||||||||||||
Low | High | Low | High | Low | High | |||||||||||||
Quarter Ended | ||||||||||||||||||
December 31 | $ | 1.6097 | $ | 2.0809 | $ | 1.2108 | $ | 1.5944 | $ | 0.7728 | $ | 0.9642 | ||||||
March 31 | 1.6075 | 1.8843 | 1.1922 | 1.6576 | 0.8645 | 1.0384 | ||||||||||||
June 30 | 1.8558 | 2.0964 | 1.3508 | 1.6761 | 0.8472 | 1.0641 | ||||||||||||
September 30 | 1.6472 | 2.1435 | 1.5609 | 2.1985 | 1.0606 | 1.3917 |
In a volatile market even small changes in supply or demand can dramatically affect prices. Heating oil prices are subject to price fluctuations if demand rises sharply because of excessively cold weather and/or disruptions at refineries and instability in key oil producing regions.
Competition
We compete with distributors offering a broad range of services and prices, from full-service distributors, like ourselves, to those offering delivery only. Our competitors typically offer lower prices. Like many companies in the home heating oil business, we provide home heating equipment repair service on a 24-hour-a-day, seven-day-a-week, 52 weeks a year basis. This tends to build customer loyalty. As a result of these factors, it is difficult for us to increase our market share, other than through acquisitions. In some
instances homeowners have formed buying cooperatives that seek to purchase fuel oil from distributors at a price lower than individual customers are otherwise able to obtain. We also compete for retail customers with suppliers of alternative energy products, principally natural gas, propane, and electricity. The rate of conversion from the use of home heating oil to natural gas is primarily affected by the relative retail prices of the two products and the cost of replacing an oil fired heating system with one that uses natural gas, in addition to environmental concerns. We believe that approximately 1% of the home heating oil customer base annually converts from home heating oil to natural gas. The expansion of natural gas into traditional home heating oil markets in the Northeast has historically been inhibited by the capital costs required to expand distribution and pipeline systems.
Most of our retail home heating oil distributionbranch locations compete with several smaller marketers or distributors, primarily on the basis of reliability of service, price, and response to customer needs. Each retail distributionbranch location operates in its own competitive environment because home heating oil distributors and marketers typically reside in close proximity to their customers in order to minimize the cost of providing service.
environment.
Seasonality
Our fiscal year ends on September 30. All references to quarters and years in this document are to fiscal quarters and years unless otherwise noted. The seasonal nature of our business results in the sale of approximately 30% of our volume in the first quarter (October through December) and 45% of our volume in the second quarter (January through March) of each fiscal year, the peak heating season, because heating oil is primarily used for space heating in residential and commercial buildings.season. We generally realize net income in both of thesethe first and second fiscal quarters and net losses during the quarters ending in Junethird and September. In addition, sales volume typically fluctuates from year to year in response to variations in weather, wholesale energy prices and other factors.
fourth fiscal quarter.
Acquisitions
We made no acquisitions in fiscal 2006 and 2005. In fiscal 2004, we completed the purchase of three retail heating oil dealers for an aggregate cost of $3.5 million. We made no acquisitions in fiscal 2005. Under the terms of our revolving credit facility, we were restricted from making any acquisitions prior to June 17, 2005. Thereafter there are limitations on the size of individual acquisitions and an annual limitation on total acquisitions. In addition, thereThere are also certain financial tests that must be satisfied before an acquisition can be consummated. We may not be able to satisfy these tests with our current levels of debt and interest expense.
Employees
As of September 30, 2005,2006, we had 2,7732,610 employees, of whom 638736 were office, clerical and customer service personnel; 1,041935 were heating equipment repairmen; 426365 were oil truck drivers and mechanics; 400385 were management and 268189 were employed in sales. Included in the heating oil segment’sOf these employees are approximately 1,000 employees that1,100 are represented by 1720 different local chapters of labor unions. Some of these unions have union administered pension plans that have significant unfunded liabilities, a portion of which could be assessed to us should we withdraw from these plans. In addition, approximately 485400 seasonal employees are rehired annually to support the requirements of the heating season. We are currently involved in threeone union negotiations andnegotiation. We believe that our relations with both our union and non-union employees are generally satisfactory.
Government Regulations
We are subject to various federal, state and local environmental, health and safety laws and regulations. Generally, these laws impose limitations on the discharge of pollutants and establish standards for the handling of solid and hazardous wastes. These laws include the Resource Conservation and Recovery Act, the Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), the Clean Air Act, the Occupational Safety and Health Act, the Emergency Planning and Community Right to Know Act, the Clean Water Act and comparable state statutes. CERCLA, also known as the “Superfund” law, imposes joint and several liabilities without regard to fault or the legality of the original conduct on certain classes of persons that are considered to have contributed to the release or threatened release of a hazardous substance into the environment. Heating oils and certain automotive waste products generated by the Partnership’s fleet are hazardous substances within the meaning of CERCLA. These laws and regulations could result in civil or criminal penalties in cases of non-compliance or impose liability for remediation costs. The heating oil segmentPartnership is currently a named “potentially responsible party” in one CERCLA civil enforcement action. This action is in its early stages of litigation with preliminary discovery activities taking place. We do not believe that this action will have a material impact on our financial condition or results of operations.
For acquisitions that involve the purchase or leasing of real estate, we conduct a due diligence investigation to attempt to determine whether any hazardous or other regulated substance has been sold from or stored on any of that real estate prior to its purchase. This
due diligence includes questioningWith respect to the seller, obtaining representationstransportation of distillates and warranties concerninggasoline by truck, we are subject to regulations promulgated under the seller’sFederal Motor Carrier Safety Act. These regulations cover the transportation of hazardous materials and are administered by the United States Department of Transportation or similar state agencies. We conduct ongoing training programs to help ensure that our operations are in compliance with environmental laws and performing site assessments. During this due diligenceapplicable safety regulations. We maintain various permits that are necessary to operate some of our employees, and, in certain cases, independent environmental consulting firms review historical records and databases and conduct physical investigationsfacilities, some of the propertywhich may be material to look for evidence of hazardous substances, compliance violations and the existence of underground storage tanks.
Future developments, such as stricter environmental, health or safety laws and regulations thereunder, could affect our operations. To the extent that there are any environmental liabilities unknown to us or environmental, health or safety laws or regulations are made more stringent, there can be no assurance that our results of operations will not be materially and adversely affected.
Trademarks and Service Marks
We market our products and services under various trademarks, which we own. They include marks such as Petro and Meenan. We believe that the Petro, Meenan and other trademarks and service marks are an important part of our ability to attract new customers and to effectively maintain and service our customer base.
ITEM 1A. | RISK FACTORS |
An investment in the Partnership involves a high degree of risk. Security holders and Investors should carefully review the following risk factors.
Unitholders May Have to Report Income for Federal Income Tax Purposes on Their Investment in the Partnership Without Receiving Any Cash Distributions From Us.
Star Gas Partners is a master limited partnership and thus not subject to federal income taxes. Instead, 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. We expect that an investor will be allocated taxable income (mostly dividend and interest income) regardless of whether a cash distribution has been paid. There will be no mandatory distributions of available cash by us to unitholders through the fiscal quarter ending September 30, 2008.
Our corporate subsidiary Star/Petro Inc. and its subsidiaries (“Star/Petro”) are subject to federal and state income taxes. See the following risk factor regarding net operating loss availability.
A change in ownership for Star Gas Partners may result in the limitation of the potential utilization of net operating loss carryforwards by our corporate subsidiary and our ability to pay cash distributions.
If Star Gas Partners were to experience an “ownership change” under Section 382 of the Internal Revenue Code of 1986, as amended, its corporate subsidiary, Star/Petro may be materially restricted in the potential utilization of its net operating loss carryforwards to offset future taxable income. A restriction on Star/Petro’s ability to use its net operating loss carryforwards to reduce its federal taxable income would reduce the amount of cash Star/Petro has available to make distributions to the Partnership, which would consequently reduce the amount of cash the Partnership has available to make distributions to its unitholders. As of September 30, 2006 Star/Petro had a total federal net operating loss carryforward of $162.7 million, of which approximately $47.9 million were limited as a result of prior transactions.
The continuation of high wholesale energy costs may adversely affect our liquidity.
Recent dynamics of the heating oil industry have increased working capital requirements, principally because high selling prices require additional borrowing to finance accounts receivable and inventory. Under our revolving credit facility, as amended, we may borrow up to $260 million, which increases to $310 million during the peak winter months from December through March of each year, (subject to borrowing base limitations and a coverage ratio) for working capital purposes subject to maintaining availability (as defined in the credit agreement) of $25 million or a fixed charge coverage ratio of not less than 1.1 to 1.0.
Recent dynamics of the heating oil industry have adversely impacted working capital requirements, principally as follows:
If our credit requirements should exceed the amounts available under our revolving credit facility or should we fail to maintain the required availability, 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.
Our substantial debt and other financial obligations could impair our financial condition and our ability to fulfill our debt obligations.
We had total debt, exclusive of our working capital facility, of approximately $268.2$174 million as of September 30, 2005.2006. Our substantial indebtedness and other financial obligations could:
If we are unable to meet our debt service obligations and other financial obligations, we could be forced to restructure or refinance our indebtedness and other financial transactions, seek additional equity capital or sell our assets. We maymight then be unable to obtain such financing or capital or sell our assets on satisfactory terms, if at all.
If our use of the net proceeds from the sale of the propane segment does not comply with the terms of the Indenture for the MLP Notes, we may be subject to liability to the note holders, which could have a material adverse effect on us.
In December 2004, we completed the sale of our propane segment. Pursuant to the terms of the indenture relating to the MLP Notes, we are permitted, within 360 days of the sale, to apply the Net Proceeds to a Permitted Use. To the extent there are any Excess Proceeds, the indenture requires us to make an offer to all holders of MLP Notes to purchase for cash that number of MLP Notes that may be purchased with Excess Proceeds at a purchase price equal to 100% of the principal amount of the MLP Notes plus accrued and unpaid interest to the date of purchase.
After payment of certain debt and transaction expenses, the Net Proceeds from the propane segment sale were approximately $156.3 million. As of September 30, 2005, we had utilized $53.1 million of such Net Proceeds to invest in working capital assets, purchase capital assets and repay long-term debt, which reduced the amount of Net Proceeds in excess of $10 million not applied toward a Permitted Use to $93.2 million as of September 30, 2005. As of December 2, 2005, all Excess Proceeds have been applied toward a Permitted Use. See “Recapitalization.”
We understand, based on informal communications, that certain holders of MLP Notes may take the position that the use of Net Proceeds to invest in working capital assets is not a Permitted Use under the indenture. We disagree with this position and have communicated our disagreement with these noteholders. However, if our position is challenged and we are unsuccessful in defending our position, this would constitute an event of default under the indenture if declared either by the holders of 25% in principal amount of the MLP Notes or by the trustee. In such event, all amounts due under the senior notes would become immediately due and payable, which would have a material adverse effect on our ability to continue as a going concern. The report of our independent registered public accounting firm on our consolidated financial statements as of September 30, 2005 and 2004, and for the three years ended September 30, 2005, includes an explanatory paragraph with respect to the impact of this matter on our ability to continue as a going concern if this matter is resolved adversely to us. We have reached an agreement with the holders of 94% in aggregate principal amount of the senior notes to resolve this matter, which is subject to our completing the proposed recapitalization, of which there can be no assurance.
Since weather conditions may adversely affect the demand for home heating oil, our financial condition is vulnerable to warm winters.
Weather conditions have a significant impact on the demand for home heating oil because our customers depend on this product principally for space heating purposes. As a result, weather conditions may materially adversely impact our operating results and financial condition. During the peak heatingpeak-heating season of October through March, sales of home heating oil historically have represented approximately 75% to 80% of our annual home heating oil volume. Actual weather conditions can vary substantially from year to year, significantly affecting our financial performance. Furthermore, warmer than normal temperatures in one or more regions in which we operate can significantly decrease the total volume we sell and the gross profit realized on those sales and, consequently, our results of operations. For example, in fiscal 20002002 and especially fiscal 2002,2006, temperatures were significantly warmer than normal for the areas in which we sell home heating oil, which adversely affected the amount of net income and EBITDA that we generated during these periods. In fiscal 2002, temperatures in our areas of operation were an average of 18.4% warmer than in fiscal 2001 and 18.0% warmer than normal. We purchaseIn fiscal 2006, temperatures in our areas of operation were an average of 11.0% warmer than in fiscal 2005 and 10.4% warmer than normal. For fiscal 2007, we have purchased $12.5 million in weather insurance to help minimize the adverse effect of weather volatility on our cash flows, of whichflows. The policy covers the period from November 1, 2006 to February 28, 2007 taken as a whole. However, there can be no assurance.
assurance that this insurance will be adequate to protect us from adverse effects of weather conditions.
Our operating results will be adversely affected if we continue to experience significant net attrition in our home heating oil customer losses that are not offset or reduced by customer gains.base.
Our net attrition rate of home heating oil customers for fiscal 2003,2006, 2005 and 2004 and 2005 was approximately 1.5%6.6%, 6.4%7.1% and 7.1%6.4%, respectively. This rate represents the net of our annual gross customer loss ratelosses after gross customer gains. For fiscal 2003,2006, 2005 and 2004 and 2005,we had gross customer losses of 19.6%, 20% and 19.5%, respectively, which were 16.4%, 19.5% and 20%, respectively. For fiscal 2003, 2004 and 2005,partially offset by gross customer gains were 14.9%during these periods of 13%, 13.1%12.9% and 12.9%13.1%, respectively. The gain of a new customer does not fully compensate for the loss of an existing customer during the first year because of the expenses incurred during the first year to acquire a new customer and the higher attrition rate associated with new customers. Customer losses are the result of various factors, including:including but not limited to:
The continuing unprecedented rise and volatility in the price of heating oil has intensified price competition which has adversely impacted our margins and added to our difficulty in reducing net customer attrition. We believe our attrition rate has risen not only because of increased price competition related to the rise in oil prices but also because of operational problems. Prior to the 2004 winter heating season, we attempted to develop a competitive advantage in
High net customer service and, as part of that effort, centralized a majority of our heating equipment service dispatch and engaged a centralized call center to fulfill telephone requirements for a majority of our home heating oil customers. We experienced difficulties in advancing this initiative during fiscal 2004, which adversely impacted our customer base and costs. In fiscal 2004 and 2005, the customer experience was below the level associated with other premium service providers and below the level of service provided by us in prior years.
We believe that we have identified the problems associated with the centralization efforts and are taking steps to address these issues. We expect that high net attrition rates may continue through fiscal 20062007 and perhaps beyond and even to the extent the rate of attrition can be halted, attrition from prior fiscal years will adversely impact net income in the future.
We believe that this increase in netFor additional information about customer attrition, over the past two years can be attributed to: (i) a combinationSee Item 7 “Management’s Discussion and Analysis of the affectFinancial Condition and Results of our premium service/premium price strategy when customer price sensitivity increased due to high energy prices; (ii) our decision in fiscal 2005 to maintain reasonable profit margins going forward in spite of competitors’ aggressive pricing tactics; (iii) the lag effect of customer attrition related to service and delivery problems experienced by customers in prior fiscal years; (iv) continued customer dissatisfaction with the centralization of customer care; and (v) tightened customer credit standards.Operations – Customer Attrition.”
We have continued to experience net customer attrition during fiscal 2006. If wholesale prices remain high, we believe the risk of customer losses due to credit problems, especially for commercial customers, may increase and bad debt expense will also increase.
We may not be able to achieve net gains of customers and may continue to experience net customer attrition in the future.
Sudden and sharp oil price increases that cannot be passed on to customers may adversely affect our operating results.
The retail home heating oil industry is a “margin-based” business in which gross profit depends on the excess of retail sales prices over supply costs. Consequently, our profitability is sensitive to changes in the wholesale price of home heating oil caused by changes in supply or other market conditions. These factors are beyond our control and thus, when there are sudden and sharp increases in the wholesale cost of home heating oil, we may not be able to pass on these increases to customers through increased retail sales prices. As of September 30, 2005, the wholesale cost of home heating oil, as measured by the closing price on the New York Mercantile Exchange, had increased by 48% to $2.06 per gallon from $1.39 per gallon as of September 30, 2004. During fiscal 2005, per gallon home heating oil prices peaked at $2.18 on September 1, 2005. Wholesale price increases could reduce our gross profits and could, if continuing over an extended period of time reduce demand by encouraging conservation or conversion to alternative energy sources. In an effort to retain existing accounts and attract new customers, we may offer discounts, which will impact the net per gallon gross margin realized.
A significant portion of our home heating oil volume is sold to price-protected customers and our gross margins could be adversely affected if we are not able to effectively hedge against fluctuations in the volume and cost of product sold to these customers.
A significant portion of our home heating oil volume is sold to individual customers under an agreement pre-establishing the maximum sales price or a fixed price of home heating oil over a 12-month period. For the fiscal yearyears ended September 30, 2006 and 2005, approximately 38% and 48%, respectively, of our retailthe total home heating oil volume sales weresold was under a price protectedprice-protected plan. The price at which home heating oil is sold to these price protected customers is generally renegotiated prior to the heating season of each year based on current market conditions. We currently purchase futures contracts, swaps and option contracts for a substantial majority of the heating oil that we expect to sell to these price-protected customers that have agreements in place in advance and at a fixed or maximum cost per gallon. We purchase these positions when a price protectedthe customer renews his purchase commitment for the next 12 months. We utilize various hedging strategies in order to “lock in”generally get a signed agreement or a voice recording from these price-protected customers acknowledging the fixed or maximum price per gallon margin for price protected customers.gallon. The amount of home heating oil volume that we hedge per price protectedprice-protected customer is based upon the estimated fuel consumption per customer, per month. In the event that the actual usage exceeds the amount of the hedged volume on a monthly basis, we could be required to obtain additional volume at unfavorable margins. In addition, should actual usage be less than the hedged volume we may have excess inventory on hand at unfavorable costs. Currently, none of our derivative instruments qualify for hedge accounting treatment. Therefore, to the extent we continue to have derivative instruments that do not qualify for hedge accounting treatment, we could experience great volatility in earnings as these currently outstanding derivative contracts are marked to market. The Partnership is currently evaluating whether to elect hedge accounting for future periods.
If we do not make acquisitions on economically acceptable terms, our future financial performancegrowth will be limited.
The home heating oil industry is not a growth industry because new housing generally does not use oil heat and increased competition exists from alternative energy sources. A significant portion of our growth in the past decade has been directly tied to our acquisition program. Accordingly, future financial performancegrowth will depend on our ability to make acquisitions at attractive prices. We cannot assure that we will be able to identify attractive acquisition candidates in the home heating oil sector in the future or that we will be able to acquire businesses on economically acceptable terms. Factors that may adversely affect home heating oil operating and financial results may limit our access to capital and adversely affect our ability to make acquisitions. Under the terms of our revolving credit facility, the heating oil segment waswe are restricted from making any acquisitions through June 17, 2005individual acquisition in excess of $10.0 million and thereafter individual acquisitionsin any fiscal year may not exceed an aggregate of $25 million.million, unless waived. In addition, the heating oil segmentPartnership is restricted from making any acquisition unless availability (essentially borrowing base availability less borrowings) waswould be at least $40 million, on a pro forma basis, during the last 12 month12-month period ending on the date of such acquisition. These restrictions severelymay limit our ability to make acquisitions. Any acquisition may involve potential risks to us and ultimately to our unitholders, including:
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.
Because of the highly competitive nature of the retail home heating oil industry, we may not be able to retain existing customers or acquire new customers, which would have an adverse impact on our operating results and financial condition.
If theour home heating oil business is unable to compete effectively, we may lose existing customers or fail to acquire new customers, which would have a material adverse effect on our results of operations and financial condition.
We compete with heating oil distributors offering a broad range of services and prices, from full service distributors, like us, to those offering delivery only. Competition with other companies in the home heating oil industry is based primarily on customer service and price. It is customary for companies to deliver home heating oil to their customers based upon weather conditions and historical consumption patterns, without the customer making an affirmative purchase decision. Most companies provide home heating equipment repair service on a 24-hour-per-day basis. In some cases, homeowners have formed buying cooperatives to purchase fuel oil from distributors at a price lower than individual customers are otherwise able to obtain. As a result of these factors, it may be difficult to acquire new customers.
We can make no assurances that we will be able to compete successfully. If competitors continue to increase market share by reducing their prices, as we believe occurred recently, our operating results and financial condition could be materially and adversely affected. We also compete for customers with suppliers of alternative energy products, principally natural gas. Competition from alternative energy sources has been increasing as a result of reduced regulation of many utilities, including natural gas and electricity, and the high price of oil. We could face additional price competition from electricity and natural gas as a result of deregulation in those industries.gas. Over the past five years, customer conversions by the heating oil segment’s customers from heating oil to natural gas have averaged approximately 1% per year.
The continuing unprecedented rise in the price of heating oil has intensified price competition, which has adversely impacted our product margins and added to our difficulty in reducing customer attrition. We believe our attrition rate has risen not only because of increasedas consumers become more price competition related to the rise in oil prices, but also because of operational problems. Prior to the 2004 winter heating season, we attempted to develop a competitive advantage in customer service and, as part of that effort, centralized a majority of our heating equipment service dispatch and engaged a centralized call center to fulfill telephone requirements for the majority of our home heating oil customers. We experienced difficulties in advancing this initiative during fiscal 2004 and 2005, which adversely impacted our customer base and costs. In fiscal 2004 and 2005 the customer experience was below the level associated with other premium service providers and below the level of service provided by us in prior years.sensitive.
We believe that we have identified the problems associated with these centralization efforts and are taking steps to address these issues We expect that high net attrition rates may continue through fiscal 2006 and perhaps beyond and even to the extent that the rate of attrition can be halted, attrition in prior fiscal years will adversely impact net income in the future.
Energy efficiency and new technology may reduce the demand for our products and adversely affect our operating results.
Increased conservation and technological advances, including installation of improved insulation and the development of more efficient furnaces and other heating devices, have adversely affected the demand for our products by retail customers. Future conservation measures or technological advances in heating, conservation, energy generation or other devices might reduce demand and adversely affect our operating results.
We are subject to operating and litigation risks that could adversely affect our operating results whether or not covered by insurance.
Our operations are subject to all operating hazards and risks normally incidental to handling, storing, transporting and otherwise providing customers with home heating oil. As a result, we may be a defendant in legal proceedings and litigation arising in the ordinary course of business.
We maintain insurance policies with insurers in amounts and with coverage and deductibles as we believe are reasonable. However, there can be no assurance that this insurance will be adequate to protect us from all material expenses related to potential future claims for remediation costs and personal and property damage or that these levels of insurance will be available in the future at economical prices.
Our insurance reserves may not be adequate to cover actual losses.
We self-insure a portion of workers’ compensation, automobile and general liability claims. We establish reserves based upon expectations as to what our ultimate liability will be for these claims using our historical developmental factors based upon historical claim experience.factors. We periodically evaluate on an annual basis the potential for changes in loss estimates with the support of qualified actuaries. As of September 30, 2005,2006, we had approximately $33.8$38.8 million of insurance reserves and had issued $43.8$47.8 million in letters of credit for current and future claims. The ultimate settlement of these claims could differ materially from the assumptions used to calculate the reserves, which could have a material effect on our results of operations.
We are the subject of a number of class action lawsuits alleging violation of the federal securities laws, which if decided adversely, could have a material adverse effect on our financial condition.
On or about October 21, 2004, a purported class action lawsuit on behalf of a purported class of unitholders was filed against the Partnership and various subsidiaries and officers and directors in the United States District Court of the District of Connecticut entitledCarter v. Star Gas Partners, L.P., et al,et.al.,No. 3:04-cv-01766-IBA, et al.et.al. Subsequently, 16 additional class action complaints, alleging the same or substantially similar claims, were filed in the same district court: (1) Feit v. Star Gas, et al. Civil Action No. 04-1832 (filed on 10/29/2004), (2) Lila Gold vs. Star Gas, et al, Civil Action No. 04-1791 (filed on 10/22/2004), (3) Jagerman v. Star Gas, et al, Civil Action No. 04-1855 (filed on 11/3/2004), (4) McCole, et al v. Star Gas, et al, Civil Action No. 04-1859 (filed on 11/3/2004), (5) Prokop vs. Star Gas, et al, Civil Action No. 04-1785 (filed on 10/22/2004), (6) Seigle v. Star Gas, et al, Civil Action No. 04-1803 (filed on 10/25/2004), (7) Strunk v. Star Gas, et al, Civil Action No. 04-1815 (filed on 10/27/2004), (8) Harriette S. & Charles L. Tabas Foundation vs. Star Gas, et al, Civil Action No. 04-1857 (filed on 11/3/2004), (9) Weiss v. Star Gas, et al, Civil Action No. 04-1807 (filed on 10/26/2004), (10) White v. Star Gas, et al, Civil Action No. 04-1837 (filed on 10/9/2004), (11) Wood vs. Star Gas et al, Civil Action No. 04-1856 (filed on 11/3/2004), (12) Yopp vs. Star Gas, et al, Civil Action No. 04-1865 (filed on 11/3/2004), (13) Kiser v. Star Gas, et al, Civil Action No. 04-1884 (filed on 11/9/2004), (14) Lederman v. Star Gas, et al, Civil Action No. 04-1873 (filed on 11/5/2004), (15) Dinkes v. Star Gas, et al, Civil Action No. 04-1979 (filed 11/22/2004) and (16) Gould v. Star Gas, et al, Civil Action No. 04-2133 (filed on 12/17/2004) (including the Carter Complaint, collectively referred to herein as the “Class Action Complaints”).court. The class actions have beenwere consolidated into one action entitled In re Star Gas Securities Litigation, No 3:04cv1766 (JBA).
The class action plaintiffs generally allege that the Partnership violated Sections 10(b) and 20(a) of the Securities Exchange Act of 1934, as amended, and Rule 10-b5 promulgated thereunder, by purportedly failing to disclose, among other things: (1) problems with the restructuring of Star Gas’s dispatch system and customer attrition related thereto; (2) that Star Gas’ heating oil segment’s business process improvement program was not generating the benefits allegedly claimed; (3) that Star Gas was struggling to maintain its profit margins in its heating oil segment; (4) that Star Gas’s fiscal 2004 second quarter profit margins were not representative of its ability to pass on heating oil price increases; and (5) that Star Gas was facing an inability to pay its debts and that, as a result, its credit rating and ability to obtain future financing was in jeopardy. The class action plaintiffs seek an unspecified amount of compensatory damages including interest against the defendants jointly and severally and an award of reasonable costs and expenses. On February 23, 2005, the Court consolidated the Class Action Complaints and heard argument on motions for the appointment of lead plaintiff. On April 8, 2005, the Court appointed the lead plaintiff. Pursuant to the Court’s order, the lead plaintiff filed a consolidated amended complaint on June 20, 2005 (the “Consolidated Amended Complaint”). The Consolidated Amended Complaint named: (a) Star Gas Partners, L.P.; (b) Star Gas LLC; (c) Irik Sevin; (d) Audrey Sevin; (e) Hanseatic Americas, Inc.; (f) Paul Biddelman; (g) Ami Trauber; (h) A.G. Edwards & Sons Inc.; (i) UBS Investment Bank; and (j) RBC Dain Rauscher Inc. as defendants. The Consolidated Amended Complaint added claims arising out of two registration statements and the same transactions under Sections
11, 12(a)(2) and 15 of the Securities Act of 1933 as well as certain allegations concerning the Partnership’s hedging practices. On September 23, 2005, defendants filed motions to dismiss the Consolidated Amended Complaintconsolidated amended complaint for failure to state a claim under the federal securities laws and failure to satisfy the applicable pleading requirements of the Private Securities Litigation Reform Act of 1995 (“PSLRA”), and the Federal Rules of Civil Procedure. Plaintiffs filed their response toOn August 21, 2006, the court issued its rulings on defendants’ motions to dismiss, granting the motions and dismissing the consolidated amended complaint in its
entirety. On August 23, 2006, the court entered a judgment of dismissal. On September 7, 2006, the plaintiffs moved for reconsideration and to alter and reopen the court’s August 23, 2006 judgment of dismissal and for leave to file a second consolidated amended complaint. On October 20, 2006, defendants filed their memorandum of law in opposition to the plaintiffs’ motion. Plaintiffs filed their reply brief on or about November 23, 2005 and defendants are scheduled to file their reply briefs on or about December 20, 2005.2006. The matter is now under consideration by the court. In the interim, discovery in the matter remains stayed pursuant to the mandatory stay provisions of the PSLRA. While no prediction may be made as to the outcome of litigation, we intend to defend against this class action vigorously.
In the event that the above action is decided adversely to us, it could have a material adverse effect on our results of operations, financial condition and liquidity
liquidity.
Our results of operations and financial condition may be adversely affected by governmental regulation and associated environmental and regulatory costs.
The home heating oil business is subject to a wide range of federal and state laws and regulations related to environmental and other regulated matters. We have implemented environmental programs and policies designed to avoid potential liability and costs under applicable environmental laws. It is possible, however, that we will experience increased costs due to stricter pollution control requirements or liabilities resulting from noncompliance with operating or other regulatory permits. New environmental regulations might adversely impact operations, including underground storage and transportation of home heating oil. In addition, there are environmental risks inherently associated with home heating oil operations, such as the risks of accidental release or spill. It is possible that material costs and liabilities will be incurred, including those relating to claims for damages to property and persons. Before August 2006, we must implement certain changes to ensure compliance with amended Environmental Protection Agency regulations. We currently estimate that the capital required to effectuate these requirements will range from $1.0 to $1.5 million.
In our acquisition of Meenan, we assumed all of Meenan’s environmental liabilities.
In our acquisition of Meenan Oil Company, or “Meenan,” in August 2001, we assumed all of Meenan’s environmental liabilities, including those related to the cleanup of contaminated properties, in consideration of a reduction of the purchase price of $2.7 million. Subsequent to closing, we established an additional reserve of $2.3 million to cover potential costs associated with remediating known environmental liabilities, bringing the total reserve to $5.0 million. To date, remediation expenses against this reserve have totaled $3.1 million. While we believe this reserve is adequate, it is possible that the extent of the contamination at issue or the expense of addressing it could exceed our estimates and thus the costs of remediating these known liabilities could materially exceed the amount reserved.
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 the Partnership and its limited partners, on the other hand.
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 the Partnership or any of the limited partners, on the other hand. As a result of these conflicts the general partner may favor its own interests and those of its affiliates over the interests of the unitholders. The nature of these conflicts is ongoing and includes the following considerations:
The risk of global terrorism and political unrest may adversely affect the economy and the price and availability of home heating oil and have a material adverse effect on our business, financial condition, and results of operations.
Terrorist attacks such as the attacks that occurred in New York, Pennsylvania and Washington, D.C. on September 11, 2001, and political unrest in the Middle East may adversely impact the price and availability of home heating oil, our results of operations, our
ability to raise capital and our future growth. The impact that the foregoing may have on the heating oil industry in general, and on our business in particular, is not known at this time. An act of terror could result in disruptions of crude oil supplies and markets, the source of home heating oil, and its facilities could be direct or indirect targets. Terrorist activity may also hinder our ability to transport home heating oil if our normal means of transportation become damaged as a result of an attack. Instability in the financial markets as a result of terrorism could also affect our ability to raise capital. Terrorist activity could likely lead to increased volatility in prices for home heating oil. Insurance carriers are routinely excluding coverage for terrorist activities from their normal policies, but are required to offer such coverage as a result of new federal legislation. We have opted to purchase this coverage with respect to our property and casualty insurance programs. This additional coverage has resulted in additional insurance premiums.
The impact of hurricanes and other natural disasters could cause disruptions in supply and have a material adverse effect on our business, financial condition and results of operations.
Hurricanes, particularly in the Gulf of Mexico, and other natural disasters may cause disruptions in the supply chains for home heating oil and other petroleum products. Disruptions in supply could have a material adverse effect on our business, financial condition and results of operations, causing an increase in wholesale prices and decrease in supply.
Cash distributions (if any) are not guaranteed and may fluctuate with performance and reserve requirements.
BecauseThere will be no mandatory distributions of available cash by us through the fiscal quarter ending September 30, 2008. Thereafter, distributions on the common and subordinated units are dependentwill depend on the amount of cash generated, and distributions may fluctuate based on our performance. The actual amount of cash that is available will depend upon numerous factors, including:
Most of these factors are beyond the control of the general partner.
The partnership agreement gives the general partner discretion in establishing reserves for the proper conduct of our business. These reserves will also affect the amount of cash available for distribution. The general partner may establish reserves for distributions on the senior subordinated units only if those reserves will not prevent the Partnership from distributing the full minimum quarterly distribution, plus any arrearages, on the common units for the following four quarters.
On October 18, 2004, we announced that we would not pay a distribution on the common units as a result of the requirements of our bank lenders. We had previously announced the suspension of distributions on the senior subordinated units on July 29, 2004. The revolving credit facility and the indenture for the MLP Notessenior notes both impose certain restrictions on our ability to pay distributions to unitholders. It is unlikely that regular distributions on the common units or senior subordinated units will be resumed in the foreseeable future. See “Recapitalization.”
ITEM 1B. | UNRESOLVED STAFF COMMENTS |
ITEM 1B. UNRESOLVED STAFF COMMENTSNot applicable.
Not applicable.
ITEM 2. | PROPERTIES |
We provide services to our customers from 19 principle operating locations and 4746 depots, 2928 of which are owned and 37 of which are leased, in 3231 marketing areas in the Northeast and Mid-Atlantic regions of the United States. As of September 30, 2005,2006, we had a fleet of 1,049918 truck and transport vehicles, the majority of which were owned and 1,245 services1,177 service vans, the majority of which are leased. We lease our corporate headquarters in Stamford, Connecticut. Our obligations under our credit facility are secured by liens and mortgages on substantially all of the Partnership’s and subsidiaries real and personal property.
ITEM 3. LEGAL PROCEEDINGS – LITIGATION
ITEM 3. | LEGAL PROCEEDINGS—LITIGATION |
On or about October 21, 2004, a purported class action lawsuit on behalf of a purported class of unitholders was filed against the Partnership and various subsidiaries and officers and directors in the United States District Court of the District of Connecticut entitledCarter v. Star Gas Partners, L.P., et al,et. al.,No. 3:04-cv-01766-IBA, et.al.et. al. Subsequently, 16 additional class action complaints, alleging the same or substantially similar claims, were filed in the same district court: (1) Feit v. Star Gas, et al. Civil Action No. 04-1832 (filed on 10/29/2004), (2) Lila Gold vs. Star Gas, et al, Civil Action No. 04-1791 (filed on 10/22/2004), (3) Jagerman v. Star Gas, et al, Civil Action No. 04-1855 (filed on 11/3/2004), (4) McCole, et al v. Star Gas, et al, Civil Action No. 04-1859 (filed on 11/3/2004), (5) Prokop vs. Star Gas, et al, Civil Action No. 04-1785 (filed on 10/22/2004), (6) Seigle v. Star Gas, et al, Civil Action No. 04-1803 (filed on 10/25/2004), (7) Strunk v. Star Gas, et al, Civil Action No. 04-1815 (filed on 10/27/2004), (8) Harriette S. & Charles L. Tabas Foundation vs. Star Gas, et al, Civil Action No. 04-1857 (filed on 11/3/2004), (9) Weiss v. Star Gas, et al, Civil Action No. 04-1807 (filed on 10/26/2004), (10) White v. Star Gas, et al, Civil Action No. 04-1837 (filed on 10/9/2004), (11) Wood vs. Star Gas et al, Civil Action No. 04-1856 (filed on 11/3/2004), (12) Yopp vs. Star Gas, et al, Civil Action No. 04-1865 (filed on 11/3/2004), (13) Kiser v. Star Gas, et al, Civil Action No. 04-1884 (filed on 11/9/2004), (14) Lederman v. Star Gas, et al, Civil Action No. 04-1873 (filed on 11/5/2004), (15) Dinkes v. Star Gas, et al, Civil Action No. 04-1979 (filed 11/22/2004) and (16) Gould v. Star Gas, et al, Civil Action No. 04-2133 (filed on 12/17/2004) (including the Carter Complaint, collectively referred to herein as the “Class Action Complaints”).court. The class actions have beenwere consolidated into one action entitled In re Star Gas Securities Litigation, No 3:04cv1766 (JBA).
The class action plaintiffs generally allege that the Partnership violated Sections 10(b) and 20(a) of the Securities Exchange Act of 1934, as amended, and Rule 10-b5 promulgated thereunder, by purportedly failing to disclose, among other things: (1) problems with the restructuring of Star Gas’s dispatch system and customer attrition related thereto; (2) that Star Gas’s heating oil segment’s business process improvement program was not generating the benefits allegedly claimed; (3) that Star Gas was struggling to maintain its profit margins in its heating oil segment; (4) that Star Gas’s fiscal 2004 second quarter profit margins were not representative of its ability to pass on heating oil price increases; and (5) that Star Gas was facing an inability to pay its debts and that, as a result, its credit rating and ability to obtain future financing was in jeopardy. The class action plaintiffs seek an unspecified amount of compensatory damages including interest against the defendants jointly and severally and an award of reasonable costs and expenses. On February 23, 2005, the Court consolidated the Class Action Complaints and heard argument on motions for the appointment of lead plaintiff. On April 8, 2005, the Court appointed the lead plaintiff. Pursuant to the Court’s order, the lead plaintiff filed a consolidated amended complaint on June 20, 2005 (the “Consolidated Amended Complaint”). The Consolidated Amended Complaint named: (a) Star Gas Partners, L.P.; (b) Star Gas LLC; (c) Irik Sevin; (d) Audrey Sevin; (e) Hanseatic Americas, Inc.; (f) Paul Biddelman; (g) Ami Trauber; (h) A.G. Edwards & Sons Inc.; (i) UBS Investment Bank; and (j) RBC Dain Rauscher Inc. as defendants. The Consolidated Amended Complaint added claims arising out of two registration statements and the same transactions under Sections 11, 12(a)(2) and 15 of the Securities Act of 1933 as well as certain allegations concerning the Partnership’s hedging practices. complaint.
On September 23, 2005, defendants filed motions to dismiss the Consolidated Amended Complaintconsolidated amended complaint for failure to state a claim under the federal securities laws and failure to satisfy the applicable pleading requirements of the Private Securities Litigation Reform Act of 1995 (“PSLRA”), and the Federal Rules of Civil Procedure. Plaintiffs filed their response toOn August 21, 2006, the court issued its rulings on defendants’ motions to dismiss, granting the motions and dismissing the consolidated amended complaint in its entirety. On August 23, 2006, the court entered a judgment of dismissal. On September 7, 2006, the plaintiffs moved for reconsideration and to alter and reopen the court’s August 23, 2006 judgment of dismissal and for leave to file a second consolidated amended complaint. On October 20, 2006, defendants filed their memorandum of law in opposition to the plaintiffs’ motion. Plaintiffs filed their reply brief on or about November 23, 2005 and defendants are scheduled to file their reply briefs on or about December 20, 2005.2006. The matter is now under consideration by the Court. In the interim, discovery in the matter remains stayed pursuant to the mandatory stay provisions of the PSLRA. While no prediction may be made as to the outcome of litigation, we intend to defend against this class action vigorously.
In the event that the above action is decided adversely to us, it could have a material effect on our results of operations, financial condition and liquidity.
(See Note 22)
Our operations are subject to all operating hazards and risks normally incidental to handling, storing and transporting and otherwise providing for use by consumers of combustible liquids such as propane and home heating oil.
As a result, at any given time we are a defendant in various legal proceedings and litigation arising in the ordinary course of business. We maintain insurance policies with insurers in amounts and with coverages and deductibles we believe are reasonable and prudent. However, we cannot assure that this insurance will be adequate to protect us from all material expenses related to potential future claims for personal and property damage or that these levels of insurance will be available in the future at economical prices. In addition, the occurrence of an explosion may have an adverse effect on the public’s desire to use our products. In the opinion of management, except as described above 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. (See Note 22 – Commitments and Contingencies)
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
ITEM 4. | SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS |
None.
ITEM 5. MARKET FOR REGISTRANT’S UNITS AND RELATED MATTERS
ITEM 5. | MARKET FOR REGISTRANT’S UNITS AND RELATED MATTERS |
The common units, representing common limited partner interests in the Partnership, are listed and traded on the New York Stock Exchange, Inc. (“NYSE”) under the symbol “SGU”. The common units began trading on the NYSE on May 29, 1998. Previously, the common units had traded on the NASDAQ National Market under the symbol “SGASZ.”
The Partnership’s senior subordinated units began trading on the NYSE on March 29, 1999 under the symbol “SGH.” The senior subordinated units became eligible to receive distributions in February 2000, and the first distribution was made in August 2000. The following tables set forth the high and low closing price ranges for the common and senior subordinated units and the cash distribution declared on each unit for the fiscal 20042006 and 2005 quarters indicated. There were no cash distributions declared on the common units during these periods.
SGU - Common Unit Price Range | Distributions Declared per Unit | |||||||||||||||||
High | Low | |||||||||||||||||
Fiscal Year 2004 | Fiscal Year 2005 | Fiscal Year 2004 | Fiscal Year 2005 | Fiscal Year 2004 | Fiscal Year 2005 | |||||||||||||
Quarter Ended | ||||||||||||||||||
December 31, | $ | 24.93 | $ | 22.23 | $ | 21.79 | $ | 4.32 | $ | 0.575 | $ | — | ||||||
March 31, | $ | 25.59 | $ | 7.22 | $ | 22.85 | $ | 3.11 | $ | 0.575 | $ | — | ||||||
June 30, | $ | 25.53 | $ | 4.11 | $ | 20.00 | $ | 1.94 | $ | 0.575 | $ | — | ||||||
September 30, | $ | 24.25 | $ | 3.64 | $ | 20.54 | $ | 2.39 | $ | 0.575 | $ | — | ||||||
SGH - Sr. Subordinated Unit Price Range | Distributions Declared per Unit | |||||||||||||||||
High | Low | |||||||||||||||||
Fiscal Year 2004 | Fiscal Year 2005 | Fiscal Year 2004 | Fiscal Year 2005 | Fiscal Year 2004 | Fiscal Year 2005 | |||||||||||||
Quarter Ended | ||||||||||||||||||
December 31, | $ | 21.60 | $ | 14.05 | $ | 20.01 | $ | 2.31 | $ | 0.575 | $ | — | ||||||
March 31, | $ | 23.80 | $ | 4.42 | $ | 20.45 | $ | 2.05 | $ | 0.575 | $ | — | ||||||
June 30, | $ | 23.90 | $ | 4.60 | $ | 18.75 | $ | 1.15 | $ | 0.575 | $ | — | ||||||
September 30, | $ | 22.65 | $ | 3.35 | $ | 12.62 | $ | 2.12 | $ | — | $ | — |
SGU – Common Unit Price Range | ||||||||||||
High | Low | |||||||||||
Fiscal Year 2006 | Fiscal Year 2005 | Fiscal Year 2006 | Fiscal Year 2005 | |||||||||
Quarter Ended | ||||||||||||
December 31, | $ | 2.39 | $ | 22.23 | $ | 1.05 | $ | 4.32 | ||||
March 31, | $ | 2.97 | $ | 7.22 | $ | 1.84 | $ | 3.11 | ||||
June 30, | $ | 2.98 | $ | 4.11 | $ | 2.26 | $ | 1.94 | ||||
September 30, | $ | 2.62 | $ | 3.64 | $ | 2.24 | $ | 2.39 |
As of September 30, 2005,2006, there were approximately 599533 holders of record of common units, and approximately 104 holders of record of senior subordinated units.
On October 18, 2004, we announced that we would not pay a distribution on our common units. We had previously announced the suspension of distributions on the senior subordinated units on July 29, 2004. We did not pay a distribution on any outstanding units in fiscal 2005. It is unlikely that regular distributions on the common units or senior subordinated units will be resumed in the foreseeable future. While we hope to position ourselves to pay some regular distribution on the common units in future years, of which there can be no assurance, it is considerable less likely that regular distributions will ever resume on the senior subordinated units because of their subordination terms. As of November 25, 2005 there are arrearages aggregating five minimum quarterly distributions on our common units amounting to approximately $92.5 million No distribution may be made on our senior subordinated notes until these arrearages have been paid. For more information on the relative rights and preferences of the senior subordinated units, see the Partnership’s Agreement of Limited Partnership, which is incorporated by reference in this Annual Report as described in Item 15. On December, 9, 2005, the closing price of SGU-common unit was $2.19 per unit and the closing price of SGH-senior subordinated unit was $2.15 per unit.
There is no established public trading market for the Partnership’s 345,364 Junior Subordinated Units and 325,7290.3 million general partner units.
Partnership Distribution Provisions
In general, we had distributedThere will be no mandatory distributions of available cash by us to our partners, on a quarterly basis, allthe holders of our Available Cash incommon units and general partner units through the manner described below. Available Cash is defined for any offiscal quarter ending September 30, 2008. Beginning October 1, 2008, minimum quarterly distributions on the Partnership’s fiscal quarters, as all cash on handcommon units will start accruing at the endrate of that$0.0675 per quarter less the amount of cash reserves that are necessary or appropriate in the reasonable discretion of the general partner to (i) provide for the proper conduct of the business; (ii) comply with applicable law, any of its debt instruments or other agreements; (iii) provide funds for distributions to the common unitholders and the senior subordinated unitholders during the next four quarters. We did not pay a distribution($0.27 on any outstanding units during fiscal 2005.
an annual basis). The general partner may not establish cash reserves for distributions to the senior subordinated units unless the general partner has determined that the establishment of reserves will not prevent it from distributing the minimum quarterly distribution on any common unit arrearages and for the next four quarters. The full definition of Available Cash is set forth in the Agreement of Limited Partnership of the Partnership. Informationinformation concerning restrictions on distributions required inby Item 5. of this sectionreport is incorporated herein by reference to footnote 5 toNote 6 Quarterly Distribution of Available Cash, of the Partnership’s Consolidated Financial Statements, which begin on page F-1 of this Form 10-K.consolidated financial statements.
The revolving credit facility and the indenture for the MLP Notesnew notes both impose certain restrictions on our ability to pay distributions to unitholders. It is unlikely that regular distributions on the common units or senior subordinated units will be resumed in the foreseeable future.
If the proposed recapitalization occurs, our Agreement of Limited Partnership will be amended to provide for no mandatory distributions until after September 30, 2008. See Item 1 “Recapitalization.”
Tax Matters
Star Gas Partners is a master limited partnership and thus not subject to federal and state income taxes. Instead, ourThe corporate subsidiaries wholly owned by Star Gas Partners are subject to federal and state income taxes at the corporate level. Our unitholders are required to report for income tax purposes their allocable share of our income, gains, losses, deductions and credits, regardless of whether we make distributions. Accordingly, each common unitholder should consult its own tax advisor in analyzing the federal, state and local tax consequences applicable to their ownership or dispositionWe expect that an investor will be allocated taxable income regardless of our units. Star Gas reports its tax information onwhether a calendar year basis, while financial reporting is based on a fiscal year ending September 30.cash distribution has been paid.
ITEM 6. SELECTED HISTORICAL FINANCIAL AND OPERATING DATA
ITEM 6. | SELECTED HISTORICAL FINANCIAL AND OPERATING DATA |
The selected financial data as of September 30, 20042006 and 2005, and for the years ended September 30, 2003,2006, 2005 and 2004 and 2005 is derived from the financial statements of the Partnership included elsewhere in this Report. The Consolidated Financial Statements for the years ended September 30, 2005 and 2004 have been restated. See Note 2 to Consolidated Financial Statements. The selected financial data as of September 30, 2001, 2002 and2004, 2003 and for the fiscal years ended September 30, 2001 and 2002 is derived from financial statements of the Partnership not included elsewhere in this Report. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
Fiscal Years Ended September 30, | ||||||||||||||||||||
(in thousands, except per unit data)
| 2001(c) | 2002(c) | 2003 | 2004 | 2005 | |||||||||||||||
Statement of Operations Data: | ||||||||||||||||||||
Sales | $ | 767,959 | $ | 790,378 | $ | 1,102,968 | $ | 1,105,091 | $ | 1,259,478 | ||||||||||
Costs and expenses: | ||||||||||||||||||||
Cost of sales | 563,803 | 546,495 | 793,543 | 799,055 | 983,779 | |||||||||||||||
Delivery and branch expenses | 142,968 | 174,030 | 217,244 | 232,985 | 231,581 | |||||||||||||||
Depreciation and amortization expenses | 28,595 | 40,444 | 35,535 | 37,313 | 35,480 | |||||||||||||||
General and administrative expenses | 19,374 | 17,745 | 39,763 | 19,937 | 43,418 | |||||||||||||||
Goodwill impairment charge | — | — | — | — | 67,000 | |||||||||||||||
Operating income (loss) | 13,219 | 11,664 | 16,883 | 15,801 | (101,780 | ) | ||||||||||||||
Interest expense, net | (20,716 | ) | (23,843 | ) | (29,530 | ) | (36,682 | ) | (31,838 | ) | ||||||||||
Amortization of debt issuance costs | (506 | ) | (1,197 | ) | (2,038 | ) | (3,480 | ) | (2,540 | ) | ||||||||||
Gain (loss) on redemption of debt | — | — | 212 | — | (42,082 | ) | ||||||||||||||
Loss from continuing operations before income taxes | (8,003 | ) | (13,376 | ) | (14,473 | ) | (24,361 | ) | (178,240 | ) | ||||||||||
Income tax expense (benefit) | 1,200 | (1,700 | ) | 1,200 | 1,240 | 696 | ||||||||||||||
Loss from continuing operations | (9,203 | ) | (11,676 | ) | (15,673 | ) | (25,601 | ) | (178,936 | ) | ||||||||||
Income (loss) from discontinued operations, net of inc. taxes | 2,488 | 507 | 19,786 | 20,276 | (4,552 | ) | ||||||||||||||
Gain (loss) on sales of discontinued operations, net of inc. taxes | — | — | — | (538 | ) | 157,560 | ||||||||||||||
Cumulative effects of changes in accounting principles for discontinued operations: | ||||||||||||||||||||
Adoption of SFAS No. 133 | (627 | ) | — | — | — | — | ||||||||||||||
Adoption of SFAS No. 142 | — | — | (3,901 | ) | — | — | ||||||||||||||
Income (loss) before cumulative effects of changes in accounting principle for continuing operations | (7,342 | ) | (11,169 | ) | 212 | (5,863 | ) | (25,928 | ) | |||||||||||
Cumulative effects of changes in accounting principle for adoption of SFAS No. 133 | 2,093 | — | — | — | — | |||||||||||||||
Net income (loss) | $ | (5,249 | ) | $ | (11,169 | ) | $ | 212 | $ | (5,863 | ) | $ | (25,928 | ) | ||||||
Weighted average number of limited partner units: | ||||||||||||||||||||
Basic | 22,439 | 28,790 | 32,659 | 35,205 | 35,821 | |||||||||||||||
Diluted | 22,552 | 28,821 | 32,767 | 35,205 | 35,821 | |||||||||||||||
Per Unit Data: | ||||||||||||||||||||
Basic and diluted loss from continuing operations per unit(a) | $ | (0.40 | ) | $ | (0.40 | ) | $ | (0.48 | ) | $ | (0.72 | ) | $ | (4.95 | ) | |||||
Basic and diluted net income (loss) per unit (a) | $ | (0.23 | ) | $ | (0.38 | ) | $ | 0.01 | $ | (0.16 | ) | $ | (0.72 | ) | ||||||
Cash distribution declared per common unit | $ | 2.30 | $ | 2.30 | $ | 2.30 | $ | 2.30 | $ | — | ||||||||||
Cash distribution declared per senior sub. unit | $ | 1.98 | $ | 1.65 | $ | 1.65 | $ | 1.73 | $ | — | ||||||||||
Balance Sheet Data (end of period): | ||||||||||||||||||||
Current assets | $ | 185,262 | $ | 222,201 | $ | 211,109 | $ | 234,171 | $ | 311,432 | ||||||||||
Total assets | $ | 898,819 | $ | 943,766 | $ | 975,610 | $ | 960,976 | $ | 629,261 | ||||||||||
Long-term debt | $ | 456,523 | $ | 396,733 | $ | 499,341 | $ | 503,668 | $ | 267,417 | ||||||||||
Partners’ Capital | $ | 198,264 | $ | 232,264 | $ | 189,776 | $ | 169,771 | $ | 145,108 | ||||||||||
Summary Cash Flow Data: | ||||||||||||||||||||
Net Cash provided by (used in) operating activities | $ | 38,078 | $ | 18,773 | $ | 15,365 | $ | 13,669 | $ | (54,915 | ) | |||||||||
Net Cash provided by (used in) investing activities | $ | (295,885 | ) | $ | (12,381 | ) | $ | (48,395 | ) | $ | 6,447 | $ | 467,431 | |||||||
Net Cash provided by (used in) financing activities | $ | 263,355 | $ | 28,135 | $ | 48,049 | $ | (19,874 | ) | $ | (306,694 | ) | ||||||||
Other Data: | ||||||||||||||||||||
Earnings from continuing operations before interest, taxes, depreciation and amortization (EBITDA)(b) | $ | 43,907 | $ | 52,108 | $ | 52,630 | $ | 53,114 | $ | (108,382 | ) | |||||||||
Heating oil segment’s retail gallons sold | 427,168 | 457,749 | 567,024 | 551,612 | 487,300 |
Fiscal Years Ended September 30, | ||||||||||||||||||||
(in thousands, except per unit data) | 2006 | 2005 | 2004 | 2003(e) | 2002(d)(e) | |||||||||||||||
(restated, see note 2) | (restated, see note 2) | (restated) | (restated) | |||||||||||||||||
Statement of Operations Data: | ||||||||||||||||||||
Sales | $ | 1,296,512 | $ | 1,259,478 | $ | 1,105,091 | $ | 1,102,968 | $ | 790,378 | ||||||||||
Costs and expenses: | ||||||||||||||||||||
Cost of sales | 1,014,908 | 983,732 | 797,330 | 793,134 | 549,841 | |||||||||||||||
Change in the fair value of derivative instruments | 45,677 | (6,081 | ) | (25,811 | ) | 5,299 | (13,939 | ) | ||||||||||||
Delivery and branch expenses | 205,037 | 231,581 | 232,985 | 217,244 | 174,030 | |||||||||||||||
Depreciation and amortization expenses | 32,415 | 35,480 | 37,313 | 35,535 | 40,444 | |||||||||||||||
General and administrative expenses | 21,673 | 43,190 | 19,537 | 39,413 | 17,515 | |||||||||||||||
Goodwill impairment charge | — | 67,000 | — | — | — | |||||||||||||||
Operating income (loss) | (23,198 | ) | (95,424 | ) | 43,737 | 12,343 | 22,487 | |||||||||||||
Interest expense, net | (21,203 | ) | (31,838 | ) | (36,682 | ) | (29,530 | ) | (23,843 | ) | ||||||||||
Amortization of debt issuance costs | (2,438 | ) | (2,540 | ) | (3,480 | ) | (2,038 | ) | (1,197 | ) | ||||||||||
Gain (loss) on redemption of debt | (6,603 | ) | (42,082 | ) | — | 212 | — | |||||||||||||
Income (loss) from continuing operations before income taxes | (53,442 | ) | (171,884 | ) | 3,575 | (19,013 | ) | (2,553 | ) | |||||||||||
Income tax expense (benefit) | 477 | 696 | 1,240 | 1,200 | (1,700 | ) | ||||||||||||||
Income (loss) from continuing operations | (53,919 | ) | (172,580 | ) | 2,335 | (20,213 | ) | (853 | ) | |||||||||||
Income (loss) from discontinued operations, net of income taxes | — | (6,189 | ) | 22,176 | 19,523 | 507 | ||||||||||||||
Gain (loss) on sales of discontinued operations, net of income taxes | — | 157,560 | (538 | ) | — | — | ||||||||||||||
Cumulative effects of changes in accounting principles for discontinued operations - Adoption of SFAS No. 142 | — | — | — | (3,901 | ) | — | ||||||||||||||
Income (loss) before cumulative effects of changes in accounting principle for continuing operations | (53,919 | ) | (21,209 | ) | 23,973 | (4,591 | ) | (346 | ) | |||||||||||
Cumulative effects of changes in accounting principles-change in inventory pricing method | (344 | ) | — | — | — | — | ||||||||||||||
Net income (loss) | $ | (54,263 | ) | $ | (21,209 | ) | $ | 23,973 | $ | (4,591 | ) | $ | (346 | ) | ||||||
Weighted average number of limited partner units: | ||||||||||||||||||||
Basic | 52,944 | 35,821 | 35,205 | 32,659 | 28,790 | |||||||||||||||
Diluted | 52,944 | 35,821 | 35,205 | 32,767 | 28,821 | |||||||||||||||
ITEM 6. SELECTED HISTORICAL FINANCIAL AND OPERATING DATA (Continued)
Fiscal Years Ended September 30, | ||||||||||||||||||||
(in thousands, except per unit data) | 2006 | 2005 | 2004 | 2003(e) | 2002(d)(e) | |||||||||||||||
(restated, see note 2) | (restated, see note 2) | (restated) | (restated) | |||||||||||||||||
Per Unit Data: | ||||||||||||||||||||
Basic and diluted loss from continuing operations per unit(a) | $ | (1.01 | ) | $ | (4.77 | ) | $ | 0.07 | $ | (0.61 | ) | $ | (0.40 | ) | ||||||
Basic and diluted net income (loss) per unit (a) | $ | (1.02 | ) | $ | (0.59 | ) | $ | 0.67 | $ | (0.14 | ) | $ | (0.1 | ) | ||||||
Cash distribution declared per common unit | $ | — | $ | — | $ | 2.30 | $ | 2.30 | $ | 2.30 | ||||||||||
Cash distribution declared per senior sub. unit | $ | — | $ | — | $ | 1.73 | $ | 1.65 | $ | 1.65 | ||||||||||
Cash distribution declared per junior sub. unit | $ | — | $ | — | $ | — | $ | 1.15 | $ | 1.15 | ||||||||||
Cash distribution declared per general partner unit | $ | — | $ | — | $ | — | $ | 1.15 | $ | 1.15 | ||||||||||
Balance Sheet Data (end of period): | ||||||||||||||||||||
Current assets | $ | 295,880 | $ | 305,319 | $ | 228,053 | $ | 204,417 | $ | 214,648 | ||||||||||
Total assets | $ | 581,208 | $ | 623,148 | $ | 954,858 | $ | 968,918 | $ | 936,213 | ||||||||||
Long-term debt | $ | 174,056 | $ | 267,417 | $ | 503,668 | $ | 499,341 | $ | 396,733 | ||||||||||
Partners’ Capital | $ | 173,325 | $ | 145,108 | $ | 169,771 | $ | 189,776 | $ | 232,264 | ||||||||||
Summary Cash Flow Data: | ||||||||||||||||||||
Net Cash provided by (used in) operating activities | $ | 18,364 | $ | (54,915 | ) | $ | 13,669 | $ | 15,365 | $ | 18,773 | |||||||||
Net Cash provided by (used in) investing activities | $ | (3,271 | ) | $ | 467,431 | $ | 6,447 | $ | (48,395 | ) | $ | (12,381 | ) | |||||||
Net Cash provided by (used in) financing activities | $ | (23,120 | ) | $ | (306,694 | ) | $ | (19,874 | ) | $ | 48,049 | $ | 28,135 | |||||||
Other Data: | ||||||||||||||||||||
Earnings from continuing operations before interest, taxes, depreciation and amortization (EBITDA)(b)(c) | $ | 2,614 | $ | (102,026 | ) | $ | 81,050 | $ | 48,090 | $ | 62,931 | |||||||||
Retail gallons sold | 389,920 | 487,300 | 551,612 | 567,024 | 457,749 | |||||||||||||||
(a) Income (loss) from continuing operations per unit is computed by dividing the limited partners’ interest in income (loss) from continuing operations by the weighted average number of limited partner units outstanding. Net income (loss) per unit is computed by dividing the limited partners’ interest in net income (loss) by the weighted average number of limited partner units outstanding.
(b) EBITDA was reduced (increased) by the following: |
| |||||||||||||||||||
2006 | 2005 | 2004 | 2003 | 2002 | ||||||||||||||||
(restated, see note 2) | (restated, see note 2) | (restated) | (restated) | |||||||||||||||||
Change in the fair value of derivative instruments | $ | 45,677 | $ | (6,081 | ) | $ | (25,811 | ) | $ | 5,299 | $ | (13,939 | ) | |||||||
(Gain) loss on redemption of debt | 6,603 | 42,082 | — | (212 | ) | — | ||||||||||||||
Goodwill impairment charge | — | 67,000 | — | — | — | |||||||||||||||
Total | $ | 52,280 | $ | 103,001 | $ | (25,811 | ) | $ | 5,087 | $ | (13,939 | ) | ||||||||
EBITDA from continuing operations should not be considered as an alternative to net income (as an indicator of operating performance) or as an alternative to cash flow (as a measure of liquidity or ability to service debt obligations), but provides additional information for evaluating our ability to make the minimum quarterly distribution. The working capital facility and the senior secured notes, impose certain restrictions on our ability to pay distributions to unitholders. |
The definition of “EBITDA” set forth above may be different from that used by other companies. EBITDA from continuing operations is calculated for the fiscal years ended September 30 as follows:
(in thousands)
| 2001 | 2002 | 2003 | 2004 | 2005 | |||||||||||||||
Loss from continuing operations | $ | (9,203 | ) | $ | (11,676 | ) | $ | (15,673 | ) | $ | (25,601 | ) | $ | (178,936 | ) | |||||
Cumulative effects of changes in accounting principle for adoption of SFAS No. 133 for continuing operations | 2,093 | — | — | — | — | |||||||||||||||
Plus: | ||||||||||||||||||||
Income tax expense (benefit) | 1,200 | (1,700 | ) | 1,200 | 1,240 | 696 | ||||||||||||||
Amortization of debt issuance cost | 506 | 1,197 | 2,038 | 3,480 | 2,540 | |||||||||||||||
Interest expense, net | 20,716 | 23,843 | 29,530 | 36,682 | 31,838 | |||||||||||||||
Depreciation and amortization | 28,595 | 40,444 | 35,535 | 37,313 | 35,480 | |||||||||||||||
EBITDA from continuing operations | $ | 43,907 | $ | 52,108 | $ | 52,630 | $ | 53,114 | $ | (108,382 | ) | |||||||||
(in thousands) | 2006 | 2005 | 2004 | 2003 | 2002 | ||||||||||||||
(restated, see note 2) | (restated, see note 2) | (restated) | (restated) | ||||||||||||||||
Loss from continuing operations | $ | (53,919 | ) | $ | (172,580 | ) | $ | 2,335 | $ | (20,213 | ) | $ | (853 | ) | |||||
Plus: | |||||||||||||||||||
Income tax expense (benefit) | 477 | 696 | 1,240 | 1,200 | (1,700 | ) | |||||||||||||
Amortization of debt issuance cost | 2,438 | 2,540 | 3,480 | 2,038 | 1,197 | ||||||||||||||
Interest expense, net | 21,203 | 31,838 | 36,682 | 29,530 | 23,843 | ||||||||||||||
Depreciation and amortization | 32,415 | 35,480 | 37,313 | 35,535 | 40,444 | ||||||||||||||
EBITDA from continuing operations | $ | 2,614 | $ | (102,026 | ) | $ | 81,050 | $ | 48,090 | $ | 62,931 | ||||||||
Our results for fiscal |
(e) | Fiscal 2003 and fiscal 2002 have been restated with respect to the accounting for derivative transactions and the calculation of pension expense. |
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
ITEM 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS. |
Statement Regarding Forward-Looking Disclosure
This Annual Report on Form 10-K includes “forward-looking statements” which represent our expectations or beliefs concerning future events that involve risks and uncertainties, including those associated with, the recapitalization, the effect of weather conditions on our financial performance, the price and supply of home heating oil, the consumption patterns of our customers, our ability to obtain satisfactory gross profit margins, our ability to obtain new accounts and retain existing accounts, our ability to effect strategic acquisitions or redeploy assets, the ultimate disposition of Excess Proceeds from the sale of the propane segment, the impact of litigation, the continuing impact of the business process redesign project at the heating oil segment and our ability to address issues related to that project, our ability to contract for our current and future supply needs, natural gas conversions, future union relations and outcome of current and future union negotiations, the impact of future environmental, health, and safety regulations, customer credit worthiness, and marketing plans. 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. 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 have been 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 under the heading “Risk Factors,”Factors” and “Business Initiatives and Strategy,” and “Business Outlook Fiscal 2006.Strategy.” Without limiting the foregoing the words “believe”,“believe,” “anticipate,” “plan,” “expect,” “seek,” “estimate” and similar expressions are intended to identify forward-looking statements. Important factors that could cause actual results to differ materially from our expectations (“Cautionary Statements”) are disclosed in this Annual Report on Form 10-K. All subsequent written and oral forward-looking statements attributable to the Partnership or persons acting on its behalf are expressly qualified in their entirety by the Cautionary Statements. Unless otherwise required by law, we undertake no obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise after the date of this Report.
Overview
In analyzing our financial results, the following matters should be considered.
The following is a discussion of the historical condition and results of operations of the Partnership and its subsidiaries, and should be read in conjunction with the description of our business in Item 1. “Business” and the historical Financial and Operating Data and Notes thereto included elsewhere in this Report. We completed the sale of our TG&E segment in March 2004 and propane segment in December 2004. The2004 and the following discussion reflects the historical results for the TG&E segment and propane segment as discontinued operations.
Restatement
On December 13, 2006, one day before the planned filing of the Partnership’s annual report, the Partnership’s external auditors, KPMG, made the Partnership aware of a speech given by a professional accounting fellow of the Securities and Exchange Commission (“SEC”) on December 11, 2006 relating to Statement of Financial Accounting Standards “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”). After reviewing the speech, the Partnership conducted an extensive review of its accounting for derivative transactions under SFAS 133 to determine whether the Partnership’s documentation for certain derivative transactions met the strict requirements of SFAS 133 to permit hedge accounting and the deferral of unrecognized non-cash gains and losses for such transactions. The documentation was consistent with the documentation previously used by the Partnership and provided to KPMG in support of hedge accounting treatment for similar transactions that had been reflected in prior period financial statements. However, SFAS 133 is a very complex and highly technical standard, which has been the subject of an evolving interpretation by the accounting community. After further review, on December 26, 2006 the Partnership, the Audit Committee and the Board of Directors, determined that the Partnership’s accounting for derivative transactions did not comply with the technical requirements of SFAS 133 to qualify for hedge accounting.
As a result, the Partnership determined that it was necessary to amend and restate its financial statements for each of the fiscal years ended September 30, 2005 and 2004 as well as the Partnership’s quarterly reports for the periods ended June 30, 2006, March 31, 2006, December 31, 2005, September 30, 2005, June 30, 2005, March 31, 2005 and December 31, 2004 with respect to the accounting and disclosures for certain derivative transactions under SFAS 133. In addition, prior to June 30, 2006, the Partnership did not include the amortization of an unrecognized gain in the calculation of pension expense resulting in an overstatement of pension expense for fiscal year’s 1999 to 2005 of $1.7 million. The Partnership has restated our results to record the amortization of the unrecognized gain. See Note 2 to our Consolidated Financial Statements for further details on the restatement. The Partnership has discussed this matter with KPMG, who served as the Partnership’s external auditors for all affected periods, in reaching the conclusion to restate the financial statements.
The restatement does not impact the economics of the hedge transactions nor does it affect the Partnership’s liquidity, cash flow from operating activities in any historical or future period, or the amount of available cash to pay distributions as defined in the Partnership agreement in any historical or future period. The hedges were primarily entered into in order to mitigate the Partnership’s exposure to market risk associated with the purchase of home heating oil for its price-protected customers.
The Partnership has been contacted informally by the Boston District Office of the SEC requesting the voluntary provision of documents and related information concerning the Partnership’s use of derivatives and hedge accounting. The SEC has advised the Partnership that the inquiry should not be construed as an indication by the SEC or its staff that any violations of the law have occurred, nor should it be considered a reflection upon any person, entity or security. The Partnership is fully cooperating with this inquiry.
Recapitalization
Effective as of April 28, 2006, the Partnership completed its recapitalization pursuant to the terms of a unit purchase agreement dated as of December 5, 2005, as amended, by and among, the Partnership, Star Gas LLC (the former general partner), Kestrel and its wholly-owned subsidiaries, Kestrel Heat (the new general partner) and KM2, LLC, a Delaware limited liability company. (See Note 3 to the Consolidated Financial Statements - Recapitalization)
Seasonality
In analyzing our financial results, the following matters should be considered. Our fiscal year ends on September 30. All references to quarters and years respectively in this document are to fiscal quarters and years unless otherwise noted. The seasonal nature of our business results in the sale of approximately 30% of our volume of home heating oil in the first fiscal quarter (October through December) and 45% of our volume in the second fiscal quarter (January through March) of each fiscal year, the peak heating season, because heating oil is primarily used for space heating in residential and commercial buildings.season. We generally realize net income in both of thesethe first and
second fiscal quarters and net losses during the quarters ending Junethird and September.fourth fiscal quarters. In addition, sales volume typically fluctuates from year to year in response to variations in weather, wholesale energy prices and other factors. Gross profit is not only affected by weather patterns but also by changes in customer mix. For example, sales to our residential variable customers ordinarily generate higher margins than sales to our other customer groups, such as residential protected or commercial customers. In addition, our gross profit margins vary by geographic region. Accordingly, gross profit margins could vary significantly from year to year in a period of identical sales volumes.
Summary of Significant Events and DevelopmentsDerivatives
Sale of propane segment
In December 2004 we completed the sale of our propane segment to Inergy for a cash purchase price of $481.3 million and recognized a gain of approximately $157 million from the sale after closing costs of approximately $14 million. $311 million of the proceeds from the sale were used to repurchase senior secured notes and first mortgage notes of the heating oil segment and propane segment, together with associated prepayment premiums, accrued interest and the amounts then outstanding under the propane segment’s working capital facility. Our propane segment represented approximately 24% and 20% of our total revenue in fiscal 2004 and 2003, respectively, and 64% of our operating income in each of fiscal 2004 and 2003. The historical results of the propane segment are reflected as discontinued operations in our consolidated financial statements.
New Credit Facility
On December 17, 2004 we executed a new $260 million revolving credit facility with a group of lenders led by J.P. Morgan Chase Bank, N.A. This new facility provides us the ability to borrow up to $260 million for working capital purposes (subject to certain borrowing base limitations and coverage ratios) and replaced the heating oil segment’s existing $235 million credit facility. Fees and expenses totaling approximately $8.0 million were incurred in connection with consummating the new facility. On November 3, 2005, the revolving credit facility was amended to increase the facility size by $50 million to $310 million for the peak winter months from December through March of each year. Obligations under the new revolving credit facility are secured by liens on substantially all of the assets of the Partnership, the heating oil segment and its subsidiaries.
Unitholder Suit
In October 2004, a purported class action lawsuit was filed against the Partnership and various subsidiaries and current and former officers and directors. Subsequently, 16 additional class action complaints alleging the same or substantially similar claims were filed in the same district court. The complaints generally allege that the Partnership violated sections 10(b) and 20(a) of the Securities Exchange Act of 1934, as amended. The court has consolidated the class action complaints and appointed a lead plaintiff. On September 23, 2005 we filed motions to dismiss. Plaintiffs replied to these motions on November 23, 2005 and we expect to file our reply briefs on or about December 20, 2005. In the interim, discovery in the matter remains stayed. We intend to continue to defend against this purported class action lawsuit vigorously.
Goodwill Write-down
During the second quarter of fiscal 2005 we incurred a non-cash goodwill impairment charge of $67 million at the heating oil segment as a result of triggering events that occurred during the second quarter of 2005. These triggering events included a significant decline in our unit price and the determination that operating results for fiscal 2005 would be significantly lower than previously expected.
MLP Notes
In accordance with the terms of the indenture relating to the Partnership’s 10 1/4% Senior Notes (“MLP Notes”), we are permitted within 360 days of the sale, to apply the net proceeds (the “Net Proceeds”) of the sale of the propane segment either to reduce indebtedness (and reduce any related commitment) of the Partnership or of a restricted subsidiary, or to make an investment in assets or capital expenditures useful to the business of the Partnership or any of its subsidiaries as in effect on the issue date of the MLP Notes (the “Issue Date”) or any business related, ancillary or complementary to any of the businesses of the Partnership on the Issue Date (each a “Permitted Use” and collectively the “Permitted Uses”). To the extent any Net Proceeds that are not so applied exceed $10 million (“Excess Proceeds”), the indenture requires us to make an offer to all holders of MLP Notes to purchase for cash that number of MLP Notes that may be purchased with Excess Proceeds at a purchase price equal to 100% of the principal amount of the MLP Notes plus accrued and unpaid interest to the date of purchase. At September 30, 2005, the amount of Net Proceeds in excess of $10 million not yet applied toward a Permitted Use totaled $93.2 million. As of December 2, 2005 all Excess Proceeds were applied toward a Permitted Use. We understand, based on informal communications, that certain holders of MLP Notes may take the position that the use of Net Proceeds to invest in working capital assets is not a Permitted Use under the indenture. We disagree with this position and have communicated our disagreement with these noteholders. However, if our position is challenged and we are unsuccessful in defending our position, this
would constitute an event of default under the indenture if declared either by the holders of 25% in principal amount of the senior notes or by the trustee. In such event, all amounts due under the senior notes would become immediately due and payable, which would have a material adverse effect on our ability to continue as a going concern. The report of our independent registered public accounting firm on our consolidated financial statements as of September 30, 2005 and 2004, and for the three years ended September 30, 2005, includes an explanatory paragraph with respect to the impact of this matter on our ability to continue as a going concern if this matter is resolved adversely to us. We have reached an agreement with the holders of 94% in aggregate principal amount of the senior notes to resolve this matter, which is subject to our completing the proposed recapitalization, of which there can be no assurance. See “Recapitalization” below.
Departure of Chairman and CEO
On March 7, 2005 (“the Termination Date”), Star Gas LLC and Mr. Irik P. Sevin entered into a letter agreement and general release (the “Agreement”). In accordance with the Agreement, Mr. Sevin resigned from employment as the Chairman and Chief Executive Officer and President of Star Gas LLC (and its subsidiaries) under the employment agreement between Mr. Sevin and Star Gas LLC dated as of September 30, 2001. In addition, under terms of the agreement Mr. Sevin transferred his member interests in Star Gas LLC to a voting trust of which Mr. Sevin is one of three trustees. Under the terms of the voting trust, those interests will be voted in accordance with the decision of a majority of the trustees. Pursuant to the Agreement, Mr. Sevin is entitled to an annual consulting fee totaling $395,000 for a period of five years following the Termination Date. In addition, the Agreement provides for Mr. Sevin to receive a retirement benefit equal to $350,000 per year for a 13 year period beginning with the month following the five year anniversary of the Termination Date. At March 31, 2005, we recorded a liability for $4.2 million, which represents the present value of the cost of the agreement.
Home Heating Oil Price Volatility
The wholesale price of home heating oil likehas been extremely volatile over the last three fiscal years and has resulted in increased consumer awareness of heating costs and increased net customer attrition. Like any other market commodity, the price of home heating oil is generally set bysubject to the economic forces of supply and demand. Rapid global economic expansion is fueling an ever-increasing demand for oil. HomeThe price of home heating oil prices areis closely linked to the price refiners pay for crude oil because crude oilwhich is the principal cost component of home heating oil. Crude oil is bought and sold in the international marketplace and as such is subject tosignificantly affected by the economic forces of worldwide supply and demand worldwide. The United States imports more than 60% of the petroleum products it consumes. The wholesale cost ofdemand.
We have seen home heating oil as measured byprice movements ranging from $0.54 to $1.00 per gallon over the New York Mercantile Exchange (“Nymex”) at September 30, 2005, 2004 and 2003 was $2.06, $1.39 and $0.78, respectively
The current marketplace for petroleum products including home heating oil has been extremely volatile.last three fiscal years. In a volatile market even small changes in supply or demand can dramatically affect prices. The changes we have seen this past year and continue to experience have been significant. Heating oil prices are subject to price fluctuations if demand rises sharply because of excessively cold weather and/or disruptions at refineries and instability in key oil producing regions. Ultimately, increases in wholesale prices are, in most instances, borne by
Customer Attrition
For fiscal 2006, we lost 29,600 accounts (net) or 6.6% of our customers. Because of these high prices we have experienced increased attrition in ourhome heating oil customer base, and aas compared to fiscal 2005 in which we lost 35,100 accounts (net) or 7.1% of our home heating oil customer base. This decrease in heating oil volume sold pernet customers lost of 5,500 was due to fewer gross customer (“conservation”)gains (5,600) and less gross customer losses (11,100). In fiscal 2006, 26,200 of the homes we serviced changed ownership compared to 34,200 homes in the prior year. In 2006, we were able to retain 13,600 of those homes versus 15,800 retained in fiscal 2005. Gross gains were negatively impacted by (i) the continuation of our higher minimum profitability standards for new customers, (ii) a reduction in mass-market advertising, which attracted more transient customers in the past, (iii) continued customer price sensitivity due to the increased level and volatility of energy prices and (iv) increased minimum credit standards for customers.
In addition to the reduction in gross losses due to moves in fiscal 2006, we also experienced fewer losses relating to price (2,500), service (1,000) and other factors.
For fiscal 2005, over 75%we lost approximately 35,100 accounts (net) or 7.1% of our revenue is attributable to the retail sale and delivery of home heating oil. About half of our retail sales of home heating oil arecustomer base, as compared to customers who agreefiscal 2004 in which we lost 33,100 accounts (net) or 6.4%. This increased loss of 2,000 accounts was largely due to paythe factors described above as well as our ability to retain existing homes that changed hands worsened by over 4,000 accounts. Losses of protected price accounts also increased. Certain of these accounts that were renewed at a low fixed or maximum price and per gallon for each delivery over the next twelve months (protected price customers). The remaining retail sales are to customers that pay a variable price based principally on the daily spot price plus our profit margin.
We mitigate our exposure to our price protected customers in a volatile market by hedging our fixed and maximum price sales through the purchase of exchange traded options and futures, and over the counter options and swaps, and we mitigate our exposure to variable priced customers, in most instances, by passing through higher home heating oil costs directly to such customers.
Customer attrition
Net customer attrition is the difference between gross customer losses and customers added through marketing efforts. Customers added through acquisitions are not includedmargin in the calculationsummer and fall of net customer attrition. The gain of a new customer does2004 chose not fully compensate for the loss of an existing customer during the first year because of the expenses that must be incurred to acquire a new customerrenew as we sought higher prices and the higher attrition rate associated with new customers. Gross customer losses are the result of a number of factors, including price competition, move-outs, and service issues. When a customer moves out of an existing home we count the “move out” as a loss and if we are successfulper gallon margins in signing up the new homeowner, the “move in” is treated as a gain.fiscal 2005.
Gross customer gains and gross customer losses for fiscal 2003, 2004 and 2005 is found below:
Fiscal Year Ended | Fiscal Year Ended | |||||||||||||||||
Description | 2003 | 2004 | 2005 | 2006 | 2005 | 2004 | ||||||||||||
Gross Customer Gains | 71,800 | 67,400 | 63,800 | 58,200 | 63,800 | 67,400 | ||||||||||||
Gross Customer Losses | (78,800 | ) | (100,500 | ) | (98,900 | ) | (87,800 | ) | (98,900 | ) | (100,500 | ) | ||||||
Net Customer Loss | (7,000 | ) | (33,100 | ) | (35,100 | ) | (29,600 | ) | (35,100 | ) | (33,100 | ) | ||||||
Net customer attrition as a percent of the home heating oil customer base for fiscal 2003, 2004, and 2005 is found below:
Fiscal Year Ended | Fiscal Year Ended | |||||||||||||||||
Description | 2003 | 2004 | 2005 | 2006 | 2005 | 2004 | ||||||||||||
Gross Customer Gains | 14.9 | % | 13.1 | % | 12.9 | % | 13.0 | % | 12.9 | % | 13.1 | % | ||||||
Gross Customer Losses | (16.4 | )% | (19.5 | )% | (20.0 | )% | (19.6 | )% | (20.0 | )% | (19.5 | )% | ||||||
Net Customer Attrition | (1.5 | )% | (6.4 | )% | (7.1 | )% | (6.6 | )% | (7.1 | )% | (6.4 | )% | ||||||
During the three months ended September 30, 2006, we lost 5,500 accounts (net) or 1.2% of our home heating oil customer base, as compared to the three months ended September 30, 2005 in which we lost 15,800 accounts (net) or 3.2% of its home heating oil customer base. This reduction in net losses of 10,300 accounts was due to an increase in gross customer gains of 1,300 accounts and a reduction in customer losses of 9,000 accounts as losses due to pricing declined by approximately 6,000 accounts and the number of customer homes changing hands declined by 3,600. In the fourth quarter of 2006, we retained 40% of those homes compared to 33% in the same period in 2005.
Net home heating oil customers accounts added (lost) for fiscal 2003, 2004, and 2005 by quarter is as follows:
Quarter Ended | Fiscal 2003 | Fiscal 2004 | Fiscal 2005 | Fiscal 2006 | Fiscal 2005 | Fiscal 2004 | ||||||||||||
December 31 | 3,500 | (3,300 | ) | (2,000 | ) | (7,200 | )* | (2,000 | ) | (3,300 | ) | |||||||
March 31 | (3,700 | ) | (8,600 | ) | (9,900 | ) | (10,600 | )* | (9,900 | ) | (8,600 | ) | ||||||
June 30 | (5,900 | ) | (10,300 | ) | (7,400 | ) | (6,300 | )* | (7,400 | ) | (10,300 | ) | ||||||
September 30 | (900 | ) | (10,900 | ) | (15,800 | ) | (5,500 | ) | (15,800 | ) | (10,900 | ) | ||||||
TOTAL | (7,000 | ) | (33,100 | ) | (35,100 | ) | (29,600 | ) | (35,100 | ) | (33,100 | ) | ||||||
* | Net customers lost have been increased by a total of 1,400 accounts from previously disclosed amounts. |
We experienced net customer attrition of 7.1% in fiscal 2005. This compares to net attrition of 6.4% and 1.5% in fiscal 2004 and 2003, respectively. This increase in net customer attrition for both fiscal 2004 and 2005 can be attributed to: (i) a combination of the effect of our premium service/premium price strategy during a volatile period when customer price sensitivity increased due to high energy prices; (ii) our decision in fiscal 2005 to maintain reasonable profit margins going forward in spite of competitors’ aggressive pricing tactics; (iii) the lag effect of customer attrition related to service and delivery problems experienced in prior fiscal years; (iv) continued customer dissatisfaction with the centralization of customer care; and (v) tightened customer credit standards.
If wholesale prices remain high, we believe the risk of customer losses due to credit problems, especially for commercial customers, may increase and bad debt expense will also increase. We have continued to experience net customer attrition during fiscal 2006.2007. For the period from October 1 to November 30, 2005December 31, 2006, we lost 4,3154,100 accounts (net ) or 0.9%(net), 1.0% of our home heating oil customer base as compared to the period from October 1 to November 30, 2004December 31, 2005 in which we gained 530lost 7,200 accounts (net) or 0.1%1.6% of our customer base.
For fiscal 2005, we lost approximately 35,100 accounts (net) or 2,000 more thanWe believe that the 33,100 accounts (net) lost in fiscal 2004. This increased loss of 2,000 accounts is largely due to the factors described above as well as losses of fixedcontinued price accounts that were renewed at a low fixed price in the summervolatility and fall of 2004, as the heating oil segment, in an attempt to retain customers, did not raise prices sufficiently to offset the increase in thehigh cost of home heating oil will continue to adversely impact our ability to attract customers and retain existing customers.
Results of Operations
The following is a discussion of the results of operations of the Partnership and its subsidiaries, and should be read in conjunction with the historical Financial and Operating Data and Notes thereto included elsewhere in this Annual Report. We completed the sale of the propane segment in December 2004. The following discussion reflects the historical results for the propane segment as discontinued operations.
Fiscal Year Ended September 30, 2006
Compared to Fiscal Year Ended September 30, 2005
Volume
For fiscal 2006, retail volume of home heating oil declined by 97.4 million gallons, or 20.0%, to 389.9 million gallons, as compared to 487.3 million gallons for fiscal 2005. Volume of other petroleum products declined by 11.5 million gallons, or 15.8%, to 62.0 million gallons for fiscal 2006, as compared to 73.5 million gallons for fiscal 2005. An analysis of the change in the retail volume of home heating oil, which choseis based on management’s estimates, sampling and other mathematical calculations, is found below:
(in millions of gallons) | Heating Oil Segment | ||
Volume—Fiscal 2005 | 487.3 | ||
Impact of warmer temperatures | (53.6 | ) | |
Net customer attrition | (36.0 | ) | |
Asset sale | (2.3 | ) | |
Conservation and other, net | (5.5 | ) | |
Change | (97.4 | ) | |
Volume—Fiscal 2006 | 389.9 | ||
Temperatures in our geographic areas of operations for fiscal 2006 were 11.0% warmer than fiscal 2005 and approximately 10.4% warmer than normal, as reported by the National Oceanic Atmospheric Administration (“NOAA”). Due to the significant increase in the price per gallon of home heating oil, we believe that customers are using less home heating oil given similar temperatures when compared to prior periods. We cannot determine if conservation is a permanent or temporary phenomenon. Home heating oil volume declined by 2.3 million gallons due to the sale of certain of our assets in New England. Excluding the impact of weather, we expect that home heating oil volume for the fiscal quarter ended December 31, 2006 and fiscal 2007 will be substantially less than the comparable period in fiscal 2006 due to net customer attrition, conservation and other factors. In addition, we expect that home heating oil volume for fiscal 2007 will be adversely affected by warmer than normal temperatures. Temperatures from October 1, 2006 to January 14, 2007 in the New York City area, which approximates our geographic areas of operations, were 20.6% warmer than normal. From October 1, 2005 to January 31, 2006, temperatures in our areas of operations were 8.5% warmer than normal.
Product Sales
For fiscal 2006, product sales increased $38.1 million, or 3.6%, to $1,109.3 million, as compared to $1,071.3 million for fiscal 2005 due to an increase in selling prices, which more than offset a decline in home heating oil volume sold. Selling prices were higher in response to the increase in wholesale home heating oil supply costs noted below of $0.4307 per gallon and our decision to pursue higher per gallon gross profit margins, particularly from our price-protected customers. Average home heating oil prices increased from $1.9405 per gallon for fiscal 2005 to $2.5067 for fiscal 2006.
In an effort to reduce net customer attrition, we delayed increasing our selling price to certain customers whose price plan agreements expired during the July to September 2004 time period. This decision negatively impacted sales by an estimated $2.8 million in fiscal 2005, primarily during the first quarter of fiscal 2005.
Installation and Service Sales
For fiscal 2006, service and installation sales decreased $1.0 million, or 0.5%, to $187.2 million, as compared to $188.2 million for fiscal 2005. Installation sales decreased by $2.1 million; however, despite a decline in the customer base, service revenues increased $1.1 million due to measures taken in the last several years to increase service billing and service contract rates.
Cost of Product
For fiscal 2006, cost of product increased $39.4 million, or 5.0%, to $825.7 million, as compared to $786.3 million for fiscal 2005, as higher wholesale product cost was reduced by lower home heating oil volume of 20.0%. Average wholesale product cost for home heating oil increased by $0.4307 per gallon, or 30.0%, to an average of $1.8137 per gallon for fiscal 2006, from an average of $1.3831 for fiscal 2005.
We believe that the change in home heating oil 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. Home heating oil margins for fiscal 2006 increased by $0.1355 per gallon to renew at$ 0.6930 per gallon in fiscal 2006 from $ 0.5575 per gallon in fiscal 2005 due largely to an increase in the margin realized on price-protected customers, an increase in the percentage of volume sold to higher margin residential variable customers, an increase in home heating oil margins realized on new accounts, the loss of some of our less profitable accounts and our decision in the summer of fiscal 2005 and fiscal 2006 to maintain profit margins going forward in spite of competitors’ aggressive pricing tactics. During the renewal period for price-protected customers in fiscal 2004, which was a period of rising heating oil prices, a number of residential variable consumers migrated to price protected plans. This shift resulted in an increase in volume sold to residential price-protected customers for the heating season of fiscal 2005. During the renewal period for price-protected customers in fiscal 2005, a period with even higher average heating oil prices than the renewal period in fiscal 2004, a number of residential price-protected customers elected variable pricing or failed to respond to our price-protected programs, which resulted in a shift back to variable pricing for these customers. The percentage of home heating oil volume sold to residential variable price customers increased to 45.0% of total home heating oil volume sales for fiscal 2006, as compared to 36.0% for fiscal 2005. Accordingly, the percentage of home heating oil volume sold to residential price-protected customers decreased to 38.3% for fiscal 2006, as compared to 48.0% for fiscal 2005. For fiscal 2006, sales to commercial/industrial customers represented 16.7% of total home heating oil volume sales, as compared to 16.0% for fiscal 2005.
Also contributing to the increase in home heating oil per gallon margins were the favorable market conditions experienced during the first quarter of fiscal 2006, as compared to the first quarter of fiscal 2005. During the three months ended September 30, 2005, we lost 15,800 accounts (net) or 3.2% of ourDecember 31, 2004, home heating oil customer base, as comparedprices spiked by over 20 cents a gallon from the beginning of the period and contributed to margin compression experienced during the three months ended September 30, 2004 in which we lost 10,900 accounts (net) or 2.1% of itsDecember 31, 2004. Conversely, during the three months ended December 31, 2005, home heating oil customer base. This increased lossprices declined by over 30 cents per gallon from the beginning of 4,900 accounts is largely due to losses attributable to accounts that were renewed at a low fixed price in the summer and fall of 2004 and who chose not to renew at higher prices in fiscal 2005. We cannot predict whether this trend will continue. Over the past several months, we have modified our marketing plan and are seeking to increase the home heating oil product margins realized on new accounts as well as some of our less profitable accounts. We anticipate that while this program could improve net income and lower marketing expenses, fewer new accounts will likely be addedperiod, which will result in higher net customer attrition in the near term.
Priorcontributed to the fiscal 2004 winter heating season, we attempted to develop a competitive advantage in customer service through a business process redesign project and, as part of that effort, centralized our heating equipment service and oil dispatch functions and engaged a centralized customer care center to fulfill our telephone requirements for a majority of our home heating oil customers. We experienced difficulties in advancing this initiative during fiscal 2004, which adversely impacted the customer base and our costs. The savings from this initiative were less than expected and the costs to operate under the centralized format were greater than originally estimated.
The 6.4% net customer attrition rate in fiscal 2004 was higher than the rate experienced in fiscal 2003 and higher than in the preceding several years. For fiscal 2003, before the full implementation of the business process and redesign project and before the increase in the wholesale priceexpansion of home heating oil margins during this period, as we experienced annual net customer attritionwere able to lag the reduction in our variable selling prices as the wholesale cost of 1.5%.heating oil declined.
We believeIn addition, the year-over-year comparison was favorably impacted by $3.4 million of expenses that we have identifiedincurred in fiscal 2005 due to a delay in hedging the problemsprice of product for certain residential price-protected customers, as well as an additional $1.6 million of expenses associated with our centralization efforts and have addressed these issues by structuringnot hedging until December 2004 the customer call center (that we sometimes refer to in this Annual Reportprice of product for certain residential price-protected customers that were incorrectly coded as the customer care center) into work groups that parallel Petro’s district structure, adding customer retention specialists at the district level, answering a portion of customer calls in two districts, providing continuous in-house training at the customer care center, and establishing a general manager of customer retention. The general manager of customer retention reports directly to the President. Despite these efforts, we continued to experience high net attrition rates in 2005, and we expect that high net attrition rates may continue throughvariable customers.
For fiscal 2006, and perhaps beyond. Eventotal product gross profit decreased by $1.3 million, as compared to the extent that the rate of attrition may be halted, the current reduced customer base will adversely impact net income in the future.
The quantitative factors we use to measure the effectiveness of the customer care center and field operations – such as customer satisfaction scores, telephone waiting times and abandonment rates at the customer care center, oil delivery run-outs and heating equipment repair and maintenance response times – have improved meaningfully during fiscal 2005, as the increase in realized home heating oil per gallon margins of $52.8 million was more than offset by the decline of $54.3 million attributable to the decline in home heating oil volume.
Change in the Fair Value of Derivative Instruments
Home heating oil prices increased in the fourth quarter of fiscal 2005 in response to the numerous hurricanes in the Gulf Coast and we recorded a significant mark to market gain. In September 2006, the home heating prices collapsed and we recorded a mark to market loss. As a result of these events, the impact on the change in the fair value of derivative instruments is $45.7 million for fiscal 2006. In the summers of fiscal 2005 and fiscal 2004, home heating oil prices increased which resulted in the recording of unrealized gains at the close of both fiscal 2005 and fiscal 2004. The net gain for fiscal 2005 exceeded the gain for fiscal 2004 by $6.1 million.
Cost of Installations and Service
For fiscal 2006, cost of installations, service and appliances decreased $8.2 million, or 4.2%, to $189.2 million, as compared to $197.4 million for fiscal 2005. The 4.2% decrease in cost of installation and service was less than the same periods6.6% decrease in customers for fiscal 2004 and2006 due to the fixed nature of these expenses. The net loss realized from service (including installations) improved by $7.2 million, from a $9.2 million loss for fiscal 2003.
2005 to a $2.0 million loss for fiscal 2006.
Operating expense/controlDelivery and Branch Expenses
For fiscal 2006, delivery and branch expenses decreased $26.5 million, or 11.5%, to $205.0 million, as compared to $231.6 million for fiscal 2005. This decrease was due to a reduction in marketing expenses of $6.0 million, an estimated
We have implemented
$15.2 million decrease in certain variable operating expenses directly associated with the 20.0% decline in home heating oil volume, $4.4 million received under our weather insurance policy, lower bad debt expense and collection costs of $4.7 million due in part to more stringent credit terms and other expense reductions of $0.7 million, offset by wage and benefit increases of approximately $4.4 million. On a seriescents per gallon basis (excluding the proceeds received from weather insurance), delivery and branch expenses increased 6.2 cents per gallon, or 13%, from 47.5 cents per gallon for fiscal 2005 to 53.7 cents per gallon for fiscal 2006 due to the fixed nature of cost reduction initiativescertain delivery and branch expenses.
Depreciation and Amortization
For fiscal 2006, depreciation and amortization expenses declined by $3.1 million, or 8.7%, to $32.4 million, as compared to $35.5 million for fiscal 2005 as certain assets, which were not replaced, became fully depreciated.
General and Administrative Expenses
For fiscal 2006, general and administrative expenses decreased by $21.5 million, or 49.8%, to $21.7 million, as compared to $43.2 million for fiscal 2005 due to the absence of bridge financing expenses of $7.5 million, which were incurred in fiscal 2005, includinglower fees and expenses totaling $3.4 million associated with certain amendments and waivers on our previous bank credit facility consolidations,obtained during the first fiscal quarter of 2005, lower compensation expense of $0.9 million attributable to staff reductions, a $5.6 million decline in legal expenses related to defending several purported class action lawsuits and exploring financing options in fiscal 2005, $3.3 million less in first year Sarbanes-Oxley compliance cost, a $3.8 million reduction in compensation expense related to separation agreements recorded in the prior period with certain former executives, other expense reductions of non-essential personnel$0.6 million, and a gain on the reduction and re-evaluationsale of certain marketing programs. We believe this will beassets of $0.9 million. Partially offsetting these reductions was an ongoing process overincrease in directors and officers liability insurance expense of $0.7 million and $1.4 million of legal and professional expenses incurred in fiscal 2006 relating to the next several months as we continue to reviewexploration of our operating expenses. We believe that operating expenses have been reduced by approximately $10.0 million atfinancial options. In addition, the heating oil segment and by approximately $1.3 million at the partners’ level. A portion of these expense reductions were realized during fiscal 2005 and the remainder are expected to be realized in fiscal 2006. In addition,results were positively impacted by a wage freeze has been implemented for senior management in fiscal 2006.
We renewed our officers’ and directors’ insurance for the policy year beginning April 2005. The annual premium is $2.7 million and represents an increasereversal of previously recorded compensation expenses of $2.2 million overdue to the prior year’s policy.
decline in the price of senior subordinated units.
RecapitalizationGoodwill Impairment Charge
On December 2,During the fiscal second quarter of 2005, a number of events occurred that indicated a possible impairment of goodwill might exist. These events included our determination in February 2005 of significantly lower than expected operating results for the boardyear and a significant decline in the Partnership’s unit price. As a result of directorsthese triggering events and circumstances, the Partnership completed an additional SFAS 142 impairment review with the assistance of Star Gas LLC approved a strategic recapitalization of Star Gas Partners that, if approved by unitholders and completed, would resultthird party valuation firm at February 28, 2005. This review resulted in a non-cash goodwill impairment charge of approximately $67.0 million, which reduced the carrying amount of goodwill. There was no goodwill impairment charge recorded during fiscal 2006.
Operating Income (Loss)
For fiscal 2006 operating income increased $72.2 million to a $23.2 million loss, as compared to an operating loss of $95.4 million fiscal 2005. This increase was due to the non-recurrence during fiscal 2006 of a $67.0 million goodwill impairment charge recorded in fiscal 2005, a $52.8 million increase in heating oil gross profit due to higher home heating oil margins, a $48.1 million decline in branch and general and administrative expenses, reduction in the outstanding amountnet service and installation loss of $7.2 million, lower depreciation and amortization expense of $3.1 million, reduced by a decrease in heating oil gross profit of $54.3 million due to lower volume and the impact of comparative change in the fair value of derivative instruments of $51.8 million.
Loss on Redemption of Debt
For fiscal 2006, we recorded a $6.6 million loss on the early redemption and conversion of our 101/4% Senior10.25% senior notes (See Notes due 2013 ( “Senior Notes”),3 and 15 of the Consolidated Financial Statements). The loss consists of the $5.4 million attributable to the difference between approximately $87 million and $100 million.
The recapitalization includes a commitment by Kestrel Energy Partners, LLC (or “Kestrel”) and its affiliates to purchase $15 millionthe value of new equity capital and provide a standby commitment in a $35 million rights offering to our common unitholders, at a price of $2.00 per common unit. We would utilize the $50 million in new equity financing, together with an additional $10 million to $23.1 million from operations, to repurchase at least $60 million in face amount of our Senior Notes and, at our option, up to approximately $73.1 million of Senior Notes. In addition, certain noteholders have agreed to convert approximately $26.9 million in face amount of Senior Notes into newly issuedPartnership’s common units at($32.2 million) exchanged for debt ($26.9 million), and the write-off of previously capitalized net deferred financing costs of $2.0 million, reduced in part by a conversion price$0.8 million basis adjustment to the carrying value of $2.00 per unitlong-term debt.
For fiscal 2005, we recorded a $42.1 million loss on the early redemption of certain notes in connection with the closingsale of the recapitalization.propane segment. The loss consisted of cash premiums paid of $37 million for early redemption, the write-off of previously capitalized net deferred financing costs of $6.1 million and legal expenses of $0.7 million, reduced in part by a $1.7 million basis adjustment to the carrying value of long-term debt.
Interest expense
We have entered into agreements with the holdersFor fiscal 2006, interest expense decreased $9.9 million, or 27.3%, to $26.3 million, as compared to $36.2 million for fiscal 2005. This decrease resulted from a lower principal amount in total debt outstanding of approximately 94%$142.5 million, which was offset in principal amountpart by an increase in the Partnership’s weighted average interest rate of our Senior1.2% from 8.9% during fiscal 2005 to 10.1% for fiscal 2006.
Total debt outstanding declined by $142.5 million due to the recapitalization (see Notes which provide that:3 and 15 to the noteholders commit to,Consolidated Financial Statements) and will, tender their Senior Notes at par (i) forlower working capital borrowings as a pro rata portion of $60the proceeds from the sale of the propane segment was used to fund working capital.
Interest Income
For fiscal 2006, interest income increased by $0.8 million, or 17.9%, to $5.1 million, as compared to $4.3 million for fiscal 2005.
Amortization of Debt Issuance Costs
For fiscal 2006, amortization of debt issuance costs was $2.4 million, $0.1 million less than fiscal 2005.
Income Tax Expense
Income tax expense for fiscal 2006 was $0.5 million and represents certain state income tax, alternative minimum federal tax and capital tax. Income tax expense for fiscal 2005 was $0.7 million. The decrease in state taxes for 2006 as compared to 2005 was largely attributable to an election made at our option, upthe state level during the fourth quarter of 2006.
Loss From Continuing Operations
For fiscal 2006, the loss from continuing operations decreased $118.7 million to approximately $73.1$53.9 million, as compared to a loss of $172.6 million for fiscal 2005. This change was due to the $72.2 million increase in cash, (ii)operating income, a $9.9 million decline in exchange for approximately 13,434,000 new common units atinterest expense and a conversion price$0.8 million increase in interest income. The year over year comparison was favorably impacted by a $35.5 million reduction in the loss on redemption of $2.00 per unit (which new units would be acquired by exchanging approximately $26.9debt.
Loss From Discontinued Operations
The discontinued propane segment was sold on December 17, 2004 and it generated a $6.2 million loss in face amountfiscal 2005.
Gains On Sale of Senior Notes) and (iii) in exchange for new notes representingSegments
During fiscal 2005, the remaining face amountPartnership recorded a gain on the sale of the tendered notes. The principle termspropane segment of $156.8 million. Additionally, the new senior notes, suchpurchase price for the TG&E segment was finalized and a positive adjustment of $0.8 million was recorded in fiscal 2005. There were no similar transactions in fiscal 2006
Cumulative Effect of Change in Accounting Principle
Effective October 1, 2005, we changed our method of accounting from the first-in, first-out method to the weighted average cost method for heating oil and other fuels. This change resulted in the recording of a charge of $0.3 million.
Net Loss
For fiscal 2006, net loss increased by $33.1 million to $54.3 million as a $118.7 million increase in income from continuing operations and a $6.2 million decline in the term and interest rate areloss from discontinued operations in the same as2005 fiscal first quarter was offset by the Senior Notes. The closing of the tender offer is conditioned upon the closing of the transactions under the Kestrel unit purchase agreement, which is discussed below. Upon closing the transaction we will incur a gain or lossgains on the exchangesale of Senior Notesdiscontinued operations recorded in the year ago period of $157.6 million and the $0.3 million charge for common units based on the difference betweenchange in accounting principle.
Earnings From Continuing Operations Before Interest, Taxes, Depreciation and Amortization (EBITDA)
For fiscal 2006, EBITDA increased $104.6 million, to $2.6 million, as compared to an EBITDA loss of $102.0 million for fiscal 2005. For fiscal 2006, EBITDA was reduced by $ 6.6 million due to the $2.00 per unit conversion pricenon-cash loss for the early redemption of debt and the non-cash change in the fair value per unit represented by the per unit price in the open market on the conversion date.
Subject to and until the transaction closing, the noteholders have agreed not to accelerate indebtedness due under the senior notes or initiate any litigation or proceeding with respect to the Senior Notes. The noteholders have further agreed to: waive any default under the indenture; not to tender the Senior Notes in the change of control offer which will be required to be made following the closingderivative instruments of the transactions under the unit purchase agreement with Kestrel; and to consent to certain amendments to the existing indenture. The agreement with the noteholders further provides for the termination of its provisions in the event that the Kestrel unit purchase agreement is no longer in effect. The understandings and agreements contemplated by these transactions will terminate if the transaction does not close prior to April 30, 2006.
We believe the proposed recapitalization would substantially strengthen our balance sheet and thereby assist us in meeting our liquidity and capital requirements, which we believe would improve our future financial performance and as a result enhance unitholder value. In addition to enhancing unitholder value, we believe we will be able to operate more efficiently going forward with less long-term debt.
As part of the recapitalization transaction, we have entered into a definitive unit purchase agreement with Kestrel and its affiliates, which provides for, among other things: the receipt by us of $50$45.7 million in new equity financing through the issuance to Kestrel’s affiliates of 7,500,000 common units at $2.00 per unit for an aggregate of $15 million and the issuance of an additional 17,500,000 common units in a rights offering to our common unitholders at an exercise price of $2.00 per unit for an aggregate of $35 million. The rights will be non-transferable, and an affiliate of Kestrel has agreed to buy any common units not subscribed for in the rights offering. Under the terms of the unit purchase agreement, Kestrel Heat, LLC, or Kestrel Heat, a wholly owned subsidiary of Kestrel, will become our new general partner and Star Gas LLC, our current general partner, will receive no consideration for its removal as general partner.
In addition, the unit purchase agreement provides for the adoption of a second amended and restated agreement of limited partnership that will, among other matters:
The recapitalization is subject to certain closing conditions including, the approval of our unitholders, approval of the lenders under our revolving credit facility, and the successful completion of the tender offer for our Senior Notes.
As a result of the challenging financial and operating conditions that we have experienced since fiscal 2004, we have not been able to generate sufficient available cash from operations to pay the minimum quarterly distribution of $0.575 per unit on our partnership securities. These conditions led to the suspension of distributions on our senior subordinated units, junior subordinated units and general partner units on July 29, 2004 and to the suspension of distributions on the common units on October 18, 2004.
We believe that the proposed amendments to our partnership agreement will simplify our capital structure, provide internally generated funds for future investment and align the minimum quarterly distribution more closely with the levels of available cash from operations that we expect to generate in the future.
Kestrel is a private equity investment firm formed by Yorktown Energy Partners VI, L.P., Paul A. Vermylen, Jr. and other investors. Yorktown Energy Partners VI, L.P. is a New York-based private equity investment partnership, which makes investments in companies engaged in the energy industry. Yorktown affiliates and Mr. Vermylen were investors in Meenan Oil Co. L.P. from 1983 to 2001, during which time Mr. Vermylen served as President of Meenan. Meenan was sold to us in 2001.
It is possible that the units purchased as part of the recapitalization transaction or units purchased by one or more than one 5% unitholder would trigger an IRC Section 382 limitation relating to certain net operating loss carryforwards. An ownership change occurs for purposes of Section 382 when there is a direct or indirect sale or exchange of more than 50% by one or more than one 5% shareholders. If an ownership change has occurred in accordance with Section 382, future limitations in the utilization of net operating losses could be significant. It is possible that the Partnership’s subsidiary, Star/Petro, Inc., will not be able to use any of its currently existing net income tax loss carry forwards in the future.
Business Outlook Fiscal 2006
We expect our business to continue to be affected by the following key trends. Our expectations are based on assumptions made by us, and information currently available to us. To the extent our underlying assumptions about or interpretations of available information prove to be incorrect, our actual results may vary materially from our estimated results.
We face numerous challenges in fiscal 2006. For fiscal 2005, EBITDA was reduced by $ 67.0 due to a goodwill impairment charge and $ 42.1 million due to the non-cash loss for the early redemption of debt. In particular, it will be difficultfiscal, 2005, EBITDA was favorably impacted by $6.1 million due to stem the high attrition rates and continued customer conservation that we are currently experiencing, primarily as a resultchange in the fair value of a volatile and consistently high heating oil commodity market.derivative instruments.
Based onEBITDA 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 outlook we expect increased global demand for oil and gas in fiscal 2006, particularlyability to make the Minimum Quarterly Distribution. EBITDA is calculated as a result of emerging energy consumers such as China and India. This resultant increase in demand may support relatively high heating oil commodity prices.follows:
We believe that our efforts to decentralize a portion of our current service operations by redirecting a portion of our customer calls and empowering our local branches will provide benefits in stemming attrition rates in 2006. In addition, we believe our cost control programs coupled with our increasing discipline in hedging rising commodity price risk for our customer price protected contracts and continued philosophy of maintaining reasonable margins in spite of competitors’ aggressive price tactics should mitigate some of the negative impact associated with the continued high heating oil prices in fiscal 2006. As a result we anticipate that our per-gallon margin may improve over our margins earned in fiscal 2005.
We believe the proposed recapitalization , as described above, if approved by our unitholders and completed, will substantially strengthen our balance sheet and thereby assist us in meeting our liquidity and capital requirements, which we believe will improve our future financial performance and as a result enhance unitholder value. In addition to enhancing unitholder value, we believe we will be able to operate more efficiently going forward with less long-term debt.
In the latter part of fiscal 2006, we intend to pursue asset acquisitions, to the extent permitted in our credit facility, in demographic areas that will enable us to realize margins we consider reasonable in the face of aggressive localized price competition as one way to replace volume lost through attrition. In addition, we may dispose of operations in markets where we are not able to effectively employ our strategy of maintaining reasonable margins. We anticipate using this cash flow, in part, to the extent permitted under our credit facility and MLP Notes, to fund anticipated acquisitions.
Fiscal Year Ended September 30, | ||||||||
(in thousands) | 2006 | 2005 | ||||||
(restated) | ||||||||
Loss from continuing operations | $ | (53,919 | ) | $ | (172,580 | ) | ||
Plus: | ||||||||
Income tax expense | 477 | 696 | ||||||
Amortization of debt issuance costs | 2,438 | 2,540 | ||||||
Interest expense, net | 21,203 | 31,838 | ||||||
Depreciation and amortization | 32,415 | 35,480 | ||||||
EBITDA | 2,614 | (102,026 | ) | |||||
Add/(subtract) | ||||||||
Income tax expense | (477 | ) | (696 | ) | ||||
Interest expense, net | (21,203 | ) | (31,838 | ) | ||||
Unit compensation expense (income) | — | (2,185 | ) | |||||
Provision for losses on accounts receivable | 6,105 | 9,817 | ||||||
Gain on sales of fixed assets, net | (956 | ) | (43 | ) | ||||
Goodwill impairment loss | — | 67,000 | ||||||
Loss on redemption of debt | 6,603 | 42,082 | ||||||
Unrealized (gains) losses on derivative contracts | 45,677 | (6,081 | ) | |||||
Change in operating other assets and liabilities | (19,999 | ) | (30,945 | ) | ||||
Net cash provided by (used in) operating activities | $ | 18,364 | $ | (54,915 | ) | |||
Fiscal Year Ended September 30, 2005 (Fiscal 2005)
Compared to Fiscal Year Ended September 30, 2004 (Fiscal 2004)
Statements of Operations by Segment
Fiscal 2004(1) | Fiscal 2005(1) | |||||||||||||||||||||||
(in thousands)
| Heating Oil | Partners & Others | Consol. | Heating Oil | Partners & Others | Consol. | ||||||||||||||||||
Statements of Operations | ||||||||||||||||||||||||
Sales: | ||||||||||||||||||||||||
Product | $ | 921,443 | $ | — | $ | 921,443 | $ | 1,071,270 | $ | — | $ | 1,071,270 | ||||||||||||
Installations and service | 183,648 | — | 183,648 | 188,208 | — | 188,208 | ||||||||||||||||||
Total sales | 1,105,091 | — | 1,105,091 | 1,259,478 | — | 1,259,478 | ||||||||||||||||||
Cost and expenses: | ||||||||||||||||||||||||
Cost of product | 594,153 | — | 594,153 | 786,349 | — | 786,349 | ||||||||||||||||||
Cost of installations and service | 204,902 | 204,902 | 197,430 | — | 197,430 | |||||||||||||||||||
Delivery and branch expenses | 232,985 | — | 232,985 | 231,581 | — | 231,581 | ||||||||||||||||||
Depreciation & amortization expenses | 37,313 | — | 37,313 | 35,480 | — | 35,480 | ||||||||||||||||||
General and administrative | 16,535 | 3,402 | 19,937 | 17,376 | 26,042 | 43,418 | ||||||||||||||||||
Goodwill impairment charge | — | — | — | 67,000 | — | 67,000 | ||||||||||||||||||
Operating income (loss) | 19,203 | (3,402 | ) | 15,801 | (75,738 | ) | (26,042 | ) | (101,780 | ) | ||||||||||||||
Net interest expense | 28,038 | 8,644 | 36,682 | 21,780 | 10,058 | 31,838 | ||||||||||||||||||
Amortization of debt issuance costs | 2,750 | 730 | 3,480 | 1,718 | 822 | 2,540 | ||||||||||||||||||
Loss on redemption of debt | — | — | — | 24,192 | 17,890 | 42,082 | ||||||||||||||||||
Loss from continuing operations before income taxes | (11,585 | ) | (12,776 | ) | (24,361 | ) | (123,428 | ) | (54,812 | ) | (178,240 | ) | ||||||||||||
Income tax expense (benefit) | 1,240 | — | 1,240 | 1,756 | (1,060 | ) | 696 | |||||||||||||||||
Loss from continuing operations | (12,825 | ) | (12,776 | ) | (25,601 | ) | (125,184 | ) | (53,752 | ) | (178,936 | ) | ||||||||||||
Income (loss) from discontinued operations | — | 20,276 | 20,276 | — | (4,552 | ) | (4,552 | ) | ||||||||||||||||
Gain (loss) on sale of segments, net of taxes | — | (538 | ) | (538 | ) | — | 157,560 | 157,560 | ||||||||||||||||
Net income (loss) | $ | (12,825 | ) | $ | 6,962 | $ | (5,863 | ) | $ | (125,184 | ) | $ | 99,256 | $ | (25,928 | ) | ||||||||
Volume
For fiscal 2005, retail volume of home heating oil decreased 64.3 million gallons, or 11.7%, to 487.3 million gallons, as compared to 551.6 million gallons for fiscal 2004. Volume of other petroleum products declined by 7.6 million gallons, or 9.3%, to 73.5 million gallons for fiscal 2005, as compared to 81.1 million gallons for fiscal 2004. An analysis of the change in retail volume of home heating oil, which is based on management’s estimates, sampling, and other mathematical calculations (as actual customer consumption patters cannot be precisely determined) is found below:
(in millions of gallons) | Heating Oil Segment | ||
| 551.6 | ||
Impact of colder temperatures | 4.2 | ||
Impact of acquisitions | 3.2 | ||
Net customer attrition | (39.0 | ) | |
Conservation | (24.5 | ) | |
Delivery scheduling | (6.0 | ) | |
Other | (2.2 | ) | |
Change | (64.3 | ) | |
| 487.3 | ||
We believe that the 64.3 million gallon declineTotal degree-days in home heating oil volume was due to net customer attrition, which occurred during fiscal 2004 and fiscal 2005, conservation, delivery scheduling, and other factors partially offset by acquisitions. Total degree days in the heating oil segment’sour geographic areas of operations were approximately 0.9% greater in fiscal 2005 than in fiscal 2004 and approximately 0.5% greater than normal, as reported by the National Oceanic Atmospheric Administration (“NOAA”).NOAA. Due to the significant increase in the price per gallon of home heating oil during the year, we believe that customers are using less home heating oil given similar temperatures. Indications based on internal studies suggest that our customers have reduced their consumption by approximately 4.4%. We cannot determine if conservation is a permanent or temporary phenomenon. In addition, we estimate that
during fiscal 2005, home heating oil volume was reduced by 6.0 million gallons due to a delivery scheduling variance. We believe that home heating oil volume sold in fiscal 2006 may be substantially less than in fiscal 2005 due to customer attrition, conservation and other factors such as warmer temperatures.
Product Sales
For fiscal 2005, product sales increased $149.8 million, or 16.3%, to $1.071 billion,$1,071 million, as compared to $921.4 million for fiscal 2004, as increases in selling prices more than offset a decline in product sales due to lower volume sold. Selling prices during fiscal 2005 were higher due to the increase in wholesale supply costs. Average wholesale supply costs were $1.40 per total gallon for fiscal 2005, as compared to $0.94 per total gallon for fiscal 2004. The weighted average selling price per total gallon was $1.91 per total gallon in fiscal 2005 compared to $1.46 per total gallon in fiscal 2004.
Average home heating oil prices increased from $1.49 per gallon in fiscal 2004 to $1.94 per gallon in fiscal 2005.
Installation, Service and Other Sales
For fiscal 2005, installation, service and other sales increased $4.6 million, or 2.5%, to $188.2 million compared to $183.6 million in fiscal 2004, as a decline in installation and other sales of $2.8 million was offset by an increase in service revenues of $7.4 million. Over the last several years, the heating oil segment has taken proactive measures, such as modifyingwe have modified service plans and billing strategies, in order to maximize service revenue.
Cost of Product
For fiscal 2005, cost of product increased $192.2$193.9 million, or 32.3%32.7%, to $786.3 million, compared to $594.2$592.4 million for fiscal 2004. This is the result of an increase in the heating oil segment’s average wholesale product cost of $0.46 per total gallon, or 49%, to an average of $1.40 per total gallon for fiscal 2005, from an average of $0.94 per total gallon for fiscal 2004. Average wholesale home heating oil product cost increased by $0.46 per gallon to an average of $1.38 per gallon for fiscal 2005, from an average of $0.92 for fiscal 2004.
We believe that the changes in home heating oil 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 changes in the market value of hedges before the settlement of the underlying transaction. Home heating oil margins decreased by $0.0159 per gallon
to $ 0.5575 per gallon in fiscal 2005 from $ 0.5734 per gallon in fiscal 2004. In an effort to reduce net customer attrition, we delayed increasing our selling price to certain customers whose price plan agreements expired during the July to September 2004 time period. This decision negatively impacted gross profit by an estimated $2.8 million in fiscal 2005, primarily during the first quarter of fiscal 2005.
During fiscal 2005, product cost was adversely impacted by $3.4 million due to a delay in hedging the price of product for certain residential protected price customers due to cash constraints under our previous credit agreement. Cost of product was also adversely impacted by $1.6 million associated with not hedging the price of product for certain residential price protected customers that were incorrectly coded as variable customers. This coding error was corrected in December 2004. Home heating oil per gallon margins for the year ended September 30, 2005 declined by 1.35.0 cents per gallon, compared to fiscal 2004 due to an increase in the percentage of volume sold to lower margin residential price protected customers, the delay in increasing the selling price to customers whose price plans expired during the July to September 2004 time period and the aforementioned hedging issues concerning price protected customers. Gross profit from product sales decreased $38.2by $44.0 million in fiscal 2005 when compared to fiscal 2004 due to the margins associated with lower sales volume and $4.2of $37.4 million due toand lower per gallon margins of $6.7 million (which includes $2.8 million delay in price increases previously described) for the volume sold in fiscal 2005 compared to fiscal 2004.
Our customer base is comprised of three types of customers, residential variable, residential protected price and commercial/industrial. The selling price for a residential variable customer generally has the highest per gallon gross profit margin. In an effort to retain existing customers and attract new customers, we have offered and currently are offering discounts that negatively impact the average per gallon gross profit margins. Currently, these discounts are being offered to residential variable and price protected customers. Over time, we will try to reduce these discounts and increase the per gallon gross profit margin. If we are not successful in reducing these discounts, per gallon gross profit margins may further decline. Due to the greater price sensitivity of residential protected price customers, the per gallon margins realized from that customer segment generally are less than variable priced residential customers. Commercial/industrial customers are characterized as large volume users and contribute the lowest per gallon margin.
The percentage of home heating oil volume sold to residential protected price customers increased to approximately 48% of total home heating oil volume sales during fiscal 2005, as compared to 43% for fiscal 2004. Accordingly, the percentage of home heating oil volume sold to residential variable customers decreased to approximately 36% for fiscal 2005, as compared to 40% for fiscal 2004. During fiscal 2005, sales to commercial/industrial customers represented approximately 16% of total home heating oil volume sales, unchanged from fiscal 2004. Rising energy costs have increased consumer interest in price protection. If wholesale supply costs remain volatile and/or
Change in the Fair Value of Derivative Instruments
In the summers of fiscal 2005 and fiscal 2004, home heating oil prices increased which resulted in the recording of unrealized gains at historically high levels, per gallon profit marginsthe close of both fiscal 2005 and results could continue to be adversely impacted.
fiscal 2004. The net gain for fiscal 2005 exceeded the gain for fiscal 2004 by $6.1 million. Home heating oil prices were relatively stable in the summer of 2003 and we recorded a small change in the value of derivative instruments. The increase in home heating oil prices in the summer of 2004 is the main driver of the change in the fair value of derivative instruments in fiscal 2004 of $25.8 million.
Cost of Installations and Service
For fiscal 2005, cost of installations and service decreased $7.5 million, or 3.6%, to $197.4 million, as compared to $204.9 million for fiscal 2004. This reduction was due to a lower level of variable installation costs of $2.0 million attributable to the lower level of installation sales and a $5.5 million decline in service expenses. Service expenses decreased due to a contraction in costs resulting from servicing a smaller customer base, warmer temperatures during the peak heating season, which reduced the frequency of service calls, and an improvement in the scheduling of preventative maintenance service calls which lowered overtime hours. The loss realized from service (including installations) improved by $12.1 million from a $21.3 million loss for fiscal 2004 to a $9.2 million loss for fiscal 2005. When measured on a per gallon of home heating oil sold basis, the loss from service improved by 2.0 cents per gallon from 3.9 cents per gallon for fiscal 2004 to 1.9 cents for fiscal 2005.
Delivery and Branch Expenses
For fiscal 2005, delivery and branch expenses decreased $1.4 million or 0.6% to $231.6 million compared to $233.0 million of expenses incurred in fiscal 2004. Bad debt expense, credit card processing fees and collection expenses all increased, primarily due to the increase in product sales dollars. Delivery costs were also higher due to the rise in vehicle fuel costs. In total, delivery and branch expenses increased by $4.9 million due to the increase in bad debt expense, credit card processing fees, collection expenses, and fuel costs. Delivery and branch expenses also increased by approximately $5.9 million due to wage and benefit increases. These delivery and branch expense increases were offset by a reduction in operating costs due to the variable nature of certain delivery and operating expenses such as direct delivery expense, which decreased with lower volume. On a cents per gallon basis, operating costs increased 5.3 cents per gallon, or 12.6%, from 42.2 cents per gallon for fiscal 2004 to 47.5 cents per gallon for fiscal 2005. The 5.3 centcents per gallon increase was due to higher bad debt and collection expenses, wage and benefit increases, and the inability to reduce certain fixed expenses commensurate with a reduction in home heating oil volume of 11.7%.
Depreciation and Amortization
For fiscal 2005, depreciation and amortization expenses declined by $1.8 million, or 4.9%, to $35.5 million, as compared to $37.3 million for fiscal 2004 as certain assets, which were not replaced, became fully depreciated.
General and Administrative Expenses
During fiscal 2005, general and administrative expenses increased by $23.5$23.7 million, or 117.8%121.1%, to $43.4$43.2 million, compared to $19.9$19.5 million for fiscal 2004. At the partners’ level, general and administrative expenses increased $22.6 million from $3.4 million in fiscal 2004 to $26.0 million in fiscal 2005 due to $7.5 million in bridge financing fees, $4.4 million of legal expenses incurred relating to defending several purported class action lawsuits, legal and professional fees associated with exploring several refinancing alternatives, legal expense attributable to inquiries from regulatory agencies, $3.4 million of expenses and fees associated with certain bank amendments and waivers on our previous credit facility obtained during the first fiscal quarter of 2005, an increase in officers and directors insurance of $1.1 million, $4.1 million in expenses for compliance with Sarbanes-Oxley, $3.8 million in expense relating to separation agreements entered into with thecertain former Chief Executive Officer, Chief Financial Officer, and Chief Marketing Officer of the Partnership,executives and $1.7 million higher compensation expense associated with unit appreciation rights. (In fiscal 2004 and fiscal 2005, the decline in the unit price for senior subordinated units resulted in reversingthe reversal of previously recorded expenses of $3.9 million and $2.2 million, respectively.) The separation agreement with Irik Sevin, the former CEO ($3.1 million), was fully accrued during fiscal 2005 and will be paid over an extended period of time. At the heating oil segment, general and administrative expenses increased by $0.8 million, or 5.1%, to $17.4 million for the fiscal 2005, compared to $16.5 million for fiscal 2004. This increase was due primarily to $3.4 million of expenses and fees associated with certain bank amendments and waivers on our previous credit facility obtained during the first fiscal quarter of 2005, offset in part byPartially offsetting these increases were lower business process improvement expenses of $1.4 million and a reduction in compensation and benefit expense of $1.2 million.
Goodwill Impairment Charge
During the second quarter of fiscal 2005, a number of events occurred that indicated a possible impairment of goodwill might exist. These events included our determination in February 2005 of significantly lower than expected operating results for fiscal 2005 and a significant decline in the Partnership’s unit price. As a result of these triggering events and circumstances, we completed an interim SFAS No. 142 impairment review with the assistance of a third party valuation firm as of February 28, 2005. This review resulted in a non-cash goodwill impairment charge of approximately $67.0 million, which reduced the carrying amount of goodwill of the heating oil segment.
goodwill.
Operating Income (Loss)
For fiscal 2005, operating income decreased $117.6$139.2 million to a loss of $101.8$95.4 million, compared to $15.8$43.7 million in operating income for fiscal 2004. The decrease in our operating income in fiscal 2005 is the result of a $67.0 million non-cash goodwill impairment charge, as described above, lower margingross profit from the sale of petroleum products of $42.4$44.0 million, increases in general and administrative expense totaling $23.5$23.7 million and the impact of comparative change in the fair value of derivative instruments of $19.7 million offset in part by an increase in service profitability of $12.1 million, decreases in branch and delivery expenses of $1.4 million and depreciation and amortization of $1.8 million.
Interest Expense
During fiscal 2005, interest expense decreased $3.9 million, or 9.8%, to $36.2 million, compared to $40.1 million for fiscal 2004. This change was due to the impact of lower average debt outstanding offset by an increase in our weighted average interest rate during fiscal 2005. Total debt outstanding declined because a portion of the proceeds from the propane sale, were used in part to repay debt at the heating oil segment.debt. Average working capital borrowings were higher in fiscal 2005 due principally to the increase in wholesale product cost.
Interest Income
During fiscal 2005, interest income increased by $0.9 million, or 27.3%, to $4.3 million, compared to $3.4 million for fiscal 2004 due principally to higher average invested cash balances.
Amortization of Debt Issuance Costs
For fiscal 2005, amortization of debt issuance costs decreased $0.9 million, or 27.0%, to $2.5 million, compared to $3.5 million for fiscal 2004.
Loss on Redemption of Debt
During the first quarter of fiscal 2005, we recorded a loss of $42.1 million on the early redemption of certain notes at the heating oil and propane segments. The loss consisted of cash premiums paid of $37.0 million for early redemption, the write-off of previously capitalized net deferred financing costs of $6.1 million and legal expenses of $0.7 million, reduced in part by the realization of the unamortized portion of a $1.7 million basis adjustment to the carrying value of long-term debt.
Income Tax Expense (Benefit)
Income tax expense for fiscal 2005 was approximately $0.7 million compared to $1.2 million in fiscal 2004. The decrease of approximately $0.5 million is the result of increases in state capital taxes of $0.5 million in fiscal 2005, which is more than offset by $1.0 million in tax benefits that were fully utilized against taxes associated with the gain on the sale of the propane segment.
Income (Loss) From Continuing Operations
For fiscal 2005 the loss from continuing operations increased $153.3$174.9 million to a loss of $178.9$172.6 million, compared to a lossincome of $25.6$2.3 million for fiscal 2004, as the decline in operating income of $117.6$139.2 million and the loss on the redemption of debt of $42.1 million were reduced by lower interest expense of $3.9 million, higher interest income of $0.9 million, lower amortization of debt issuance costs of $0.9 million and a decrease in income tax expense of $0.5 million.
Income (Loss) From Discontinued Operations
For fiscal 2005, income from discontinued operations decreased $24.8$28.4 million. Income from the discontinued propane segment, which was sold on December 17, 2004, generated $19.4$21.3 million in net income for fiscal 2004 and a net loss of $4.6$6.2 million for fiscal 2005. The discontinued TG&E segment was sold on March 31, 2004 and generated net income of $0.9 million for fiscal 2004.
Gain on Sales of Discontinued Operations
During fiscal 2005, the purchase price for the TG&E segment was finalized and a positive adjustment of $0.8 million was recorded. In addition, during fiscal 2005, we recorded a gain on the sale of the propane segment totaling approximately $156.8 million, which is net of income taxes of $1.3 million.
The purchase price for the TG&E segment was also finalized in fiscal 2005 and a positive adjustment of $0.8 million was recorded.
Net loss
For fiscal 2005, the net loss increased $20.0$45.2 million to a net loss of $25.9$21.2 million, compared to a net lossincome of $5.9$24.0 million incurred in fiscal 2004, as the decline in operating income (loss) from continuing operations of $153.3$174.9 million, and the reduction in income from discontinued operations of $24.8$28.4 million waswere partially offset by the gain on the sale of the propane segment and TG&E segment of $157.6 million.
Earnings From Continuing Operations Before Interest, Taxes, Depreciation and Amortization (EBITDA)
For fiscal 2005, EBITDA decreased $161.5$183.1 million to an EBIDTA loss of $108.4$102.0 million, as compared to $53.1$81.1 million in EBITDA for fiscal 2004. This decreaseFor fiscal 2005, EBITDA was reduced by $67.0 due to a non-cash goodwill impairment charge of $67.0 million, the recording of aand $42.1 million due to the non cash loss onfor the early redemption of debt a reduction in gross profit of $42.4for fiscal 2005, EBITDA was favorably impacted by $6.1 million due to lower sales volume resulting from net customer attrition, conservation and lower gross profit margins from product sales, bridge facility fees, bank amendment fees, and legal fees totaling $15.3the change in the fair value of derivative instruments. For fiscal 2004, EBITDA was favorably impacted by $25.8 million $3.8 milliondue to the change in compensation expense relating to severance agreements with former executives, and $4.1 million for compliance with Sarbanes-Oxley, offset in part by a $12.1 million increase in service profitability and lower branch expenses and business process improvement costs. the fair value of derivative instruments.
EBITDA should not be considered as an alternative to net income (as an indicator of operating performance) or as an alternative to cash flow (as a measure of liquidity or ability to service debt obligations), but provides additional information for evaluating our ability to make the minimum quarterly distribution. EBITDA is calculated for the fiscal years ended September 30 as follows:
Fiscal Year Ended September 30, | Fiscal Year Ended September 30, | |||||||||||||||
(in thousands)
| 2004 | 2005 | 2005 | 2004 | ||||||||||||
(restated) | (restated) | |||||||||||||||
Loss from continuing operations | $ | (25,601 | ) | $ | (178,936 | ) | $ | (172,580 | ) | $ | 2,335 | |||||
Plus: | ||||||||||||||||
Income tax expense | 1,240 | 696 | 696 | 1,240 | ||||||||||||
Amortization of debt issuance costs | 3,480 | 2,540 | 2,540 | 3,480 | ||||||||||||
Interest expense, net | 36,682 | 31,838 | 31,838 | 36,682 | ||||||||||||
Depreciation and amortization | 37,313 | 35,480 | 35,480 | 37,313 | ||||||||||||
EBITDA | 53,114 | (108,382 | ) | (102,026 | ) | 81,050 | ||||||||||
Add/(subtract) | ||||||||||||||||
Income tax expense | (1,240 | ) | (696 | ) | (696 | ) | (1,240 | ) | ||||||||
Interest expense, net | (36,682 | ) | (31,838 | ) | (31,838 | ) | (36,682 | ) | ||||||||
Unit compensation expense (income) | (4,382 | ) | (2,185 | ) | (2,185 | ) | (4,382 | ) | ||||||||
Provision for losses on accounts receivable | 7,646 | 9,817 | 9,817 | 7,646 | ||||||||||||
Gain on sales of fixed assets, net | (281 | ) | (43 | ) | (43 | ) | (281 | ) | ||||||||
Goodwill impairment charge | — | 67,000 | 67,000 | — | ||||||||||||
Loss on redemption of debt | — | 42,082 | 42,082 | — | ||||||||||||
Loss on derivative instruments, net | 1,673 | 2,144 | ||||||||||||||
Unrealized (gains) losses on derivative contracts | (6,081 | ) | (25,811 | ) | ||||||||||||
Change in operating assets and liabilities | (6,179 | ) | (32,814 | ) | (30,945 | ) | (6,631 | ) | ||||||||
Net cash provided by (used in) operating activities | $ | 13,669 | $ | (54,915 | ) | $ | (54,915 | ) | $ | 13,669 | ||||||
Fiscal Year Ended September 30, 2004 (Fiscal 2004)LIQUIDITY AND CAPITAL RESOURCES
Compared to Fiscal Year Ended September 30, 2003 (Fiscal 2003)
Statements of Operations by Segment
Fiscal 2003(1) | Fiscal 2004(1) | |||||||||||||||||||||||
(in thousands)
| Heating Oil | Partners & Others | Consol. | Heating Oil | Partners & Others | Consol. | ||||||||||||||||||
Statements of Operations | ||||||||||||||||||||||||
Sales: | ||||||||||||||||||||||||
Product | $ | 934,967 | $ | — | $ | 934,967 | $ | 921,443 | $ | — | $ | 921,443 | ||||||||||||
Installations and service | 168,001 | — | 168,001 | 183,648 | — | 183,648 | ||||||||||||||||||
Total sales | 1,102,968 | — | 1,102,968 | 1,105,091 | — | 1,105,091 | ||||||||||||||||||
Cost and expenses: | ||||||||||||||||||||||||
Cost of product | 598,397 | — | 598,397 | 594,153 | — | 594,153 | ||||||||||||||||||
Cost of installations and service | 195,146 | — | 195,146 | 204,902 | — | 204,902 | ||||||||||||||||||
Delivery and branch expenses | 217,244 | — | 217,244 | 232,985 | — | 232,985 | ||||||||||||||||||
Depreciation & amortization expenses | 35,535 | — | 35,535 | 37,313 | — | 37,313 | ||||||||||||||||||
General and administrative | 22,356 | 17,407 | 39,763 | 16,535 | 3,402 | 19,937 | ||||||||||||||||||
Operating income (loss) | 34,290 | (17,407 | ) | 16,883 | 19,203 | (3,402 | ) | 15,801 | ||||||||||||||||
Net interest expense | 22,760 | 6,770 | 29,530 | 28,038 | 8,644 | 36,682 | ||||||||||||||||||
Amortization of debt issuance costs | 1,655 | 383 | 2,038 | 2,750 | 730 | 3,480 | ||||||||||||||||||
Gain on redemption of debt | (212 | ) | — | (212 | ) | — | — | — | ||||||||||||||||
Income (loss) from continuing operations before income taxes | 10,087 | (24,560 | ) | (14,473 | ) | (11,585 | ) | (12,776 | ) | (24,361 | ) | |||||||||||||
Income tax expense | 1,200 | — | 1,200 | 1,240 | — | 1,240 | ||||||||||||||||||
Income (loss) from continuing operations | 8,887 | (24,560 | ) | (15,673 | ) | (12,825 | ) | (12,776 | ) | (25,601 | ) | |||||||||||||
Income (loss) from discontinued operations | — | 19,786 | 19,786 | — | 20,276 | 20,276 | ||||||||||||||||||
Loss on sale of segment, net of taxes | — | — | — | — | (538 | ) | (538 | ) | ||||||||||||||||
Cumulative effect of change in accounting principle for discontinued operations adoption of SFAS No. 142 | — | (3,901 | ) | (3,901 | ) | — | — | — | ||||||||||||||||
Net income (loss) | $ | 8,887 | $ | (8,675 | ) | $ | 212 | $ | (12,825 | ) | $ | 6,962 | $ | (5,863 | ) | |||||||||
Volume
For fiscal 2004, retail volume of home heating oil decreased 15.4 million gallons, or 2.7%, to 551.6 million gallons, as compared to 567 million gallons for fiscal 2003. An analysis of the change in retail volume of home heating oil, which is based on management’s estimates, sampling, and other mathematical calculations (as actual customer consumption patterns cannot be precisely determined) is found below.
| |||
| |||
| |||
| |||
| |||
| |||
| |||
| |||
We believe that this 15.4 million gallon decline at the heating oil segment was due to the impact of warmer temperatures and net customer attrition partially offset by acquisitions and other volume changes. Net customer attrition is the difference between gross customer losses and customers added through internal marketing efforts. Customers added through acquisitions do not impact the calculation of net attrition. Temperatures in the heating oil segment’s geographic areas of operations were 7.7% warmer in fiscal 2004 than in fiscal 2003 and approximately 0.2% warmer than normal as reported by the NOAA.
At September 30, 2004, after adjusting for acquisitions, the heating oil segment estimated that it had approximately 6.4% fewer home heating oil customers than as of September 30, 2003. For the quarter ended September 30, 2004, the heating oil segment (excluding acquisitions) lost approximately 10,900 customers (net) as compared to the quarter ended September 30, 2003, in which the heating oil segment lost approximately 900 customers (net). We believe that net customer attrition is the result of various factors including but not limited to price, service and credit. The continued rise in the price of heating oil, especially during the fourth quarter of fiscal 2004, added to the heating oil segment’s difficulties in reducing customer attrition. We believe that the unprecedented rise in heating oil prices has increased the competitive pressures facing our heating oil segment. As wholesale prices have risen, many of our competitors have not raised their retail prices to fully offset the wholesale price rise. In an effort to minimize the loss of customers to price competition, we did not increase our prices to fully offset for the rise in wholesale prices, resulting in reduced margins. Nevertheless, many of our competitors appear to have succeeded in inducing some of our customers to leave through various price-related strategies.
In addition, prior to the 2004 winter heating season, we attempted to develop a competitive advantage in customer service and, as part of that effort, we experienced difficulties in centralizing our heating equipment service dispatch and engaged a centralized customer care center to respond to telephone inquiries. The implementation of that initiative has taken longer than we anticipated, impacting customer service. We believe that the rate of customer loss in fiscal 2004 was due to a combination of higher energy prices, operational and customer service problems together with the implementation of stricter customer credit requirements towards the end of fiscal 2004.
Product Sales
For fiscal 2004, product sales declined by $13.5 million, or 1.4%, to $921.4 million, as compared to $935.0 million in fiscal 2003. While warmer temperatures and customer losses at the heating oil segment led to a reduction in product sales, the decline was partially offset by an increase in product sales attributable to acquisitions and higher selling prices.
Sales, Installations and Service
For fiscal 2004, installation, service and appliance sales increased $15.6 million, or 9.3%, to $183.6 million, as compared to $168.0 million for fiscal 2003 due to acquisitions and measures taken in the last several years to increase service revenues.
Cost of Product
For fiscal 2004, cost of product declined by $4.2 million, or 0.7%, to $594.2 million, as compared to $598.4 million in fiscal 2003, as the impact of net customer attrition and warmer temperatures exceeded wholesale cost increases and the additional product requirement for acquisitions.
While selling prices and wholesale prices increased on a per gallon basis, the increase in selling prices exceeded the increase in supply costs during the first nine months of fiscal 2004. At September 30, 2004, heating oil supply costs were approximately 38% higher than at June 30, 2004. During the three months ended September 30, 2004, we were not able to fully pass these increases on to our respective customers. As a result, per gallon margins for the three months ended September 30, 2004 declined by 2.3 cents per gallon at the heating oil segment, as compared to the three months ended September 30, 2003, which partially offset per gallon margin increases that the heating oil segment experienced earlier in the year. The per gallon margins realized in the heating oil segment for the three months ended September 30, 2004 were significantly less than expected. For fiscal 2004, per gallon margin increases were realized in the base business compared to fiscal 2003 (excluding the impact of acquisitions) of 0.8 cents per gallon.
Cost of Installations, Service and Appliances
For fiscal 2004, cost of installations, service and appliances increased $9.8 million, or 5.0%, to $204.9 million in fiscal 2004, as compared to $195.1 million in fiscal 2003. This change was primarily due to acquisitions and wage and other cost increases.
Delivery and Branch Expenses
For fiscal 2004, delivery and branch expenses increased $15.7 million, or 7.2%, to $233.0 million, as compared to $217.2 million in fiscal 2003. This increase of $15.7 million was due to a higher level of fixed and variable operating costs attributable to acquisitions, (primarily those completed in eastern Pennsylvania) of $10.1 million and approximately $6.3 million due to operating and wage increases. These increases in delivery and branch expenses were partially reduced by cost reductions relating to lower volume delivered due to warmer temperatures and net customer attrition experienced in fiscal 2004. Prior to the 2004 winter heating season, we attempted to develop a competitive advantage in customer service, and as part of that effort centralized our heating equipment service dispatch functions and engaged a centralized call center to respond to telephone inquiries. Start-up challenges associated with this initiative impacted the customer base and unanticipated training and support was required. The expected savings from this initiative were less than expected.
Depreciation and Amortization
For fiscal 2004, depreciation and amortization expenses increased approximately $1.8 million, or 5%, to $37.3 million, as compared to $35.5 million for fiscal 2003. This increase was primarily due to a larger depreciable base of assets, as a result of the impact of acquisitions in fiscal 2004 and to increased depreciation resulting from the technology investment made by the heating oil segment in centralizing its customer service and dispatcher functions.
General and Administrative Expenses
For fiscal 2004, general and administrative expenses declined approximately $20 million, or 50%, to $19.9 million, as compared to $39.8 million for fiscal 2003. At the partners’ level, general and administrative expenses declined by $14.0 million from $17.4 million in fiscal 2003 to $3.4 million in fiscal 2004, due to a $10.4 million reduction in the expense for compensation earned for unit appreciation rights on the Partnership’s senior subordinated units, a $2.5 million reduction in restricted stock awards and a reduction of $1.4 million in bonus compensation expense. For fiscal 2004, partners’ expenses totaled $3.4 million, which included $2.5 million in salary expense and bonus, $4.9 million in legal and administrative costs, partially offset by a credit of $4.0 million for unit appreciation rights. For fiscal 2003, partners’ expenses totaled $17.4 million, which included $3.4 million in salary and bonus expense, $9.0 million in unit appreciation rights and restricted stock awards expense and $5.0 million in legal and administrative costs. At the heating oil segment, general and administrative expenses declined by $5.8 million, or 26.0%, to $16.5 million in fiscal 2004 from $22.4 million in fiscal 2003. This decline was due to a reduction in certain expenses relating to the heating oil segment’s centralized customer service and dispatch project of $7.0 million. The reduction in general and administrative expenses at the heating oil segment was partially offset by $1.2 million in additional expenses due to severance paid and a higher level of legal and professional expenses.
Operating Income (Loss)
For fiscal 2004, operating income decreased approximately $1.1 million, or 6.5%, to $15.8 million, as compared to $16.9 million for fiscal 2003. At the partners’ level, the operating loss decreased by $14.0 million from a $17.4 million loss in fiscal 2003 to a $3.4 million loss in fiscal 2004 due to a $10.4 million reduction in the accrual for compensation earned for unit appreciation rights on the Partnership’s senior subordinated units, lower restricted stock awards of $2.5 million and lower bonus compensation expense of $1.4 million. At the heating oil segment, operating income declined by $15.1 million, or 44.0%, to $19.2 million, as compared to $34.3 million for fiscal 2003. This decline was due to warmer temperatures of 7.7% in the heating oil segment’s geographic areas of operations in fiscal 2004 than in fiscal 2003, net customer attrition, operating and wage increases and higher depreciation and amortization expense, which were reduced in part by the operating income attributable to acquisitions, an increase in per gallon gross profit margins of the base business, lower expenses associated with the heating oil segment’s centralized customer service and dispatch project and increased service revenues.
Interest Expense
For fiscal 2004, interest expense increased $6.7 million, or 20%, to $40 million, as compared to $33.3 million for fiscal 2003. This increase was due to higher principal amount of long-term debt outstanding and an increase in the weighted average interest rate during fiscal 2004, as compared to fiscal 2003.
Amortization of Debt Issuance Costs
For fiscal 2004, amortization of debt issuance costs increased $1.4 million, or 66.7%, to $3.5 million, as compared to $2.1 million for fiscal 2003. This increase was largely due to the amortization of debt issuance costs for the Partnership’s $265.0 million senior notes offerings and for the amortization of bank fees incurred in connection with refinancing certain bank facilities.
Income Tax Expense
Income tax expense for fiscal 2004 was $1.2 million and represents certain state income taxes. The amount recorded in fiscal 2004 was unchanged from fiscal 2003.
Income (Loss) From Continuing Operations
For fiscal 2004, income (loss) from continuing operations decreased $9.9 million, to a loss of $25.6 million, as compared to a loss of $15.7 million for fiscal 2003. This decline was due to a $21.7 million decrease in income at the heating oil segment offset by $12.9 million in lower losses at the partners’ level. Income (loss) from continuing operations declined as the effects of warmer temperatures, other volume changes, including customer losses, operating and wage increases and an increase in interest expense were partially offset by the positive impacts of acquisitions, improved per gallon gross profit margins on the base business and lower compensation expenses at the partners’ level of $14.3 million in the form of unit appreciation rights, restricted stock awards and bonus expense.
Income From Discontinued Operations
For fiscal 2004, income from discontinued operations increased $0.5 million from $19.8 million in 2003 to $20.3 million in 2004. This income relates to the operating results of the TG&E segment that was sold on March 31, 2004 and the propane segment sold on December 17, 2004. Net income attributable to the TG&E segment decreased $0.3 million and net income attributable to the propane segment increased $0.8 million. The TG&E segment includes operations for six months of the fiscal year ended September 30, 2004 and the propane segment includes operations for the entire 2004 fiscal year. Propane segment sales increased approximately $70 million, operating income decreased approximately $1.5 million, and net income increased approximately $0.8 million. The increase in sales is attributable to higher selling prices due to the higher wholesale cost of propane and to a lesser extent an increased customer base resulting from acquisitions. The decrease in operating income is principally due to higher product costs as a result of the higher wholesale cost of propane.
Loss On Sale of TG&E Segment
For fiscal 2004, we recorded a $0.5 million loss on the sale of the TG&E segment. TG&E was sold in March 2004.
Cumulative Effect of Change in Accounting Principle
For fiscal 2003, we recorded a $3.9 million charge arising from the adoption of Statement No. 142 to reflect the impairment of its goodwill for TG&E.
Net Income (loss)
For fiscal 2004, net income (loss) decreased $6.1 million, to a loss of $5.9 million, as compared to $0.2 million in income for fiscal 2003. The change was due to a $9.9 million decrease in income from continuing operations, a $0.5 million increase in income from discontinued operations and the $0.5 million loss on the sale of TG&E. Net income was also impacted by the adoption of SFAS No. 142, which resulted in a charge of $3.9 million in fiscal 2003.
Liquidity and Capital Resources
Our ability to satisfy our obligations will dependdepends 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 wholesale heating oil prices to customers, the effects of high net customer attrition, conservation and other factors, most of which are beyond our control. See “Risk Factors”.Item 1A—“Risk Factors.” Capital requirements, at least in the near term, are expected to be provided by cash flows from operating activities, cash on hand at September 30, 20052006 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.
DISCUSSION OF CASH FLOWS
Operating Activities
For fiscal 2006, cash provided by operating activities was $18.4 million, as compared to cash used in operating activities of $54.9 million for fiscal 2005. The change of $73.3 million was largely due to an increase in operating income of $5.2 million (before the non cash goodwill impairment charge of $67.0 million recorded in June 2005) and lower cash requirements to finance accounts receivable of $10.0 million. During fiscal 2006, the increase in accounts receivable was $3.8 million or $10.0 million less than the comparable increase in accounts receivable at September 30, 2005 of $13.8 million, as the increase in sales of $37.0 million in fiscal 2006 over fiscal 2005 was $117.4 million less than the increase experienced in fiscal 2005 of $154.4 million compared to fiscal 2004. Generally, accounts receivable collections in fiscal 2006 were favorably impacted by warmer temperatures, which resulted in lower sales of $104.1 million. Net cash used in operating activities on a comparable basis was negatively impacted by $5.6 million primarily due to an increase in the quantity of home heating oil on hand at September 30, 2006 versus September 30, 2005. During the fourth quarter of fiscal 2006, we increased our quantity of home heating oil inventory on hand to take advantage of favorable prices in the spot delivery and futures markets. As a result, at September 30, 2006 inventory increased by 11.2 million gallons to 32.5 million gallons as compared to September 30, 2005.
Investing Activities
During fiscal 2006, we spent $5.4 million for fixed assets and received $2.2 million from the utilizationsale of the Excess Proceeds fromcertain fixed assets. Cash flow provided by investing activities was $467.3 million for fiscal 2005, primarily due to the sale of the propane segment for any purpose permitted by its debt instruments. We also believe that we will able to reduce our peak inventory levels, which will positively impact our liquidity. See “Recapitalization”
Operating Activities
For fiscal 2005, net cash used in operating activities was $54.9 million or $68.6 million less than net cash provided by operating activities of $13.7 million for fiscal 2004 due to the following factors. At September 30, 2005, accounts receivable (before the allowance for doubtful accounts) were $13.8 million higher than at September 30, 2004 and accounts receivable at September 30, 2004 were $6.1 million higher than at September 30, 2003 due to higher per gallon selling prices resulting from the continuing increase in the wholesale cost of home heating oil throughout this two-year period. As a result of the change in accounts receivable in fiscal 2005 when compared to fiscal 2004, cash flow from operating activities was reduced by $7.7 million. Higher per gallon wholesale heating oil costs and additional volume on hand resulted in a higher inventory balance as of September 30, 2005 than September 30, 2004 and a higher inventory balance as of September 30, 2004 than September 30, 2003. As a result, cash provided by operating activities was reduced by $8.2 million in fiscal 2005 when compared to fiscal 2004 due to the change in inventory. Operating activities were adversely impacted by the loss of trade credit. Prior to October 18, 2004, we were able to purchase a portion of our home heating oil under terms extended by suppliers, which averaged approximately two to three days. Currently, heating oil suppliers are not extending trade credit to the heating oil segment and the heating oil segment must prepay for its supply. The loss of trade credit reduced cash flow from operating activities by $11.1 million in 2005. The decline in operating income of $117.6 million described elsewhere in this report (which included a non-cash impairment charge of $67.0 million and approximately $19.4 million in costs associated with legal and professional fees in connection with class action lawsuits, compliance with Sarbanes-Oxley, bank refinancing and bank fees) contributed to the decline in cash from operating activities.
Investing Activities
During fiscal 2005, we completed the sale of the propane segment. The net proceeds, after deducting expenses, were approximately $466.4 million. In addition, we also finalized the sale of TG&E and recorded an additional $0.8 million in proceeds. During fiscal 2005, the heating oil segment spent $3.2 million for capital expenditures and received proceeds from the sale of certain assets of $3.4 million. As a result, cash flow provided by investing activities was $467.4 million. For fiscal 2004, cash flows provided by investing activities were $6.4 million as the heating oil segment received $1.5 million from the sale of certain assets, spent $4.0 million for capital expenditures, completed acquisitions totaling $3.5 million and received $12.5 million in cash from the sale of the TG&E segment.
December 2004.
Financing Activities
For fiscal 2006, cash flows used in financing activities were $23.1 million, as the $50.2 million (net of expenses) raised in our recapitalization along with $46.3 million borrowed under our revolving credit facility, was used to repay $52.9 million previously borrowed under the revolving credit facility, repay long-term debt of $66.1 million, and pay $0.6 million to amend our bank facility. Cash flows used in financing activities were $306.7 million for fiscal 2005. During this period,fiscal 2005, $292.2 million of cash was provided from borrowings under the heating oil segment’sour new revolving credit facility ($181.2 million) and previous credit facility ($111.0 million), which werewas used to repay $119.0 million borrowed under our previous credit facilityagreement and $174.6 million borrowed under ourthe new credit facility.agreement. Also, during fiscal 2005, we repaid $259.6$259.5 million in long-term debt, paid $37.7 million in debt prepayment premiums and expenses and paid $8.0 million in fees and expenses related to refinancing the heating oil segment’s newour bank credit facilities.
As a result of the above activity, and $11.4 million of cash useddecreased by discontinued operations, cash increased by $94.5$8.0 million, to $99.1$91.1 million as of September 30, 2005.2006.
Financing and Sources of LiquidityFINANCING AND SOURCES OF LIQUIDITY
We had $268.2 million of debt outstanding as of September 30, 2005 (excluding working capital borrowings of $6.6 million). The following summarizes our long-term debt maturities occurring over the next five years as of September 30, 2005:
(in millions) | |||
2006 | $ | 0.8 | |
2007 | $ | 0.1 | |
2008 | $ | — | |
2009 | $ | — | |
2010 | $ | — | |
Thereafter | $ | 267.3 |
On December 17, 2004, we entered into a $260 millionhave an asset based revolving credit facility with a group of lenders, led by JP Morgan Chase Bank, which was amended in November 2005. The revolving credit facility provides the heating oil segmentus with the ability to borrow up to $260 million for working capital purposes (subject to certain borrowing base limitations and coverage ratios) including the issuance of up to $75$95 million in letters of credit. From December through March of each year, the heating oil segmentwe can borrow up to $310.0 million. Obligations under the revolving credit facility are secured by liens on substantially all of theour assets of the heating oil segment, including accounts receivable, inventory, general intangibles, real property, fixtures and equipment.
On December 28, 2006, the Partnership obtained a waiver from the lender group which extended the date for the delivery of financial statements for fiscal 2006 to February 15, 2007.
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 $25.0 million or a fixed charge coverage ratio (as defined in the credit agreement) of not less than 1.1 to 1.0. As of September 30, 2005,2006, availability was $74.6$140.2 million and the fixed charge coverage ratio (as defined in the credit agreement) was 0.562.65 to 1.0. This $25 million represents a reduction in availability. We do not anticipate maintaining a fixed charge coverage ratio of 1.1 to 1.0 or greater in the foreseeable future.
In December 2004, we completed the sale of our propane segment. Pursuant to the terms of the indenture relating to the MLP Notes, we are permitted, within 360 days of the sale, to apply the Net Proceeds to a Permitted Use. To the extent there are any Excess Proceeds, the indenture requires the Partnership to make an offer to all holders of MLP Notes to purchase for cash that number of MLP Notes that may be purchased with Excess Proceeds at a purchase price equal to 100% of the principal amount of the MLP Notes plus accrued and unpaid interest to the date of purchase.
After repayment of certain debt and transaction expenses and estimated taxes paid of $1.0 million, the Net Proceeds from the propane segment sale were approximately $156.3 million. As of September 30, 2005, the heating oil segment had utilized $53.12006, $52.3 million in letters of such Net Proceedscredit were outstanding, primarily for current and future insurance reserves. For fiscal 2007, we expect to investfree-up $7 million in working capital assets, purchase capital assetscash by issuing an additional $4.0 million in letters of credit in connection with our insurance program and repay long-term debt, which reduced the amountby issuing very short-term duration (2-5 days) letters of Net Proceeds in excess of $10 million not applied toward a permitted usecredit from time to $93.2 million as of September 30, 2005. At September 30, 2005, the amount of Excess Proceeds totaled $93.2 million. As of December 2, 2005 all Excess Proceeds were applied toward a Permitted Use. See “Management’s Discussion and Analysis of Financial Condition on Results of Operations—Summary of Significant Events and Developments—MLP Notes.”time to finance our inventory purchases.
As of September 30, 2005 total liquidity resources including proceeds from the sale of the propane segment, were $148.8 million. Total liquidity resources reflect the availability of $74.6 million, less minimum availability of $25.0 million, plus cash of $99.2 million, subject to the requirements of the indenture for the MLP Notes. We expect total liquidity resources to decline throughDuring the first and second quartershalf of fiscal 2006, as we fund working capital requirements for the heating oil season. As we have indicated, we are in the process of evaluating our near-term and longer-term liquidity position and capital structure.
Availability under our revolving credit facility could be significantly impacted by our current hedging strategy. We enter into various hedging arrangementspurchased futures contracts to manage the majority of our exposure to market risk related to changes in the current and future market price of home heating oil purchased for resale to our protectedfixed price customers. To a certain extent, availability must be set aside to respond to the volatile home heating oil markets. Futures contracts are marked to market on a daily basis and require an initial cash margin deposit and potentially require a daily adjustment to such cash deposit (maintenance margin). For example, assuming 64100 million gallons, based on the volume hedged under the fixed price program as of September 30, 2005, a 10 cent30-cent per gallon decline in the market value of these hedged instruments (as we experienced from time-to-time) would create an additional cash margin requirement of approximately $6.4 million, (while a 10 cent per gallon increase in market value would provide $6.4 million in available margin).$30.0 million. In this example, availability in the short-term is reduced, as we fund the margin call. This availability reduction should be temporary, as we should be able to purchase product at a later date for 1030 cents a gallon less than the anticipated strike price when the agreement with the price-protected customer was entered into. In addition, aA spike in wholesale heating oil prices could also reduce availability, as we must finance a portion of our inventory and accounts receivable with internally generated cash as the net advance for eligible accounts receivable is 85% and 40% to 80% of eligible inventory. We may also borrow up to $35 million against fixed assets and customer lists, which is reduced by $7.0 million each year over
Since the lifebeginning of the agreement. In addition, duesecond half of fiscal 2006, we have entered into forward swaps with members of our bank group to manage our current credit position,exposure to market risk for our protected-price customers rather than purchase futures contracts. These institutions have not required an initial cash margin deposit or any mark to market maintenance margin for these swaps. Any mark to market exposure is reserved against our borrowing base. As a result of this strategy, the abilitycost to execute certain over-the-counter hedging strategies, which do not require margin adjustments, has been curtailed.
At any given time, the volume hedged underfinance our price-protectedprotected-price program will be less thanreduced.
Included in our accounts receivable is $20.6 million related to the expected volume to be sold annually under this program as the renewals for this program are staggered throughout the year. For example, the hedged balance remaining at September 30, 2005 forsale of heating and air-conditioning equipment that is payable on a price protection arrangementshort-term installment basis. In July 2006, we entered into in January 2005a preferred arrangement with a financial institution that finances installations for our customers. Over time, we anticipate that these short-term installation receivables will represent approximately 25% of the customer’s annual consumption. We hedge home heating oil volume for fixed price customers at the time they renew their protected price contract. For example, if a protected price customer’s contract expires in July 2005be reduced and the customer does not renew its contract until October 2005, this customer becomes a variable price customer until the time that he/she renews their contract,both liquidity and as such there would notavailability will be a hedge in place at September 30, 2005 for the purchase of this customer’s anticipated volume usage. We would hedge the anticipated volume in October 2005 at the time of the customer’s contract renewal.
As of September 30, 2005, the accounts receivable net of allowances totaled $89.7 million, which represents an increase of $5.7 million when compared to the balance as of September 30, 2004 of $84.0 million. Our ability to collect these receivables over the upcoming months will impact our borrowing base availability, as the borrowing base, which is used to measure availability, does not include accounts receivable over 60 days past due. At September 30, 2005 accounts receivable over 60 days past due were approximately $19.8 million compared to $18.2 million as of September 30, 2004 or an increase of $1.6 million. A component of accounts receivable at September 30, 2005 represent amounts due from customers under a budget payment plan, which permits a customer to pay their annual consumption ratably over the year. As of September 30, 2005, the aggregate amount due from budget customers over 60 days past due whose billings exceeded their payments was $3.5 million, compared to $1.9 million at September 30, 2004. This increase of $1.6 million is primarily due to the increase in the per-gallon selling price of home heating oil. In addition, we have $4.4 million of accounts over 60 days past due at September 30, 2005 for certain commercial accounts, compared to $2.7 million at September 30, 2004.
increased.
Prior to October 18, 2004, we were generally able to obtain trade credit from home heating oil suppliers of twosuppliers. Since then we have been required to three business days. Since October 18, 2004, we must now prepay for most of our heating oil supply by at least two days. The losssupply. However, as a result of the recapitalization, we have received some form of trade credit has reduced availability. Availability is also negatively impacted by outstanding lettersfrom several of credit. As of September 30, 2005, $47.3 million inour suppliers and we plan to issue letters of credit have been issued, primarilyrather than prepay with cash for current and future insurance reserves. In fiscal 2006, we expect to issue an additional $6.0 million in letters of credit in connection with our insurance renewal.
inventory purchases.
For the majority of our fiscal year, the amount of cash received from customers with a budget payment plan is greater than actual billings. This amount is reflected on the balance sheet under the caption “customer credit balances.” At September 30, 2005,2006, customer credit balances aggregated $65.3$73.9 million. Generally, customer credit balances are at their low point after the end of the heating season and peak prior to the beginning of the heating season. At September 30, 2004,2005, customer credit balances were $53.9$65.3 million. During the non-heating season, cash is provided from customer credit balances to fund operating activities. If net receipts from budget customers are reduced, cash availability in the non-heating season will be reduced and we will need to borrow under the revolving credit facility to fund operations.
Before August 2006,October 2007, we must implement certain changes to ensure compliance with amended Environmental Protection Agency regulations. We currently estimate that the capital required to effectuate these requirements will range from $1.0 to $1.5 million. Annual maintenance capital expenditures are estimated to be approximately $3.0$4 to $6 million, excluding the capital requirements for environmental compliance. We have $174.2 million of long-term debt outstanding as of September 30, 2006, which includes $174.1 million of 10 1/4% senior notes due 2013.
As mentioned in Item 1. - Business Initiatives and Strategy, we plan to seek to acquire other heating oil distributors. Currently we are reviewing several acquisition candidates.
In general, the Partnership has distributed to its partners on a quarterly basis, all Available Cash . Available Cash is defined for anyDistribution Provisions
There will be no mandatory distributions of the Partnership’s fiscal quarters, as allavailable cash on hand at the end of that quarter, less the amount of cash reserves that are necessary or appropriate in the reasonable discretion of the general partner to (i) provide for the proper conduct of the business; (ii) comply with applicable law, any of its debt instruments or other agreements; or (iii) provide funds for distributionsby us to the common unitholders and the senior subordinated unitholders during the next four quarters, in some circumstances. On October 18, 2004, we announced that we would not pay a distribution on the common units. We had previously announced the suspensionholders of distributions on the senior subordinated units on July 29, 2004. The Partnership did not pay distributions on any of its outstanding units in fiscal 2005. It is unlikely that regular distributions on the common units or senior subordinated units will be resumed in the foreseeable future. While we hope to position ourself to pay some regular distribution on our common units in future years,and general partner units through the fiscal quarter ending September 30, 2008. (See Part II - Item 5. Market for Registrant’s Units and Related Matters - Partnership Distribution Provisions and Note 6. Quarterly Distribution of which there can be no assurance, it is considerably less likely that regular distributions will ever resume on the senior subordinated units because of their subordination terms and the existing arrearages on our common units. The revolving credit facility and the indenture for the MLP Notes both impose certain restrictions on our ability to pay distributions to unitholders. It is unlikely that regular distributions on the common units or senior subordinated units will be resumed in the foreseeable future. See “Recapitalization”
Available Cash)
Contractual Obligations and Off-Balance Sheet Arrangements
We have no special purpose entities or off balance sheet debt, other than operating leases entered into in the ordinary course of business, as fully disclosed in Note 14 to the consolidated financial statements.business.
Long-term contractual obligations, except for our long-term debt obligations, are not recorded in our consolidated balance sheet. Non-cancelable purchase obligations are obligations we incur during the normal course of business, based on projected needs.
The table below summarizes the payment schedule of our contractual obligations at September 30, 20052006 (in thousands):
Payments Due by Year | |||||||||||||||
Total | Less Than 1 Year | 1 - 3 Years | 3 - 5 Years | More Than 5 Years | |||||||||||
Long-term debt obligations(a) | $ | 267,417 | $ | — | $ | 95 | $ | — | $ | 267,322 | |||||
Use of Excess Proceeds | 93,161 | 93,161 | — | — | — | ||||||||||
Operating lease obligations(b) | 47,457 | 9,155 | 13,205 | 10,070 | 15,027 | ||||||||||
Purchase obligations(c) | 16,645 | 9,695 | 5,449 | 1,461 | 40 | ||||||||||
Interest obligations Senior Notes (d) | 200,324 | 27,163 | 54,325 | 54,325 | 64,511 | ||||||||||
$ | 625,004 | $ | 139,174 | $ | 73,074 | $ | 65,856 | $ | 346,900 | ||||||
Payments Due by Year | |||||||||||||||
Total | 1 Year | 2 - 3 Years | 4 - 5 Years | More Than 5 Years | |||||||||||
Long-term debt obligations(a) | $ | 174,056 | $ | — | $ | — | $ | — | $ | 174,056 | |||||
Capital lease obligations(b) | 743 | 173 | 470 | 100 | — | ||||||||||
Operating lease obligations(c) | 55,794 | 8,772 | 14,873 | 9,954 | 22,195 | ||||||||||
Purchase obligations(d) | 128,980 | 25,970 | 39,856 | 36,515 | 26,639 | ||||||||||
Interest obligations Senior Notes (e) | 115,095 | 17,707 | 35,414 | 35,414 | 26,560 | ||||||||||
Long-term liabilities reflected on the balance sheet (f) | 5,900 | 395 | 790 | 165 | 4,550 | ||||||||||
$ | 480,568 | $ | 53,017 | $ | 91,403 | $ | 82,148 | $ | 254,000 | ||||||
(a) | Excludes current maturities of long-term debt of |
(b) | Represents various third party capital leases for trucks. |
(c) | Represents various operating leases for office space, trucks, vans and other equipment from third |
Reflects 10 1 |
(f) | Reflects long-term liabilities excluding a pension accrual of approximately $21.2 million. Under current prescribed regulatory minimum funding requirements, we have satisfied the minimum funding obligations related to our pension plans for fiscal 2006 and 2007. The remaining long-term liabilities reflected on the balance sheet represent the present value of amounts due subsequent to September 30, 2006 per the separation agreement entered into with the former CEO in March 2005. At September 30, 2006, approximately $5.9 million is scheduled to be paid out to the former CEO over the term of the separation agreement as follows: (i) $395,000 per year for five years following the termination date in March 2005, and (ii) $350,000 per year for 13 years beginning with the month following the five-year anniversary of the termination date. The payments scheduled by year in the tabular presentation above, totaling $5.9 million, represents undiscounted payments and are therefore greater than the present value of these payments totaling $3.9 million at September 30, 2006, which is part of the other long-term liabilities amount on the Balance Sheet. |
Recent Accounting Pronouncements
In December 2004,July 2006, the Financial Accounting Standards Board (“FASB”) issued Financial Interpretation No. 48 “Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109.” In September 2006, the FASB issued Statement No. 123 (revised 2004), “Share-Based Payment”157 “Fair Value Measurements” and Statement No. 158 “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans.” And in September 2006, the Securities and Exchange Commission (“SFAS No. 123R”SEC”). SFAS No. 123R, which is effective for the first annual period beginning after June 15, 2005 SFAS No. 123 requires all share-based payments to employees, including grants of stock options, to be recognized in the financial statements based on their fair values. In addition, two transition alternatives are permitted at the time of adoption of this statement. Currently, we account for unit appreciation rights and other unit based compensation arrangements using the intrinsic value method under the provisions of APB 25. We will be required to adopt SFAS No. 123R effective October 1, 2005. In March 2005, the SEC issued Staff Accounting Bulletin (“SAB”) No. 107 (“SAB 107”) regarding108, “Considering the SEC’s interpretationEffects of SFAS No. 123R. We are currently evaluating the requirementsPrior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements.” (See Note 4. Summary of SFAS No. 123R and SAB 107. We have not yet determined the method of adoption or the effect of adopting SFAS No. 123R. However, we believe that of SFAS No. 123R will not have a material adverse effect on our results of operations, financial position or liquidity, upon adoption.Significant Accounting Policies – Recent Accounting Pronouncements)
In May 2005, the FASB issued Statement No. 154, “Accounting Changes and Error Corrections” (“SFAS No. 154”), which is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. We are required to adopt SFAS No. 154 in fiscal 2007. SFAS No. 154 provides guidance for and reporting of accounting changes and error corrections. It states that retrospective application, or the latest practicable date, is the required method for reporting a change in accounting principle and the reporting of a correction of an error. Our results of operations and financial condition will only be impacted following the adoption of SFAS No. 154 if we implement changes in accounting principle that are addressed by the standard or correct accounting errors in future periods.
Critical Accounting Estimates
The preparation of financial statements in conformity with Generally Accepted Accounting Principles requires management to establish accounting policies and make estimates and assumptions that affect reported amounts of assets and liabilities at the date of the Consolidated Financial Statements. Star Gas evaluates its policies and estimates on an on-going basis. The Partnership’s Consolidated Financial Statements may differ based upon different estimates and assumptions. The Partnership’s critical accounting estimates have been reviewed with the Audit Committee of the Board of Directors.
Our significant accounting policies are discussed in Note 3 to the consolidated financial statements.Consolidated Financial Statements. We believe the following are our critical accounting policies and estimates:
Goodwill and Other Intangible Assets
We calculate amortization using the straight-line method over periods ranging from five to ten years for intangible assets with definite useful lives. We use amortization methods and determine asset values based on our best estimates using reasonable and supportable assumptions and projections. We assess the useful lives of intangible assets based on the estimated period over which we will receive
benefit from such intangible assets such as historical evidence regarding customer churn rate. In some cases, the estimated useful lives are based on contractual terms. At September 30, 2005,2006, we had $82.3$61 million of net intangible assets subject to amortization. If circumstances required a change in estimated useful lives of the assets, it could have a material effect on results of operations. For example, if lives were shortened by one year, we estimate that amortization for these assets for fiscal 20052006 would have increased by approximately $2.7$2.6 million.
SFAS No. 142 requires goodwill to be assessed at least annually for impairment. These assessments involve management’s estimates of future cash flows, market trends and other factors to determine the fair value of the reporting unit, which includes the goodwill to be assessed. If the carrying amount of goodwill exceeds its implied fair value and is determined to be impaired, an impairment charge is recorded to write-down goodwill to its fair value. At September 30, 2005,2006, we had $166.5 million of goodwill. Intangible assets with finite lives must be assessed for impairment whenever changes in circumstances indicate that the assets may be impaired. Similar to goodwill, the assessment for impairment requires estimates of future cash flows related to the intangible asset. To the extent the carrying value of the assets exceeds its future undiscounted cash flows, an impairment loss is recorded based on the fair value of the asset. We test the carrying amount of goodwill annually during the fourth quarter of its fiscal year.quarter. During the second quarter of fiscal 2005, a number of events occurred that indicated a possible impairment of goodwill of the heating oil segment might exist.goodwill. These events included: the determination in February 2005 that we could expect to generate significantly lower than expected operating results for the heating oil segment for the year and a significant decline in the Partnership’s unit price. As a result of these triggering events and circumstances, we completed an interim SFAS No. 142 impairment review of the heating oil segment with the assistance of a third party valuation firm as of February 28, 2005. The evaluation utilized both an income and market valuation approach and contained reasonable assumptions and reflected management’s best estimate of projected future cash flows. This review resulted in a non-cash goodwill impairment charge of approximately $67 million, which reduced the carrying amount of goodwill of the heating oil segment.goodwill. As of August 31, 2005,2006, we performed our annual goodwill impairment valuation for its heating oil segment, with the assistance of a third party valuation firm.valuation. Based upon this analysis, we determined that there is no additional goodwill impairment as of August 31, 2005.
2006.
Depreciation of Property, Plant and Equipment
Depreciation is calculated using the straight-line method based on the estimated useful lives of the assets ranging from 1 to 40 years. Net property, plant and equipment was $50.0$42.4 million at September 30, 2005.2006. If circumstances required a change in estimated useful lives of the assets, it could have a material effect on results of operations. For example, if the remaining estimated useful lives of these assets were shortened by one year, we estimate that depreciation for fiscal 20052006 would have increased by approximately $4.2$3.6 million.
Fair Values Of Derivatives
The fair market value of all derivative instruments is recognized as an asset or liability on our balance sheet. The accounting treatment forTo the changes in fair value is dependent upon whether or not aextent that any derivative instrument is: (i) a cash flowdoes not meet the requirements of SFAS 133 to qualify for hedge or (ii) a fair value hedge, and upon whether or not the derivative qualifies as an effective hedge. Changes in the fair value of effective cash flow hedges are recognized in accumulated other comprehensive income until the hedged item is recognized in earnings. For fair value hedges, to the extent the hedge is effective there is no effect on the statement of operations asaccounting, changes in the fair value of the derivativethat derivate instrument offset changes in the fair value of the hedged item. For derivative instruments that do not qualify, or are not treated as hedge accounting, changes in fair value areis recognized currently in earnings. The Partnership is currently evaluating whether to elect hedge accounting for future periods.
The estimated fair value of our derivative instruments requires judgementjudgment on our part. We have established the fair value of our derivative instruments using estimates determined by our counterparties and subsequently evaluated them internally using established index prices and other sources. These values are based upon, among other things, future prices, volatility, time-to-maturity value and credit risk. The values we report in our financial statements change as these estimates are revised to reflect actual results, changes in market conditions, or other factors, many of which are beyond our control. In addition, other factors that can impact results of operations each period is our ability to estimate the level of correlation between changes in the fair value of our hedge instruments and those transactions being hedged (effectiveness) both at inception and on an on-going basis. The factors underlying our estimates of fair value and our assessment of correlation of our commodity hedging derivatives are impacted by actual results and changes in conditions, market and otherwise, which may be beyond our control.
Defined Benefit Obligations
SFAS No. 87, “Employers’ Accounting for Pensions” as amended by SFAS No. 132 “Employers Disclosure about Pensions and Other Postretirement Benefits” requires the Partnership to make assumptions as to the expected long-term rate of return that could be achieved on defined benefit plan assets and discount rates to determine the present value of the plans’ pension obligations. The Partnership evaluates these critical assumptions at least annually.
The discount rate enables the Partnership to state expected future cash flows at a present value on the measurement date. The rate is required to represent the market rate for high-quality fixed income investments. A lower discount rate increases the present value of benefit obligations and increases pension expense. A 25 basis point decrease in the discount rated used for fiscal 20052006 would have
increased pension expense by approximately $0.1 million and would have increased the minimum pension liability by another $1.6$1.7 million. The discount rate used to determine net periodic pension expense was 5.5% in 20052006 and 6.0% in 20032005 and 2004. The discount rate used by the Partnership in determining pension expense andend of year pension obligations reflectswas 5.75% in 2006, 5.5% in 2005 and 6.0% in 2004. These rates reflect the yield of high quality (AA or better rating by a recognized rating agency) corporate bonds whose cash flows are expected to match the timing and amounts of future benefit payments. The discount rates to determine net periodic expense used in each of 2003 and 2004 (6.0%) and 2005 (5.50%) reflect the decline in applicable bond yields over the past year.
We consider the current and expected asset allocations, as well as historical and expected returns on various categories of plan assets to determine our expected long-term rate of return on pension plan assets. The expected long-term rate of return on assets is developed with input from the Partnership’s qualified actuaries. The long-term rate of return assumption used for determining net periodic pension expense for fiscals 20042006 and 2005 was 8.25%. A further 25 basis point decrease in the expected return on assets would have increased pension expense in fiscal 20052006 by approximately $0.1 million.
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, 2005, $19.82006, $21.2 million of unrecognized losses remain to be recognized by the plans. These losses may result in increases in future pension expense as they are recognized.
Allowance for Doubtful Accounts
We periodically review past due customer accounts receivable balances. After giving consideration to economic conditions, overdue status and other factors, the heating oil segment establishes an allowance for doubtful accounts, which it deems sufficient to cover future potential losses. Actual losses could differ from management’s estimates; however, based on historical experience, we do not expect our estimate of uncollectible accounts to vary significantly from actual losses.
Insurance Reserves
We currently self-insure a portion of workers’ compensation, auto and general liability claims. We establish reserves based upon expectations as to what our ultimate liability may be for outstanding claims using developmental factors based upon historical claim experience. We periodically evaluate the potential for changes in loss estimates with the support of qualified actuaries. As of September 30, 2005,2006, we had approximately $33.8$38.8 million of insurance reserves. The ultimate resolution of these claims could differ materially from the assumptions used to calculate the reserves, which could have a material adverse effect on results of operations.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
ITEM 7A. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
We are exposed to interest rate risk primarily through our bank credit facilities. We utilize these borrowings to meet our working capital needs.
During fiscal 2006, our average working capital borrowing was $9.7 million and the maximum borrowed was $47 million in January 2006.
At September 30, 2005,2006, we had outstanding borrowings totaling $274.8$ 174.2 million, none of which approximately $6.6 million is subject to variable interest rates under our bank credit facilities. In the event that interest rates associated with these facilities were to increase 100 basis points, the impact on future cash flows would be a decrease of less than $0.1 million.
rates.
We also selectively 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. Consistent with the nature of hedging activity, associated unrealized gains and losses would be offset by corresponding decreases or increases in the purchase price we would pay for the home heating oil being hedged. Sensitivity analysis is a technique used to evaluate the impact of hypothetical market value changes. Based on a hypothetical ten percent increase in the cost of product at September 30, 2005,2006, the potential impact on our hedging activity would be to increase the fair market value of these outstanding derivatives by $20.6$7.0 million to a fair market value of $55.7$(2.6) million; and conversely a hypothetical ten percent decrease in the cost of product would decrease the fair market value of these outstanding derivatives by $19.8$7.2 million to a fair market value of $15.3$(16.8) million.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
ITEM 8. | FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA |
The financial statements and financial statement schedules referred to in the index contained on page F-1 of this report are incorporated herein by reference.
ITEM 9. | CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE |
NONE
NONE
ITEM 9A. CONTROLS AND PROCEDURES
ITEM 9A. | CONTROLS AND PROCEDURES |
(a) | Evaluation of disclosure controls and procedures. |
The General Partner’s principal executive officer and its principal financial officer evaluated the effectiveness of the Partnership’s disclosure controls and procedures (as that term is defined in Rule 13a-15(e) of the Securities Exchange Act of 1934, as amended) as of the end of the period covered by this report. Based on that evaluation, such principal executive officer and principal financial officer concluded that the Partnership’s disclosure controls and procedures as of the end of the period covered by this report have been designed and are functioning effectivelySeptember 30, 2006, to provide reasonable assuranceensure that the information required to be disclosed by the Partnership in reports filed under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Based on that evaluation, such principal executive officer and principal financial officer concluded that the Partnership’s disclosure controls and procedures as of September 30, 2006 were not effective because of the material weakness in internal control over financial reporting in hedge accounting as discussed below.
(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 inis defined in Rule 13a-15(f) under the Securities Exchange Act Rules 13a-15(f).of 1934, as amended. Under the supervision of management and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework inInternal Control – IntegratedControl-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation underof internal control over financial reporting, the frameworkPartnership identified the following material weakness with regard to its accounting for certain derivative instruments inInternal Control – Integrated Framework, our accordance with Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS 133):
The Partnership did not have personnel with sufficient technical expertise related to the application of the provisions of SFAS 133. Specifically, the Partnership’s personnel lacked sufficient technical expertise to ensure compliance with the documentation requirements of SFAS 133 at inception of certain hedge relationships. This material weakness resulted in the restatement of the Partnership’s consolidated financial statements for fiscal years ended September 30, 2005 and 2004, the first, second and third quarters of fiscal 2006 and each of the quarters in fiscal 2005.
As a result of the material weakness described above, management concluded that ourthe Partnership’s internal control over financial reporting was not effective as of September 30, 2005.
2006.
Our management’s assessment of the effectiveness of our internal control over financial reporting as of September 30, 20052006 has been audited by KPMG LLP, an independent registered public accounting firm, as stated in their report which is included herein.
(c) | Change in Internal Control over Financial Reporting. |
No change in the Partnership’s internal control over financial reporting occurred during the Partnership’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect the Partnership’s internal control over financial reporting.
(d) | Other. |
The Partnership restated its financial statements for fiscal years ended September 30, 2005 and 2004 and the first, second and third quarters of fiscal 2006 and each of the quarters in fiscal 2005 because it did not comply with the initial documentation requirements of paragraph 28(a)(2) of SFAS 133 which states that a forecasted transaction shall be described with sufficient specificity such that when a specific transaction occurs, it is clear whether the specific transaction is or is not the hedged transaction. The Partnership’s initial documentation lacked this clarity as the hedging instruments for a given month could not be linked to a specific purchase during the month. In addition to not meeting the documentation requirements, the Partnership has also determined that its forward contracts did not meet the criteria as described in paragraph 65(a) of SFAS 133 which permits an entity to assume that a hedge of a forecasted purchase of a commodity with a forward contract will be highly effective and that there will be no ineffectiveness to be recognized.
The Partnership believes that its initial accounting treatment of certain derivative transactions properly reflected the intent and economics of the underlying transactions; however, the interpretations of how to apply SFAS 133 and how to adequately provide documentation for such instruments so as to qualify for hedge accounting are complex and continue to evolve. Since the initial documentation did not meet the requirements of SFAS 133 to allow certain derivative instruments to qualify for hedge accounting, any changes in the market value of these derivative instruments prior to their maturity are recorded through the Consolidated Statements of Operations rather than through Consolidated Statements of Comprehensive Income. There is no effect on consolidated cash flows, or Total Partners’ Capital.
The General Partner and the Partnership believe that a control system, no matter how well designed and operated, can not provide absolute assurance that the objectives of the control system are met, and no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the Partnership have been determined.
(e) | Remediation |
The Partnership is evaluating the accounting technical expertise requirements necessary for compliance with SFAS 133 and considering whether it will choose to apply hedge accounting in the future. Prior to applying hedge accounting in future periods, the Partnership will ensure that it has appropriate resources with sufficient technical expertise to comply with the provisions of SFAS 133 to qualify for hedge accounting.
ITEM 9B. | OTHER INFORMATION |
Not Applicable
ITEM 9B. OTHER INFORMATIONPART III
Not Applicable
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
ITEM 10. | DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT |
Partnership Management
Effective as of April 28, 2006, Star Gas LLC iswithdrew as the general partner of the Partnership. The membership interests in Star Gas LLC are owned by Audrey L. Sevin, Irik P. SevinPartnership and Hanseatic Americas, Inc. The members holding a majority of interests inKestrel Heat became the General Partner appoint the directorsgeneral partner of the General Partner. A majority of interestsPartnership, in the General Partner are currently held in the aggregate by Irik P. Sevin and his mother, Audrey L. Sevin.
On March 7, 2005, the General Partner entered into a voting trust agreement (the “Voting Trust Agreement”)accordance with Irik P. Sevin, in his capacity as a member of the General Partner, and Irik P. Sevin, Stephen Russell and Joseph P. Cavanaugh in their capacities as trustees under the Voting Trust Agreement (the “Voting Trustees”). Pursuant to the Voting Trust Agreement, Mr. Sevin transferred all of his membership interests (representing 15.6363% of the membership interests) in the General Partner to a voting trust for his benefit. Under the terms of the voting trust, these interests will be voted in accordance with the decision of a majority of the Voting Trustees. The voting trust createdunit purchase agreement. Kestrel Heat is wholly-owned by the Voting Trust Agreement terminates on the earliest of (i) March 4, 2030, unless extended by further agreement as provided by law, (ii) at any time upon the agreement of all three of the Voting Trustees and the holders of voting trust certificates representingKestrel. Kestrel appoints all of the interests indirectors of Kestrel Heat. Kestrel is a private equity investment partnership formed by Yorktown Energy Partners VI, L.P. (“Yorktown”), Paul A. Vermylen and other investors.
Kestrel Heat, as the General Partner that are being held in trust pursuant togeneral partner of the Voting Trust Agreement and (iii) the date upon which the Voting Trust Agreement is required to be terminated in order to comply with applicable law.
The General PartnerPartnership, oversees the activities of the Partnership. Unitholders do not directly or indirectly participate in the management or operation of the Partnership.Partnership or elect the directors of the general partner. The General PartnerBoard of Directors of the general partner has adopted a set of Partnership Governance Guidelines in accordance with the requirements of the New York Stock Exchange. A copy of these Guidelines is available on the Partnership’s website at www.Star-Gas.com or a copy may be obtained without charge by contacting Richard F. Ambury, (203) 328-7300.
As of December 14, 2006, Kestrel Heat and its affiliates owned an aggregate of 12,803,128 common units, representing 16.9% of the issued and outstanding common units, and Kestrel Heat owned 325,729 general partner units.
The general partner owes a fiduciary duty to the unitholders. However, theour partnership agreement of the Limited Partners contains provisions that allow the General Partnergeneral partner to take into account the interestedinterests of parties other than the Limited Partners in resolving conflict of interest, thereby limiting such fiduciary duty. Notwithstanding any limitation on obligations or duties, the General Partnergeneral partner will be liable, as the general partner of the Partnership, for all debts of the Partnership (to the extent not paid by the Partnership), except to the extent that indebtedness or other obligations incurred by the Partnership are made specifically non-recourse to the General Partner.
William P. Nicoletti, Paul Biddelman and Stephen Russell, who are neither officers nor employees of the General Partner nor directors, officers or employees of any affiliate of the General Partner, have been appointed to serve on the Audit Committee of the General Partner’s Board of Directors. The Partnership’s Board of Directors adopted an Audit Committee Charter during fiscal 2003. A copy of this charter is available on the Partnership’s website at www.Star-Gas.com. The Audit Committee has the authority to review, at the request of the General Partner, specific matters as to which the General Partner believes there may be a conflict of interest in order to determine if the resolution of such conflict proposed by the General Partner is fair and reasonable to the Partnership. Any matters approved by the Audit Committee will be conclusively deemed fair and reasonable to the Partnership, approved by all partners of the Partnership and not a breach by the General Partner of any duties it may owe the Partnership or the holders of Partnership units. In addition, the Audit Committee reviews the external financial reporting of the Partnership, selects and engages the Partnership’s independent registered public accountants and approves all non-audit engagements of the independent registered public accountants. With respect to the additional matters, the Audit Committee may act on its own initiative to question the General Partner and, absent the delegation of specific authority by the entire Board of Directors, its recommendations will be advisory.
The Board of Directors of the General Partner has adopted a set of Partnership Governance Guidelines in accordance with the requirements of the New York Stock Exchange. A copy of these Guidelines is available on the Partnership’s website at www.Star-Gas.com.
general partner.
As is commonly the case with publicly traded limited partnerships, the General Partnergeneral partner does not directly employ any of the persons responsible for managing or operating the Partnership.
Directors and Executive Officers of the General Partner
Directors are elected for one-year terms. The following table shows certain information for directors and executive officers of the general partner as of December 12, 2005:29, 2006:
Name | Age | Position | ||
Paul A. Vermylen, Jr. | 60 | Chairman, Director | ||
Joseph P. Cavanaugh | Chief Executive Officer and Director | |||
Daniel P. Donovan | President, | |||
Richard F. Ambury | Chief Financial Officer | |||
| ||||
Richard G. Oakley | Vice President and Controller | |||
Henry D. Babcock(1) | 66 | Director | ||
| Director | |||
| ||||
Bryan H. Lawrence | Director | |||
Sheldon B. Lubar | 77 | Director | ||
William P. Nicoletti(1) | 61 | Director |
Paul A. Vermylen, Jr. Mr. Vermylen has been the Chairman and a director of Kestrel Heat since April 28, 2006. Mr. Vermylen is a founder of Kestrel and has served as its President and as a manager since July, 2005. Mr. Vermylen has been employed since 1971, serving in various capacities, including as a Vice President of Citibank N.A. and Vice President-Finance of Commonwealth Oil Refining Co. Inc. Mr. Vermylen served as Chief Financial Officer of Meenan Oil Co., L.P. from 1982 until 1992 and as President of Meenan Oil Co., L.P. until 2001, when Meenan was acquired by the Partnership. Since 2001, Mr. Vermylen has pursued private investment opportunities. Mr. Vermylen serves as a director of certain non-public companies in the energy industry in which Kestrel holds equity interests including Downeast LNG, Inc., COALition Energy, LLC and Moneta Energy Services Ltd. Mr. Vermylen is a graduate of Georgetown University and has a M.B.A. from Columbia University.
Joseph P. Cavanaugh. Mr. Cavanaugh has been Chief Executive Officer and a director of Kestrel Heat since April 28, 2006. Mr. Cavanaugh was Chief Executive Officer and a director of Star Gas LLC sincefrom March 2005.2005 until April 28, 2006. From December 2004, after the sale of the Partnership’s propane segment to Inergy L.P. to March 2005, Mr. Cavanaugh was employed by Inergy L.P.to direct the transition of the business to them. From March 1999 to December 2004 Mr. Cavanaugh was Chief Executive Officer of the Partnership’s propane segment. From December 1997 to March 1999, Mr. Cavanaugh served as President and Chief Executive Officer of Star Gas Corporation, thea predecessor general partner. From October 19791969 to December 1997, Mr. Cavanaugh held various financial and management positions with Petro. Mr. Cavanaugh is a graduate of Iona College and received an MS from Pace University.
Daniel P. Donovan. Mr. Donovan has been President and Chief Operating Officer and a director of the heating oil segmentKestrel Heat since May 2004 andApril 28, 2006. Mr. Donovan was President and Chief Operating Officer of Star Gas LLC since March 2005.from May 2004 until April 28, 2006. From January 1980 to May 2004, he held various management positions with Meenan Oil Co. LP, including Vice President and General Manager. From 1971Manager from 1998 to 1980, he2004. Mr. Donovan worked for Mobil Oil.Oil Corp. from 1971 to 1980. His last position with Mobil Oil was President and General MangerManager of its heating oil subsidiary in New York City.City and Long Island. Mr. Donovan is a graduate of St. Francis College in Brooklyn, New York and received an M.B.A. from Iona College.
Richard F. Ambury. Mr. Ambury has been Senior Vice President and Chief Financial Officer, Treasurer and Secretary of Kestrel Heat since April 28, 2006. Mr. Ambury was Chief Financial Officer, Treasurer and Secretary of Star Gas LLC sincefrom May 2005.2005 until April 28, 2006. From November 2001 to May 2005, Mr. Ambury was Vice President and Treasurer of Star Gas, LLC.Gas. From March 1999 to November 2001, Mr. Ambury was Vice President of Star Gas Propane, L.P. From February 1996 to March 1999,
Mr. Ambury served as Vice President—Finance of Star Gas Corporation, the predecessor general partner. Mr. Ambury was employed by Petro from June 1983 through February 1996, where he served in various accounting/finance capacities. From 1979 to 1983, Mr. Ambury was employed by a predecessor firm of KPMG, a public accounting firm. Mr. Ambury has been a Certified Public Accountant since 1981.
1981 and is a graduate of Marist College.
Paul BiddelmanRichard G. Oakley. Mr. Oakley has been Vice President and Controller of Kestrel Heat since May 22, 2006. From September 1982 until May 2006 he held various positions with Meenan Oil Co. LP, most recently that of Controller since 1993. Mr. Oakley is a graduate of Long Island University.
Henry D. Babcock. Mr. Babcock has been a Director of Star Gas LLC since March 1999 and was a Director of Star Gas Corporation, the predecessor general partner from December 1993 to March 1999. Mr. Biddelman was a director of PetroKestrel Heat since April 28, 2006. Mr. Babcock is Chairman of Train, Babcock Advisors LLC, a privately-owned registered investment advisor. He joined the firm in 1976, became a partner in 1980 and CEO in 1999. Prior to this, he ran an affiliated venture capital company that was active the in the U.S. and abroad. Mr. Babcock is a graduate of Yale University and received an MBA from October 1994 until March 1999. Mr. Biddelman has been PresidentColumbia University. He serves on the Education Leadership Council of Hanseatic Corporation since December 1997. From April 1992 through December 1997, he was Treasurer of Hanseatic Corporation. Mr. BiddelmanSave the Children and is a director of Celadon Group, Inc., Insituform Technologies, Inc., Six Flags, Inc.the Caumsett Foundation.
William P. NicolettiC. Scott Baxter. Mr. Baxter has been Non-Executivea director of Kestrel Heat since April 28, 2006. Mr. Baxter is the Managing Partner for Green River Energy Partners, LLC, headquartered in New York City. Green River is a principal investing firm, which invests in public and private equity in energy and was founded in 2005. From 2002 to 2005, he was a founding partner of Baxter Bold & Company, a corporate energy M&A and private equity advisory firm. From 1999 through 2001, he was Head of Americas for the Global Energy Investment Banking Group of JPMorgan. From 1989 to 1999, Mr. Baxter worked for Salomon Smith Barney’s Global Energy Investment Banking Group where he was a Managing Director. Mr. Baxter holds a B.S. degree in Economics from Weber State University where he graduatedcum laude, and received an MBA degree from the University of Chicago Graduate School of Business. From 2002 to 2005 Mr. Baxter was also an adjunct professor of finance at Columbia University’s Graduate School of Business.
Bryan H. Lawrence. Mr. Lawrence has been a director of Kestrel Heat since April 28, 2006 and as a manager of Kestrel since July, 2005. Mr. Lawrence is a founder and senior manager of Yorktown, the manager of the Yorktown group of investment partnerships, which make investments in companies engaged in the energy industry. The Yorktown partnerships were formerly affiliated with the investment firm of Dillon, Read & Co. Inc., where Mr. Lawrence had been employed since 1966, serving as a Managing Director until the merger of Dillon Read with SBC Warburg in September 1997. Mr. Lawrence also serves as a director of Crosstex Energy, Inc., Hallador Petroleum Company (each a United States publicly traded company), Winstar Resources Ltd. (a Canadian public company) and certain non-public companies in the energy industry in which Yorktown partnerships hold equity interests. Mr. Lawrence also serves as a director of Crosstex Energy GP, LLC, the general partner of Crosstex Energy, L.P. (a United States publicly traded company). Mr. Lawrence is a graduate of Hamilton College and received an M.B.A. from Columbia University.
Sheldon B. Lubar. Mr. Lubar has been a director of Kestrel Heat since April 28, 2006 and a manager of Kestrel since July, 2005. Mr. Lubar has been Chairman of the Boardboard of Star GasLubar & Co. Incorporated, a private investment and venture capital firm he founded, since 1977. He was Chairman of the board of Christiana Companies, Inc., a logistics and manufacturing company, from 1987 until its merger with Weatherford International in 1995. Mr. Lubar had also been Chairman of Total Logistics, Inc., a logistics and manufacturing company until its acquisition in 2005 by SuperValu Inc. He has served as a director of Grant Prideco, Inc., an energy services company, since 2000; Weatherford International, Inc., an energy services company, since 1995; Crosstex Energy, Inc. since January 2004 and Crosstex Energy GP, LLC, since March 2005. the General Partner of Crosstex Energy, L.P. He is also a director of several private companies. Mr. Lubar holds a bachelor’s degree in Business Administration and a Law degree from the University of Wisconsin-Madison. He was awarded an honorary Doctor of Commercial Science degree from the University of Wisconsin-Milwaukee.
William P. Nicoletti. Mr. Nicoletti has been a Directordirector of Kestrel Heat since April 28, 2006. Mr. Nicoletti was the non-executive chairman of the board of Star Gas LLC sincefrom March 2005 until April 28, 2006. Mr. Nicoletti was a director of Star Gas from March 1999 until April 28, 2006 and was a Directordirector of Star Gas Corporation, the predecessor general partner from November 1995 until March 1999. He is Managing Director of Nicoletti & Company, Inc., a private investment banking firm. Mr. Nicoletti was formerly a senior officer and head of Energy Investment Banking for E. F. Hutton & Company, Inc., PaineWebber Incorporated and McDonald Investments, Inc. Mr. Nicoletti is a director of MarkWest Energy Partners, L.P., and SPI Petroleum, LLC. Mr. Nicoletti is a graduate of Seton Hall University and received an M.B.A. from Columbia University.
Meetings and Compensation of Directors
Stephen Russell has been a Director of Star Gas LLC since October 1999 and was a director of Petro from July 1996 until March 1999. He has been Chairman of the Board and Chief Executive Officer of Celadon Group, Inc., an international transportation company, since its inception in July 1986. Mr. Russell has been a member of the Board of Advisors of the Johnson Graduate School of Management, Cornell University since 1983.
Irik P. Sevin has been a Director of Star Gas LLC since March 1999. From March 1999 until March 2005 Mr. Sevin was Chairman of the Board and Chief Executive Officer of Star Gas LLC and was President from November 2003 until March 2005. From December 1993 to March 1999, Mr. Sevin served as Chairman ofDuring fiscal 2006, the Board of Directors of Star Gas Corporation, the predecessor general partner. Mr. Sevin has been a Director of Petro since its organization in October 1979,met 15 times and Chairman of the Board of Petro since January 1993 and served as President of Petro from 1979 through January 1997.
Meetings and Compensation of Directors
During fiscal 2005, the Board of Directors of Kestrel Heat met 26 times.one time. All Star Gas Directors attended each meeting except that Mr. Russellone former director did not attend two meetings. one meeting. Following its appointment as general partner, all Kestrel directors except Mr. Lubar attended the Board of Directors meeting.
Each non-management Directordirector, with the exception of Bryan Lawrence who has chosen not to receive any fees, receives an annual fee of $27,000 plus $1,500 for each regular meeting attended and $750 for each telephonic meeting attended. The Chairman of the Audit Committee receives an annual fee of $12,000 while other Audit Committees members receive an annual fee of $6,000. The Chairman of the Compensation Committee receives an annual fee of $6,000 while other non-management members of the Compensation Committee and Distribution Committee receive an annual fee of $3,000. Each member of the Audit Committee receives $1,500 for every regular meeting attended and $750 for every telephonic meeting attended. Each non-management member of the Compensation Committee and Distribution Committee receives $1,000 for each regular meeting attended and $500 for each telephonic meeting attended. In October 2004, a Special Committee of the Board of Directors was established for purposes of reviewing the sale of the propane segment. The members of this Committee received a one-time fee of $100,000 each plus $1,500 for each regular meeting attended and $750 for each telephonic meeting. See “Special Committee” below. Effective March 7, 2005 the Non-Executive Chairmannon-executive chairman of the Board receives an annual fee of $120,000.
In lieu of director fees, Messrs. Biddelman, Nicoletti and Russell each was granted 2,709 senior subordinated unit appreciation rights during fiscal 2003. Each of these directors forfeited $4,200 of director fees to obtain these rights. The Unit Appreciation Rights vested in three equal installments on October 1, 2002, October 1, 2003 and October 1, 2004. The grantee will be entitled to receive payment in cash for these UARs on October 1, 2005 (subject to deferral to a date no later than October 1, 2007) equal to the excess of the fair market value of a Senior Subordinated Unit on the respective vesting dates over the strike price of $10.70. The Partnership may elect to deliver senior subordinated units in satisfaction of this payment rather than cash, subject to complying with applicable securities regulations. These units were granted under the same program as units granted to the Chief Executive Officer and other certain named executives – see Item 11 – Executive Compensation.
Committees of the Board of Directors
Star Gas LLC’sKestrel Heat’s Board of Directors has threeone standing committees; ancommittee, the Audit Committee, a Compensation Committee and a Distribution Committee. TheIts members of each such committee are appointed by the Board of Directors for a one-year term and until their respective successors are elected. The
Audit Committee
William P. Nicoletti, Henry D. Babcock and C. Scott Baxter have been appointed to serve on the Audit Committee of the general partner’s Board of Directors. Kestrel Heat’s Board of Directors has also appointedadopted an Audit Committee Charter. A copy of this charter is available on the Partnership’s website at www.Star-Gas.com or a Specialcopy may be obtained without charge by contacting Richard F. Ambury (203)328-7300. The Audit Committee in connection withreviews the saleexternal financial reporting of the propane segment, which is discussed below.
Audit Committee
The dutiesPartnership, selects and engages the Partnership’s independent registered public accountants and approves all non-audit engagements of the independent registered public accountants. During fiscal 2006, the Audit Committee are described above under “Partnership Management.”
The current members of Star Gas met three times and the Audit Committee are William P. Nicoletti, Paul Biddelman and Stephen Russell. During fiscal 2005, the audit committeeof Kestrel Heat met 11four times. All members attended each meeting.
Members of the Audit Committee may not be employees of Star Gas LLCKestrel Heat or its affiliated companies and must otherwise meet the New York Stock Exchange and SEC independence requirements for service on the Audit Committee. The Board of Directors has determined that Messrs. Nicoletti, BiddelmanBabcock and RussellBaxter are independent directors in that they do not have any material relationships with the Partnership (either directly, or as a partner, shareholder or officer of an organization that has a relationship with the Partnership) and they otherwise meet the independence requirements of the NYSE and the SEC. The Partnership’s Board of Director’sDirectors has also determined that Mr. Biddelman, the Chairmanat least one member of the Audit Committee, Mr. Nicoletti, meets the definitionSEC criteria of an Audit Committee“audit committee financial expert under applicable SEC and NYSE regulations.
Compensation Committee
The current members of the Compensation Committee are Paul Biddelman and Stephen Russell. Mr. Russell was appointed as a member of the Compensation Committee in December 2004. Pursuant to resolutions adopted by the Board of Directors, effective as of October 1, 2003, the Chief Executive Officer has the authority to recommend (other than with respect to himself) and the Compensation Committee the authority to set: (i) the general compensation policies of the Partnership and any of the Partnership’s subsidiaries or subsidiary partnerships, its general partner or other affiliates whose cost is borne directly or indirectly by the Partnership; (ii) the terms of compensation plans and compensation levels for officers of the Partnership; (iii) the salary and bonus ranges for officers of the Partnership, including the performance criteria and target compensation on all performance-based compensation plans or programs and the specific amounts within those ranges; (iv) the terms of any equity or equity-linked securities to be granted to any employee or director of the Partnership; and (v) the accruals to be utilized in the financial statements related to such compensation.
Distribution Committee
The current members of the Distribution Committee are Irik Sevin and Paul Biddelman. The duties of the Distribution Committee are to discuss and review, and recommend to the Board of Directors, the Partnership’s distributions. During fiscal 2005, the Distribution Committee did not meet.
Special Committee
In October 2004, the Board of Directors established a special committee of two independent directors (Messrs. Nicoletti and Russell) to exercise all power and authority of the Board of Directors in examining the fairness to the nonaffiliated unitholders of the Partnership taken as a whole, of the consideration to be received by the Partnership from any sale, merger or other similar transaction involving the propane assets and business of the Partnership.
expert.”
Reimbursement of Expenses of the General Partner
The General Partnergeneral partner does not receive any management fee or other compensation for its management of Star Gas Partners.the Partnership. The General Partnergeneral partner is reimbursed for all expenses incurred on the behalf of Star Gas Partners,the Partnership, including the cost of compensation, which is properly allocable to Star Gas Partners.the Partnership. The Partnership’s partnership agreement provides that the General Partnergeneral partner shall determine the expenses that are allocable to Star Gas Partnersthe Partnership in any reasonable manner determined by the General Partnergeneral partner in its sole discretion. In addition, the General Partnergeneral partner and its affiliates may provide services to Star Gas Partnersthe Partnership for which a reasonable fee would be charged as determined by the General Partner.general partner.
Adoption of Code of Business Conduct and Ethics
The Partnership has adopted a written codeCode of ethicsBusiness Conduct and Ethics that applies to the Partnership’s officers, directors and employees. A copy of the Code of Business Conduct and Ethics is available on the Partnership’s website at www.Star-Gas.com or a copy may be obtained without charge, by contacting Richard F. Ambury, (203) 328-7300.
Non-Management Directors
The non-management directors on the Board of Directors of the general partner are Messrs. Sevin, Biddelman,Babcock, Baxter, Lawrence, Lubar, Nicoletti and Russell.Vermylen. The non-management directors have selected Mr. Nicoletti also servesVermylen to serve as the Non-Executive Chairmanlead director to chair executive sessions of the Board.non-management directors. Unitholders interested in contacting the Chairman of the Board or the non-management directors as a group may do so by contacting William P. NicolettiPaul A. Vermylen, Jr. c/o Star Gas Partners, L.P., 2187 Atlantic Street, Stamford, CT 06902.
Officer Certification Requirements
The Partnership’s chief executive officer submitted to the NYSE the CEO certification required pursuant to Section 303A 12(a) of the NYSE rules for the fiscal year ended September 30, 2004.
2005.
This annual report on Form 10-K includes as exhibits the certifications of the Partnership’s chief executive officer and chief financial officer required under Section 302 and Section 906 of the Sarbanes-Oxley Act of 2002 and the rules and regulations promulgated thereunder.
ITEM 11. EXECUTIVE COMPENSATION
ITEM 11. | EXECUTIVE COMPENSATION |
The following table sets forth the annual salary, bonuses and all other compensation awards and payouts to the Chief Executive Officer and to the named executive officers for services rendered to Star Gasthe Partnership and its subsidiaries during the fiscal years ended September 30, 2003, 20042006, 2005 and 2005.2004.
Name and Principal Position | Year | Summary Compensation Table Annual Compensation | Restricted | Long-Term Compensation | |||||||||||||||||
Salary | Bonus | Other Annual | Securities Underlying UARs | All Other | |||||||||||||||||
Irik P. Sevin, | 2005 | $ | 345,417 | $ | — | $ | 6,560,094 | (1) | $ | ||||||||||||
Director(2) | 2004 | $ | 650,000 | $ | — | $ | $65,736 | (3) | 77,419 | ||||||||||||
2003 | $ | 505,000 | (4) | $ | 985,200 | (5) | 14,600 | (6) | 77,419 | ||||||||||||
Ami Trauber, Chief Financial Officer (8) | 2005 | $ | 223,430 | $ | — | $ | 295,821 | (7) | |||||||||||||
2004 | $ | 370,800 | $ | — | $ | 12,201 | (6) | 46,452 | |||||||||||||
2003 | $ | 298,800 | (4) | $ | 272,550 | (5) | $ | 11,762 | (6) | 46,452 | |||||||||||
Joseph P. Cavanaugh, Chief Executive Officer(11) | 2005 | $ | 189,000 | $ | 1,140,894 | (9) | $ | 9,910 | (10) | ||||||||||||
2004 | $ | 267,800 | $ | — | $ | 494,169 | (10) | ||||||||||||||
2003 | $ | 267,800 | $ | 268,060 | (5) | $ | 18,768 | (10) | |||||||||||||
David A. Shinnebarger, Executive Vice President(12) | 2005 | $ | 195,983 | $ | — | $ | 250,673 | (7) | |||||||||||||
2004 | $ | 284,375 | $ | — | $ | — | 4,500 | ||||||||||||||
Daniel P. Donovan, President and Chief Operating Officer (13) | 2005 | $ | 300,000 | $ | — | $ | 21,778 | (6) | 5,000 | ||||||||||||
2004 | $ | 253,654 | $ | 85,785 | $ | 24,614 | (6) | 10,000 | |||||||||||||
Richard F. Ambury Chief Financial Officer (14) | 2005 | $ | 232,988 | $ | 100,000 | $ | 16,629 | (6) | 9,917 | ||||||||||||
2004 | $ | 222,956 | $ | — | $ | 10,034 | (6) | 9,917 | |||||||||||||
2003 | $ | 207,941 | (4) | $ | 162,550 | (5) | $ | 14,185 | (6) | 9,917 |
Name and Principal Position Joseph P. Cavanaugh, Chief Executive Officer Daniel P. Donovan, President and Chief Operating Officer Richard F. Ambury Chief Financial Officer Richard G. Oakley Vice President - Controller Year Summary Compensation Table Annual
Compensation Restricted
Stock
Awards Long-Term
Compensation Salary Bonus(1) Other
Annual
Comp. Securities
Underlying
UARs All
Other
Comp. 2006 $ 275,000 $ 220,000 $ 34,040 (3) 2005 $ 189,000 $ 1,140,894 (2) $ 9,910 (3) 2004 $ 267,800 $ — $ 494,169 (3) 2006 $ 300,000 $ 240,000 $ 12,985 (4) 2005 $ 300,000 $ — $ 21,778 (4) 5,000 2004 $ 253,654 $ 85,785 $ 24,614 (4) 10,000 2006 $ 236,333 $ 240,000 $ 12,492 (4) 2005 $ 232,988 $ 100,000 $ 16,629 (4) 9,917 2004 $ 222,956 $ — $ 10,034 (4) 9,917 2006 $ 162,730 (5) $ 50,000 $ 7,729 (4)
(1) |
(2) |
In connection with the sale of the propane segment in December 2004, the Partnership paid the segment’s then Chief Executive Officer, Joseph Cavanaugh, a bonus equal to three times Mr. Cavanaugh’s annual salary and bonus upon the successful completion of the sale. |
Mr. |
Aggregated Option/UAR Exercises in Last Fiscal Year
and Fiscal Year End Option/UAR Values
Name | Units Acquired Exercise of UARs | Value Realized | Number of 2005 | Value of at September 30, | |||||||||
Irik P. Sevin | 102,000 | (2) | $ | 286,963 | (3) | 436,019 | (U) | $ | — | ||||
Ami Trauber | 44,749 | (2) | $ | 172,182 | (3) | — | $ | — | |||||
Daniel P. Donovan | — | $ | — | 5,000 | (U) | $ | — | ||||||
Richard F. Ambury | — | $ | — | 6,612 | $ | 36,762 |
None
Long-Term Incentive Plans – Plans—Awards in Last Fiscal
None
Equity Compensation Plan Information
|
| |||||
| ||||||
| ||||||
| ||||||
None
Employment Contracts and Service Agreements
Agreement with Daniel P. Donovan
The Partnership entered into an employment agreement with Mr. Donovan effective as of May 5, 2004. Mr. Donovan’s employment agreement has a term of three years unless otherwise terminated in accordance with the employment agreement. The employment agreement provides for an annual base salary of $300,000. In addition, Mr. Donovan may earn a bonus of up to 35% of his base salary for services rendered based upon achieving certain performance criteria. Mr. Donovan is also entitled to receive 10,000 common units annually under a long-term incentive plan that is to be developed by the Partnership. The employment agreement provides for one year’s salary as severance if Mr. Donovan’s employment is terminated without cause or by Mr. Donovan for good reason.
Agreement with Joseph P. Cavanaugh
In connection with the sale of the propane segment in December 2004, the Partnership paid the segment’s then Chief Executive Officer, Joseph Cavanaugh, a bonus of $1,140,894 equal(equal to three times Mr. Cavanaugh’s annual salary and bonusbonus) upon the successful completion of the sale. Upon completion of the sale, Mr. Cavanaugh’s position was terminated by the Partnership. Mr. Cavanaugh was subsequently employed by Inergy, the entity that acquired the propane segment, from December 2004 to March 2005 as President, of its Star Gas Division. Mr. Cavanaugh was appointed as the Chief Executive Officer of Star Gas, effective as of March 7, 2005, at an annual salary of $275,000.
Agreement with Daniel P. Donovan
The Partnership entered into an employment agreement with Mr. Donovan effective as of May 5, 2004. Mr. Donovan’s employment agreement has a term of three-years ending on July 12, 2007, or unless otherwise terminated in accordance with the employment agreement. The employment agreement provides for an annual base salary of $300,000. In addition, Mr. Donovan may earn a bonus of up to 40% of his base salary for services rendered based upon achieving certain performance criteria. Mr. Donovan will also be entitled to receive 10,000 common units annually under a long-term incentive plan that is to be developed by the Partnership. The employment agreement provides for one year’s salary as severance if Mr. Donovan’s employment is terminated without cause or by Mr. Donovan for good reason.
Agreement with Richard F. Ambury
Effective May 4, 2005, Petro entered into an employment agreement with Richard F. Ambury pursuant to which Mr. Ambury will be employed by Petro for a three-year term ending on May 3, 2008. Mr. Ambury will serve as Vice President and Chief Financial Officer of both Petro and the general partner of the Partnership. The agreement provides for an annual base salary of $236,333 and a performance-based bonus of up to 35%40% of his base salary or such higher percentage as shall be applicable to Petro’s chief operating officer. In addition to the performance-based bonus, Mr. Ambury will receive a payment of $50,000 on the last day of each 12-month period during the term. If Mr. Ambury’s employment is terminated without cause or Mr. Ambury terminates his employment as a result of a material breach of this agreement by Petro,for good reason, Mr. Ambury willwould be entitled to the following severance compensation: $858,999, if the agreement is terminated prior to April 30, 2006; $572,666 if the agreement is terminated after May 1, 2006 and prior to April 30, 2007; and $286,333, if the agreement is terminated after May 1, 2007 and prior to May 3, 2008.
Agreement with Irik P. SevinRichard G. Oakley
On March 7, 2005,Effective May 22, 2006, the General Partner and Mr. Irik P. SevinPartnership entered into an employment agreement with Mr. Richard G. Oakley pursuant to which Mr. Oakley will be employed for a letter agreement and general release (the “Agreement”). In accordance with the Agreement,three-year term ending on May 21, 2009. Mr. Sevin confirmed his resignationOakley will serve as ChairmanVice President – Controller of the BoardPartnership. The agreement provides for an annual base salary of $190,000 and a performance-based bonus of up to 25% of his base salary or such higher percentage as may be applicable. If the General Partner and his resignation fromPartnership terminates Mr. Oakley’s employment as the Chief Executive Officer and President of the General Partner (and its subsidiaries) under the employment agreement between Mr. Sevin and the General Partner dated as of September 30, 2001, in each case effective immediately. Pursuant to the Agreement, Mr. Sevin will not be eligible for any benefits or compensation,reasons other than as specifically provided in the Agreement. Pursuant to the Agreement, for the 13-year period beginning with the month following the five-year anniversary of the termination date, the General Partner will provide Mr. Sevin with a retirement benefit equal to $350,000 per year.
Mr. Sevin continues to be a director of the General Partner and will provide consulting services to the Partnership for a period of five years following the termination date. Mr. Sevincause, he will be entitled to annual consulting fees of $395,000, payable in equal monthly installments. For a period of two years following the termination date, the General Partner will reimburse Mr. Sevin for all reasonable expenses incurred in maintaining an office to provide the consulting services provided that such expenses shall in no event exceed $50,000 per year. The General Partner will also provide Mr. Sevin with one administrative assistant at the same levelyear’s salary as his current assistant during this two-year period. Mr. Sevin executed a general release in favor of the Partnership, containing certain exceptions.
severance.
Agreement with Ami Trauber
On July 27, 2005, Star Gas LLC and Mr. Ami Trauber entered into an agreement, effective as July 15, 2005, in connection with the termination of his employment agreement dated as of October 15, 2001. Mr. Trauber received a payment of $92,700 representing salary in lieu of the 90 days’ notice plus six months of severance compensation equal to $185,400. In addition, the Partnership will pay the premium for Mr. Trauber’s healthcare coverage for nine months. Mr. Trauber received all amounts due and payable to him in accordance with the terms of the unit appreciation rights that were previously granted to him in 2001 and 2002.
Agreement with David Shinnebarger
Effective as of May 3, 2005, the employment of Mr. David Shinnebarger, as Chief Marketing Officer of the Partnership, was terminated. Mr. Shinnebarger was employed pursuant to an employment agreement dated as of October 17, 2003, by and between, the Partnership and Mr. Shinnebarger. In connection with the termination of this agreement, Mr. Shinnebarger received a payment of $243,750, representing salary in lieu of the 90 days’ notice plus the six months severance. In addition, the Partnership will pay the premium for Mr. Shinnebarger’s healthcare coverage for nine months.
401(k) Plan
Mr. Cavanaugh, Mr. Donovan, Mr. Ambury, and Mr. AmburyOakley are covered under a 401(k) defined contribution plan maintained by Petro. Participants in the plan may elect to contribute a sum not to exceed the lesser of 17% of a participant’s compensation or the maximum limit under the Internal Revenue Code of 1975, as amended. Under this plan, Petro makes a core contribution from 4% up to a maximum 5.5% of a participant’s compensation up to $205,000$220,000 and matches 2/3 of each amount that a participant contributes with a maximum employer match of 2%.
Management Incentive Compensation Plan
On July 20, 2006, the Board of Directors of Kestrel Heat adopted a Management Incentive Compensation Plan (the “Plan”) for the Partnership. Under the Plan, certain management employees of the Partnership and its direct and indirect subsidiaries that are selected by the Board to participate in the Plan shall be entitled to receive a pro rata share of an amount in cash up to:
To fund the benefits under the Plan, Kestrel Heat has agreed to forego receipt of up to 50% of all distributions to which it would be entitled in excess of minimum quarterly distributions. Amounts payable to management under this Plan will be treated as compensation and will reduce both EBITDA and net income. Kestrel Heat has also agreed to contribute to the Partnership, as a contribution to capital, an amount equal to the Gains Interest payable to participants in the Plan by the Partnership.
The Plan is administered by the Partnership’s Chief Financial Officer under the direction of the Board or by such other officer as the Board may from time to time direct.
In October 2006, the Board awarded 1,000 participation points in the Plan to certain officers, including the following points to the following named executive officers: Joseph Cavanaugh-233 1/3; Dan Donovan-233 1/3; and Richard Ambury-233 1/3. This would entitle each of them to receive approximately 23% of any amounts distributed under the Plan during the 2007 fiscal year.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
ITEM 12. | SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT |
The following table shows the beneficial ownership as of November 20, 2005December 14, 2006 of common units, senior subordinated units, junior subordinated 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
Except as indicated, the address of each person is c/o Star Gas Partners, L.P. at 2187 Atlantic Street, Stamford, Connecticut 06902-0011.
Common Units | Senior Subordinated Units | Junior Subordinated Units | General Partner Units(a) | |||||||||||||||||||
Name | Number | Percentage | Number | Percentage | Number | Percentage | Number | Percentage | ||||||||||||||
Star Gas LLC | — | — | % | 29,133 | * | % | — | — | % | 325,729 | 100 | % | ||||||||||
Irik P. Sevin | 33,000 | * | 300,609 | (b) | 8.8 | 53,426 | 15.5 | 325,729 | (b) | 100 | ||||||||||||
Audrey L. Sevin | 6,000 | * | 42,829 | (b) | 1.3 | 153,131 | 44.3 | 325,729 | (b) | 100 | ||||||||||||
Hanseatic Americas, Inc. | — | — | 29,133 | (b) | * | 138,807 | 40.2 | 325,729 | (b) | 100 | ||||||||||||
Paul Biddelman | — | — | 8,057 | * | — | — | — | — | ||||||||||||||
William P. Nicoletti | — | — | 5,252 | * | — | — | — | — | ||||||||||||||
Stephen Russell | — | — | 5,252 | * | — | — | — | — | ||||||||||||||
Richard F. Ambury | 2,125 | * | — | — | — | — | — | — | ||||||||||||||
Joseph P. Cavanaugh | — | — | — | — | — | — | — | — | ||||||||||||||
Daniel P. Donovan | — | — | — | — | — | — | — | — | ||||||||||||||
Ami Trauber | — | — | 44,749 | — | — | — | — | — | ||||||||||||||
All officers and directors and Star Gas LLC as a group (9 persons) | 41,125 | * | 377,615 | 9.8 | % | 206,557 | 59.8 | % | 325,729 | 100 | % | |||||||||||
Third Point Management Company, LLC(c) | 2,000,000 | 6.2 | % | |||||||||||||||||||
Dalal Street, Inc.(d) | 1,802,926 | 5.4 | % | |||||||||||||||||||
Lime Capital Management LLC(e) | 1,690,100 | 5.3 | % | |||||||||||||||||||
Atticus Capital LLC(f) | 1,749,000 | 5.4 | % |
Common Units | General Partner Units | |||||||||
Name | Number | Percentage | Number | Percentage | ||||||
Kestrel(a) | 12,803,128 | 16.90 | % | 325,729 | 100 | % | ||||
Paul A. Vermylen, Jr. | — | — | ||||||||
Joseph P. Cavanaugh | — | — | ||||||||
Daniel P. Donovan | — | — | ||||||||
Richard F. Ambury | 2,125 | * | ||||||||
Richard G. Oakley | — | — | ||||||||
Henry D. Babcock | 41,121 | * | ||||||||
C. Scott Baxter | — | — | ||||||||
Bryan H. Lawrence | — | — | ||||||||
Sheldon B. Lubar | — | — | ||||||||
William P. Nicoletti | 20,252 | * | ||||||||
All officers and directors and Kestrel Heat, LLC as a group (10 persons) | 12,866,626 | 16.98 | % | 325,729 | 100 | % | ||||
MacKay Shields, LLC(b) | 8,808,932 | 11.63 | % |
(a) |
(b) |
According to a Schedule 13G filed with the SEC on |
|
|
* | Amount represents less than 1%. |
Section 16(a) of the Securities Exchange Act of 1934 requires the General Partner’s officers and directors, and persons who own more than 10% of a registered class of the Partnership’s equity securities, to file reports of beneficial ownership and changes in beneficial ownership with the Securities and Exchange Commission (“SEC”). Officers, directors and greater than 10 percent unitholders are required by SEC regulation to furnish the General Partner with copies of all Section 16(a) forms.
Based solely on its review of the copies of such forms received by the General Partner, or written representations from certain reporting persons that no Section 16 Forms 5 were required for those persons, the General Partner believes that during fiscal 20052006 all filing requirements applicable to its officers, directors, and greater than 10 percent beneficial owners were met in a timely manner, except that Mr. Sevin filed two Form 5’s relating to gifts of 4,067 senior subordinated units in the aggregate, subsequent to the required filing dates.manner.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
ITEM 13. | CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS |
The Partnership and the General Partner have certain ongoing relationships with Petro andgeneral partner does not receive any management fee or other compensation for its affiliates. Affiliatesmanagement of the General Partner, including Petro, perform certain administrative servicesPartnership. The general partner is reimbursed for the General Partnerall expenses incurred on behalf of the Partnership, including the cost of compensation, which is properly allocable to the Partnership. Such affiliates do not receive a fee for such services, butThe Partnership’s partnership agreement provides that the general partner shall determine the expenses that are reimbursed for all direct and indirect expenses incurred in connection therewith.
On March 7, 2005, the General Partner and Audrey L. Sevin, a director and the Secretary of Star Gas, LLC, entered into a letter agreement and general release (the “Letter Agreement”). In accordance with the Letter Agreement, Ms. Sevin confirmed her resignation from employment as the Secretary of the General Partner (and its subsidiaries), effective immediately. Pursuant to a separate letter from Ms. Sevinallocable to the Partnership Ms. Sevin also agreedin any reasonable manner determined by the general partner in its sole discretion. In addition, the general partner and its affiliates may provide services to resignthe Partnership for which a reasonable fee would be charged as a member ofdetermined by the general partner.
Kestrel has the ability to elect the Board of Directors of Kestrel Heat, including Messrs. Vermylen, Lawrence and Lubar. Messrs. Vermylen, Lawrence and Lubar are also members of the General Partner, effective immediately. Pursuantboard of managers of Kestrel and, either directly or through affiliated entities, own equity interests in Kestrel. Kestrel owns all of the issued and outstanding membership interests of Kestrel Heat and KM2, LLC, a Delaware limited liability company (“M2”). Kestrel Heat and M2 purchased an aggregate of 12,722,523 common units in connection with the recapitalization.
On April 26, 2006, Mr. Vermylen contributed 50,000 common units that he owned prior to the Letter Agreement, Ms. Sevin will not be eligible for any benefits or compensation, other than as specifically provided in the Letter Agreement. The Partnership agreed to pay Ms. Sevin, as severance, 26 weeks of her base salary, payable in intervals in accordance with the Partnership’s customary payroll practices. Ms. Sevin executed a general release in favorcommencement of the Partnership, containing certain exceptions.negotiation of the recapitalization to Kestrel and an additional 30,605 common units acquired upon exercise of the rights, in exchange for additional membership interests in Kestrel. Kestrel, in turn, contributed the 80,605 common units to M2.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
ITEM 14. | PRINCIPAL ACCOUNTANT FEES AND SERVICES |
The following table represents the aggregate fees for professional audit services rendered by KPMG LLP including fees for the audit of the Partnership’s annual financial statements for the fiscal years 20042006 and 2005, and for fees billed and accrued for other services rendered by KPMG LLP (in thousands).
2004 | 2005 | 2006 | 2005 | |||||||||
Audit Fees(1) | $ | 900 | $ | 1,716 | $ | 1,540 | $ | 1,716 | ||||
Audit-Related Fees(2) | 298 | 139 | 65 | 139 | ||||||||
Audit and Audit-Related Fees | 1,198 | 1,855 | 1,605 | 1,855 | ||||||||
Tax Fees(3) | 261 | 390 | 653 | 390 | ||||||||
Total Fees | $ | 1,459 | $ | 2,245 | $ | 2,258 | $ | 2,245 | ||||
(1) | Audit fees were for professional services rendered in connection with audits and quarterly reviews of the consolidated financial statements of the Partnership, review of and preparation of consents for registration statements filed with the Securities and Exchange Commission, for review of the Partnership’s tax provision and for subsidiary statutory audits. The |
(2) | Audit-related fees were principally for audits of financial statements of certain employee benefit plans, internal controls reviews, other services related to financial accounting and reporting standards and preparation for the Partnership’s compliance with Section 404 of the Sarbanes-Oxley Act of 2002. |
(3) | Tax fees related to services for tax consultation and tax compliance. |
Audit Committee: Pre-Approval Policies and Procedures. At its regularly scheduled and special meetings, the Audit Committee of the Board of Directors considers and pre-approves any audit and non-audit services to be performed by the Partnership’s independent accountants. The Audit Committee has delegated to its chairman, an independent member of the Partnership’s Board of Directors, the authority to grant pre-approvals of non-audit services provided that the service(s) shall be reported to the Audit Committee at its next regularly scheduled meeting.
Promptly after the effective date of the Sarbanes-Oxley Act of 2002, the Audit Committee approved all non-audit services being performed at that time by the Partnership’s principal accountant. On June 18, 2003, the Audit Committee adopted its pre-approval policies and procedures. Since that date, there have been no non-audit services rendered by the Partnership’s principal accountants that were not pre-approved.
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
ITEM 15. | EXHIBITS AND FINANCIAL STATEMENT SCHEDULES |
1. Financial Statements
See “Index to Consolidated Financial Statements and Financial Statement Schedule” set forth on page F-1.
2. Financial Statement Schedule.
See “Index to Consolidated Financial Statements and Financial Statement Schedule” set forth on page F-1.
3. Exhibits.
See “Index to Exhibits” set forth on page 61the following page.
INDEX TO EXHIBITS
Exhibit Number | Incorp by Ref. to Exh. | Description | ||
3.1 | 3.1(1) | Amended and Restated Certificate of Limited Partnership | ||
4.1 | 99.1(2) | Second Amended and Restated Agreement of Limited Partnership | ||
4.2 | 99.3(3) | Amendment No. 1 to Second Amended and Restated Agreement of Limited Partnership | ||
4.3 | 99.1(3) | Amended and Restated Unit Purchase Rights Agreement dated as of July 20, 2006 | ||
10.1 | 10.21(4) | June 2000 Star Gas Employee Unit Incentive Plan† | ||
10.2 | 10.41(5) | Employment Agreement between Petro Holdings, Inc. and Daniel P. Donovan.† | ||
10.3 | 10.1(6) | Interest Purchase Agreement for the sale of the propane operations | ||
10.4 | 10.2(6) | Non-Competition Agreement with Inergy | ||
10.5 | 10.35(7) | Credit Agreement dated December 17, 2004, between Petroleum Heat and Power Co., Inc. and JPMorgan Chase Bank, N.A., Bank of America, N.A., Wachovia Bank, National Association, General Electric Capital Corporation, Citizens Bank of Massachusetts and J. P. MorganSecurities, Inc. | ||
10.6 | 99.1(8) | Amendment, dated as of November 2, 2005, to the Credit Agreement, dated as of December 17, 2004 among Petroleum Heat and Power Co., Inc. and JPMorgan Chase Bank, N.A., Bank of America, N.A., Wachovia Bank, National Association, General Electric Capital Corporation, and Citizens Bank of Massachusetts | ||
10.7 | 99.2(9) | Letter Agreement and general release dated March 7, 2005 between Star Gas Partners L.P. and Irik P. Sevin † | ||
10.8 | 10.1(10) | Employment Agreement dated May 4, 2005 between the Registrant and Richard F. Ambury† | ||
10.9 | 99.1(11) | Unit Purchase Agreement dated as of December 5, 2005 among Star Gas Partners, L.P., Star Gas LLC, Kestrel Energy Partners, LLC, Kestrel Heat, LLC and KM2, LLC | ||
10.10 | 99.2(2) | Indenture for the new senior notes | ||
10.11 | 99.3(2) | Amended and Restated Indenture for the existing senior notes | ||
10.12 | 10.60(12) | Second Amendment dated as of February 3, 2006 to Credit Agreement | ||
10.13 | 99.2(3) | Management Incentive Compensation Plan† | ||
10.14 | 99.4(3) | Form of Indemnification Agreement for Officers and Directors. | ||
10.15 | * | Approved Dealer / Contractor Agreement dated as of July 11, 2006 by and between AFC First Financial Corporation and Petro Holdings, Inc. | ||
10.16 | * | Employment Agreement dated May 17, 2006 between Star Gas Partners, L.P. and Richard G. Oakley. | ||
10.17 | * | Third Amendment dated as of October 30, 2006 to the Credit Agreement. | ||
10.18 | 99.4(13) | Form of Amendment No. 1 to Indemnification Agreement. | ||
10.19 | * | Fourth Amendment and Waiver dated as of December 28, 2006 to the Credit Agreement. | ||
14 | * | 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) | ||
31.3 | * | Certification of Chief Executive Officer, Star Gas Finance Company, pursuant to Rule 13a-14(a)/15d-14(a).(1) | ||
31.4 | * | Certification of Chief Financial Officer, Star Gas Finance Company, 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) |
INDEX TO EXHIBITS (continued)
* | Filed herewith. |
(1) | Incorporated by reference to an | ||
(2) | Incorporated by reference to an exhibit to the Registrant’s Form 8-K dated April |
(4) | Incorporated by reference to the same Exhibit to Registrant’s Quarterly Report on Form 10-Q filed with the Commission on August 10, 2000. |
(5) | Incorporated by reference to | ||
(6) | Incorporated by reference to an exhibit to the |
(7) | Incorporated by reference to an exhibit to Registrant’s Quarterly Report on Form 10-Q filed with the Commission on February 9, 2005. |
(8) | Incorporated by reference to an exhibit to the Registrant’s Current Report on Form 8-K dated November 4, 2005. |
(9) | Incorporated by reference to an exhibit to the Registrant’s Current Report on Form 8-K filed with the Commission on March 8, 2005. |
(10) | Incorporated by reference to the an |
(11) | Incorporated by reference to an | ||
(12) | Incorporated by reference to an exhibit to Registrant’s Quarterly Report on Form 10-Q filed with the Commission on February 7, 2006. |
(13) | Incorporated by reference to an exhibit to the Registrant’s Current Report on Form 8-K dated October 19, 2006. |
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the General Partner has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized:
STAR GAS PARTNERS, L.P. | ||
By: | ||
By: | /s/ JOSEPH P. CAVANAUGH | |
Joseph P. Cavanaugh | ||
Chief Executive Officer |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons in the capacities and on the date indicated:
Signature | Title | Date | ||
/s/ Joseph P. Cavanaugh Joseph P. Cavanaugh | Chief Executive Officer and Director
|
| ||
Daniel P. Donovan | President, Chief Operating Officer and Director Kestrel Heat, LLC | January 16, 2007 | ||
/s/ Richard F. Ambury Richard F. Ambury | Chief Financial Officer (Principal Financial
|
| ||
/s/ Richard Richard G. Oakley | Vice President – Controller (Principal Accounting Officer) Kestrel Heat, LLC | January 16, 2007 | ||
/s/ Paul A. Vermylen, Jr. Paul A. Vermylen, Jr. | Non-Executive Chairman of the Board and Director Kestrel Heat, LLC | January 16, 2007 | ||
/s/ Henry D. Babcock Henry D. Babcock | Director Kestrel Heat, LLC | January 16, 2007 | ||
/s/ C. Scott Baxter C. Scott Baxter | Director Kestrel Heat, LLC | January 16, 2007 | ||
/s/ Bryan H. Lawrence Bryan H. Lawrence | Director Kestrel Heat, LLC | January 16, 2007 | ||
/s/ Sheldon B. Lubar Sheldon B. Lubar | Director Kestrel Heat, LLC | January 16, 2007 | ||
/s/ William P. Nicoletti |
|
| ||
William P. Nicoletti | ||||
| Director
|
| ||
| ||||
|
|
| ||
| ||||
|
|
| ||
| January 16, 2007 |
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized:
STAR GAS FINANCE COMPANY | ||
By: | (Registrant) | |
By: | /s/ JOSEPH P. CAVANAUGH | |
Joseph P. Cavanaugh | ||
Chief Executive Officer |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons in the capacities and on the date indicated:
Signature | Title | Date | ||
/s/ JOSEPH P. CAVANAUGH Joseph P. Cavanaugh | Chief Executive Officer and Director ( Star Gas Finance Company |
| ||
| January 16, 2007 | |||
/s/ RICHARD F. AMBURY Richard F. Ambury | Chief Financial Officer (Principal Financial Star Gas Finance Company | January 16, 2007 | ||
/s/ RICHARD G. OAKLEY Richard G. Oakley | Vice President - Controller (Principal Accounting Officer) Star Gas Finance Company |
| ||
| January 16, 2007 |
STAR GAS PARTNERS, L.P. AND SUBSIDIARIES
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
AND FINANCIAL STATEMENT SCHEDULE
Page | ||||
Part II Financial Information: | ||||
Item | ||||
F-2 – F-3 | ||||
Consolidated Balance Sheets as of September 30, | F-4 | |||
F-5 | ||||
F-6 | ||||
F-7 | ||||
F-8 | ||||
F-9 | ||||
F-33 – F-35 | ||||
All other schedules are omitted because they are not applicable or the required information is shown in the consolidated financial statements or the notes therein. |
F - 1
STAR GAS PARTNERS, L.P. AND SUBSIDIARIES
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Partners of Star Gas Partners, L.P.:
We have audited the consolidated financial statements of Star Gas Partners, L.P. and Subsidiaries (the “Partnership”) as listed in the accompanying index. In connection with our audits of the consolidated financial statements, we have also audited the financial statement scheduleschedules as listed in the accompanying index. These consolidated financial statements and financial statement scheduleschedules are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these consolidated financial statements and financial statement scheduleschedules based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
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, 20042006 and 2005 and the results of their operations and their cash flows for each of the years in the three-year period ended September 30, 2005,2006, in conformity with U.S. generally accepted accounting principles. Also in our opinion, the related financial statement schedule,schedules, when considered in relation to the basic consolidated financial statements taken as a whole, presentspresent fairly, in all material respects, the information set forth therein.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Partnership’s internal control over financial reporting as of September 30, 2005,2006, based on criteria established in Internal Control – Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated December 12, 2005January 16, 2007 expressed an unqualified opinion on management’s assessment of, and an adverse opinion on the effective operation of, internal control over financial reporting.
The accompanying financial statements have been prepared assuming that the Partnership will continue as a going concern. As discussed in Note 2 to the consolidated financial statements, the Partnership must utilize all or a portion of the excess proceeds (as defined) from the sale of its propane segment to fund its working capital requirements over the next twelve months. Under the terms of the Indenture for the Partnership’s Senior Notes, such excess proceeds (as defined) are required to be offered to the holders of the Senior Notes by December 12, 2005. It is possible that the holders of the Senior Notes will not permit the use of such excess proceeds (as defined) by the Partnership to fund its working capital requirements. This factor raises substantial doubt about the Partnership’s ability to continue as a going concern. Management’s plans in regard to these matters are described in Note 21. Thefiscal 2005 and 2004 consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.
have been restated.
As discussed in Notes 3 and 9Note 8 to the consolidated financial statements, the Partnership adoptedchanged to the provisionsweighted average cost method of Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets,” as of October 1, 2002.
valuing inventory in fiscal 2006.
KPMG, LLP
Stamford, Connecticut
December 12, 2005January 16, 2007
F - 2
STAR GAS PARTNERS, L.P. AND SUBSIDIARIES
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Partners of Star Gas Partners, L.P.:
We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control over Financial Reporting appearing under Item 9A(b),that Star Gas Partners, L.P. maintaineddid not maintain effective internal control over financial reporting as of September 30, 2005,2006, because of the effect of the material weakness identified in management’s assessment, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Management of Star Gas Partners, L.P. is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Partnership’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, management’s assessmentA material weakness is a control deficiency, or combination of control deficiencies, that Star Gas Partners, L.P. maintained effective internal control over financial reporting as of September 30, 2005, is fairly stated,results in allmore than a remote likelihood that a material respects, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizationsmisstatement of the Treadway Commission (COSO). Also,annual or interim financial statements will not be prevented or detected. The following material weakness has been identified and included in our opinion, Star Gas Partners, L.P. maintained, in all material respects, effective internal control over financial reporting as of September 30, 2005, based on criteria established in Internal Control—Integrated Framework issued bymanagement’s assessment:
The Partnership did not have personnel with sufficient technical expertise related to the Committee of Sponsoring Organizationsapplication of the Treadway Commission (COSO)provisions of Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS133).
Specifically, the Partnership’s personnel lacked sufficient technical expertise to ensure compliance with the documentation requirements of SFAS 133 at inception of certain hedge relationships. This material weakness resulted in the restatement of the Partnership’s consolidated financial statements for fiscal years ended 2005 and 2004, the first, second, third quarters of 2006 and each of the quarters in fiscal 2005.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Star Gas Partners, L.P. and Subsidiaries as of September 30, 20042006 and 2005, and the related consolidated statements of operations, comprehensive income (loss), partners’ capital, and cash flows for each of the years in the three-year period ended September 30, 2005,2006. This material weakness was considered in our audit of 2006 consolidated financial statements, and this report does not affect our report dated December 12, 2005January 16, 2007, which expressed an unqualified opinion on those consolidated financial statements. Our report contains an explanatory paragraph
In our opinion, management’s assessment that Star Gas Partners, L.P. did not maintain effective internal control over financial reporting as of September 30, 2006, is fairly stated, in all material respects, based on criteria established in Internal Control—Integrated Framework issued by the Partnership mayCommittee of Sponsoring Organizations of the Treadway Commission (COSO). Also, in our opinion, because of the effect of the material weakness described above on the achievement of the objectives of the control criteria, Star Gas Partners, L.P. has not be able to fund its working capital requirements, which raises substantial doubt aboutmaintained effective internal control over financial reporting as of September 30, 2006, based on criteria established in Internal Control—Integrated Framework issued by the Partnership’s ability to continue as a going concern. The consolidated financial statements do not include any adjustments that might result fromCommittee of Sponsoring Organizations of the outcome of this uncertainty.
Treadway Commission (COSO).
KPMG LLP
Stamford, Connecticut
December 12, 2005January 16, 2007
F - 3
STAR GAS PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
Years Ended September 30, | ||||||||
(in thousands)
| 2004 | 2005 | ||||||
ASSETS | ||||||||
Current assets | ||||||||
Cash and cash equivalents | $ | 4,692 | $ | 99,148 | ||||
Receivables, net of allowance of $5,622 and $8,433, respectively | 84,005 | 89,703 | ||||||
Inventories | 34,213 | 52,461 | ||||||
Prepaid expenses and other current assets | 60,973 | 70,120 | ||||||
Current assets of discontinued operations | 50,288 | — | ||||||
Total current assets | 234,171 | 311,432 | ||||||
Property and equipment, net | 63,701 | 50,022 | ||||||
Long-term portion of accounts receivables | 5,458 | 3,788 | ||||||
Goodwill | 233,522 | 166,522 | ||||||
Intangibles, net | 103,925 | 82,345 | ||||||
Deferred charges and other assets, net | 13,885 | 15,152 | ||||||
Long-term assets of discontinued operations | 306,314 | — | ||||||
Total assets | $ | 960,976 | $ | 629,261 | ||||
LIABILITIES AND PARTNERS’ CAPITAL | ||||||||
Current liabilities | ||||||||
Accounts payable | $ | 25,010 | $ | 19,780 | ||||
Working capital facility borrowings | 8,000 | 6,562 | ||||||
Current maturities of long-term debt | 24,418 | 796 | ||||||
Accrued expenses | 65,491 | 56,580 | ||||||
Unearned service contract revenue | 35,361 | 36,602 | ||||||
Customer credit balances | 53,927 | 65,287 | ||||||
Current liabilities of discontinued operations | 50,676 | — | ||||||
Total current liabilities | 262,883 | 185,607 | ||||||
Long-term debt | 503,668 | 267,417 | ||||||
Other long-term liabilities | 24,654 | 31,129 | ||||||
Partners’ capital (deficit) | ||||||||
Common unitholders | 167,367 | 144,312 | ||||||
Subordinated unitholders | (6,768 | ) | (8,930 | ) | ||||
General partner | (3,702 | ) | (3,936 | ) | ||||
Accumulated other comprehensive income | 12,874 | 13,662 | ||||||
Total partners’ capital | 169,771 | 145,108 | ||||||
Total liabilities and partners’ capital | $ | 960,976 | $ | 629,261 | ||||
Years Ended September 30, | ||||||||
(in thousands) | 2006 | 2005 | ||||||
(restated) | ||||||||
ASSETS | ||||||||
Current assets | ||||||||
Cash and cash equivalents | $ | 91,121 | $ | 99,148 | ||||
Receivables, net of allowance of $6,532 and $8,433, respectively | 87,393 | 89,703 | ||||||
Inventories | 75,859 | 52,461 | ||||||
Fair asset value of derivative instruments | 3,766 | 35,140 | ||||||
Prepaid expenses and other current assets | 37,741 | 28,867 | ||||||
Total current assets | 295,880 | 305,319 | ||||||
Property and equipment, net | 42,377 | 50,022 | ||||||
Long-term portion of accounts receivables | 3,513 | 3,788 | ||||||
Goodwill | 166,522 | 166,522 | ||||||
Intangibles, net | 61,007 | 82,345 | ||||||
Deferred charges and other assets, net | 10,899 | 15,152 | ||||||
Long-term assets held for sale | 1,010 | — | ||||||
Total assets | $ | 581,208 | $ | 623,148 | ||||
LIABILITIES AND PARTNERS’ CAPITAL | ||||||||
Current liabilities | ||||||||
Accounts payable | $ | 21,544 | $ | 19,780 | ||||
Working capital facility borrowings | — | 6,562 | ||||||
Fair liability value of derivative instruments | 13,790 | — | ||||||
Current maturities of long-term debt | 96 | 796 | ||||||
Accrued expenses and other current liabilities | 62,651 | 56,580 | ||||||
Unearned service contract revenue | 36,634 | 36,602 | ||||||
Customer credit balances | 73,863 | 65,287 | ||||||
Total current liabilities | 208,578 | 185,607 | ||||||
Long-term debt | 174,056 | 267,417 | ||||||
Other long-term liabilities | 25,249 | 25,016 | ||||||
Partners’ capital (deficit) | ||||||||
Common unitholders | 194,818 | 175,461 | ||||||
Subordinated unitholders | — | (5,469 | ) | |||||
General partner | (293 | ) | (3,621 | ) | ||||
Accumulated other comprehensive loss | (21,200 | ) | (21,263 | ) | ||||
Total partners’ capital | 173,325 | 145,108 | ||||||
Total liabilities and partners’ capital | $ | 581,208 | $ | 623,148 | ||||
See accompanying notes to consolidated financial statements.
F - 4
STAR GAS PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
Years Ended September 30, | ||||||||||||
(in thousands, except per unit data)
| 2003 | 2004 | 2005 | |||||||||
Sales: | ||||||||||||
Product | $ | 934,967 | $ | 921,443 | $ | 1,071,270 | ||||||
Installations and service | 168,001 | 183,648 | 188,208 | |||||||||
Total sales | 1,102,968 | 1,105,091 | 1,259,478 | |||||||||
Cost and expenses: | ||||||||||||
Cost of product | 598,397 | 594,153 | 786,349 | |||||||||
Cost of installations and service | 195,146 | 204,902 | 197,430 | |||||||||
Delivery and branch expenses | 217,244 | 232,985 | 231,581 | |||||||||
Depreciation and amortization expenses | 35,535 | 37,313 | 35,480 | |||||||||
General and administrative expenses | 39,763 | 19,937 | 43,418 | |||||||||
Goodwill impairment charge | — | — | 67,000 | |||||||||
Operating income (loss) | 16,883 | 15,801 | (101,780 | ) | ||||||||
Interest expense | (33,306 | ) | (40,072 | ) | (36,152 | ) | ||||||
Interest income | 3,776 | 3,390 | 4,314 | |||||||||
Amortization of debt issuance costs | (2,038 | ) | (3,480 | ) | (2,540 | ) | ||||||
Gain (loss) on redemption of debt | 212 | — | (42,082 | ) | ||||||||
Loss from continuing operations before income taxes | (14,473 | ) | (24,361 | ) | (178,240 | ) | ||||||
Income tax expense | 1,200 | 1,240 | 696 | |||||||||
Loss from continuing operations | (15,673 | ) | (25,601 | ) | (178,936 | ) | ||||||
Income (loss) from discontinued operations, net of income taxes | 19,786 | 20,276 | (4,552 | ) | ||||||||
Gain (loss) on sales of discontinued operations, net of income taxes | — | (538 | ) | 157,560 | ||||||||
Cumulative effect of changes in accounting principles for discontinued operations - Adoption of SFAS No. 142 | (3,901 | ) | — | — | ||||||||
Net income (loss) | $ | 212 | $ | (5,863 | ) | $ | (25,928 | ) | ||||
General Partner’s interest in net income (loss) | $ | 2 | $ | (57 | ) | $ | (234 | ) | ||||
Limited Partners’ interest in net income (loss) | $ | 210 | $ | (5,806 | ) | $ | (25,694 | ) | ||||
Basic and diluted income (loss) per Limited Partner Unit: | ||||||||||||
Continuing operations | $ | (0.48 | ) | $ | (0.72 | ) | $ | (4.95 | ) | |||
Net income (loss) | $ | 0.01 | $ | (0.16 | ) | $ | (0.72 | ) | ||||
Weighted average number of Limited Partner units outstanding: | ||||||||||||
Basic | 32,659 | 35,205 | 35,821 | |||||||||
Diluted | 32,767 | 35,205 | 35,821 | |||||||||
Years Ended September 30, | ||||||||||||
(in thousands, except per unit data) | 2006 | 2005 | 2004 | |||||||||
(restated) | (restated) | |||||||||||
Sales: | ||||||||||||
Product | $ | 1,109,332 | $ | 1,071,270 | $ | 921,443 | ||||||
Installations and service | 187,180 | 188,208 | 183,648 | |||||||||
Total sales | 1,296,512 | 1,259,478 | 1,105,091 | |||||||||
Cost and expenses: | ||||||||||||
Cost of product | 825,694 | 786,302 | 592,428 | |||||||||
Cost of installations and service | 189,214 | 197,430 | 204,902 | |||||||||
Change in the fair value of derivative instruments | 45,677 | (6,081 | ) | (25,811 | ) | |||||||
Delivery and branch expenses | 205,037 | 231,581 | 232,985 | |||||||||
Depreciation and amortization expenses | 32,415 | 35,480 | 37,313 | |||||||||
General and administrative expenses | 21,673 | 43,190 | 19,537 | |||||||||
Goodwill impairment charge | — | 67,000 | — | |||||||||
Operating income (loss) | (23,198 | ) | (95,424 | ) | 43,737 | |||||||
Interest expense | (26,288 | ) | (36,152 | ) | (40,072 | ) | ||||||
Interest income | 5,085 | 4,314 | 3,390 | |||||||||
Amortization of debt issuance costs | (2,438 | ) | (2,540 | ) | (3,480 | ) | ||||||
Loss on redemption of debt | (6,603 | ) | (42,082 | ) | — | |||||||
Income (loss) from continuing operations before income taxes | (53,442 | ) | (171,884 | ) | 3,575 | |||||||
Income tax expense | 477 | 696 | 1,240 | |||||||||
Income (loss) from continuing operations | (53,919 | ) | (172,580 | ) | 2,335 | |||||||
Income (loss) from discontinued operations, net of income taxes | — | (6,189 | ) | 22,176 | ||||||||
Gain (loss) on sales of discontinued operations, net of income taxes | — | 157,560 | (538 | ) | ||||||||
Income (loss) before cumulative effect of changes in accounting principles | (53,919 | ) | (21,209 | ) | 23,973 | |||||||
Cumulative effect of changes in accounting principles — change in inventory pricing method | (344 | ) | — | — | ||||||||
Net income (loss) | $ | (54,263 | ) | $ | (21,209 | ) | $ | 23,973 | ||||
General Partner’s interest in net income (loss) | (160 | ) | (191 | ) | 221 | |||||||
Limited Partners’ interest in net income (loss) | $ | (54,103 | ) | $ | (21,018 | ) | $ | 23,752 | ||||
Basic and diluted loss per Limited Partner Unit: | ||||||||||||
Continuing operations | $ | (1.01 | ) | $ | (4.77 | ) | $ | 0.07 | ||||
Net income (loss) | $ | (1.02 | ) | $ | (0.59 | ) | $ | 0.67 | ||||
Weighted average number of Limited Partner Units outstanding: | ||||||||||||
Basic | 52,944 | 35,821 | 35,205 | |||||||||
Diluted | 52,944 | 35,821 | 35,205 | |||||||||
See accompanying notes to consolidated financial statements.
F - 5
STAR GAS PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
Years Ended September 30, | ||||||||||||
(in thousands)
| 2003 | 2004 | 2005 | |||||||||
Net income (loss) | $ | 212 | $ | (5,863 | ) | $ | (25,928 | ) | ||||
Other comprehensive income (loss): | ||||||||||||
Unrealized gain (loss) on derivative instruments | (4,930 | ) | 27,536 | 6,128 | ||||||||
Unrealized gain (loss) on pension plan obligations | (1,469 | ) | 1,159 | (3,703 | ) | |||||||
Other comprehensive income (loss) from discontinued operations | (495 | ) | 1,900 | (1,637 | ) | |||||||
Other comprehensive income (loss) | (6,894 | ) | 30,595 | 788 | ||||||||
Comprehensive income (loss) | $ | (6,682 | ) | $ | 24,732 | $ | (25,140 | ) | ||||
Years Ended September 30, | |||||||||||
(in thousands) | 2006 | 2005 | 2004 | ||||||||
(restated) | (restated) | ||||||||||
Net income (loss) | $ | (54,263 | ) | $ | (21,209 | ) | $ | 23,973 | |||
Other comprehensive income (loss): | |||||||||||
Unrealized gain (loss) on pension plan obligations | 63 | (3,931 | ) | 759 | |||||||
Comprehensive income (loss) | $ | (54,200 | ) | $ | (25,140 | ) | $ | 24,732 | |||
Reconciliation of Accumulated Other Comprehensive Income (Loss)
(in thousands)
| Pension Plan Obligations | Derivative Instruments | Total | |||||||||
Balance as of September 30, 2002 | $ | (15,745 | ) | $ | 4,918 | $ | (10,827 | ) | ||||
Reclassification to earnings | — | (7,745 | ) | (7,745 | ) | |||||||
Unrealized loss on pension plan obligations | (1,469 | ) | — | (1,469 | ) | |||||||
Unrealized gain on derivative instruments | — | 2,815 | 2,815 | |||||||||
Other comprehensive loss from discontinued operations | — | (495 | ) | (495 | ) | |||||||
Other comprehensive loss | (1,469 | ) | (5,425 | ) | (6,894 | ) | ||||||
Balance as of September 30, 2003 | (17,214 | ) | (507 | ) | (17,721 | ) | ||||||
Reclassification to earnings | — | (10,870 | ) | (10,870 | ) | |||||||
Unrealized gain on pension plan obligations | 1,159 | — | 1,159 | |||||||||
Unrealized gain on derivative instruments | — | 38,406 | 38,406 | |||||||||
Other comprehensive income from discontinued operations | — | 1,900 | 1,900 | |||||||||
Other comprehensive income | 1,159 | 29,436 | 30,595 | |||||||||
Balance as of September 30, 2004 | (16,055 | ) | 28,929 | 12,874 | ||||||||
Reclassification to earnings | — | (34,901 | ) | (34,901 | ) | |||||||
Unrealized loss on pension plan obligations | (3,703 | ) | — | (3,703 | ) | |||||||
Unrealized gain on derivative instruments | — | 41,029 | 41,029 | |||||||||
Other comprehensive loss from discontinued operations | — | (1,637 | ) | (1,637 | ) | |||||||
Other comprehensive income (loss) | (3,703 | ) | 4,491 | 788 | ||||||||
Balance as of September 30, 2005 | $ | (19,758 | ) | $ | 33,420 | $ | 13,662 | |||||
(in thousands) | Pension Plan Obligations | |||
Balance as of September 30, 2003 (restated) | $ | (18,091 | ) | |
Unrealized gain on pension plan obligations (restated) | 759 | |||
Other comprehensive income (restated) | 759 | |||
Balance as of September 30, 2004 (restated) | (17,332 | ) | ||
Unrealized loss on pension plan obligations | (3,931 | ) | ||
Other comprehensive loss (restated) | (3,931 | ) | ||
Balance as of September 30, 2005 (restated) | (21,263 | ) | ||
Unrealized gain on pension plan obligations | 63 | |||
Other comprehensive income | 63 | |||
Balance as of September 30, 2006 | $ | (21,200 | ) | |
See accompanying notes to consolidated financial statements.
F - 6
STAR GAS PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL
Years Ended September 30, 2003,2006, 2005 and 2004 and 2005
Number of Units | Common | Sr. Sub. | Jr. Sub. | General | Accum. Other | Total | ||||||||||||||||||||||||||
(in thousands, except per unit amounts)
| Common | Sr. Sub. | Jr. Sub. | General Partner | ||||||||||||||||||||||||||||
Balance as of September 30, 2002 | 28,970 | 3,134 | 345 | 326 | $ | 242,696 | $ | 4,337 | $ | (1,232 | ) | $ | (2,710 | ) | $ | (10,827 | ) | $ | 232,264 | |||||||||||||
Issuance of units | 1,701 | 8 | 34,180 | 34,180 | ||||||||||||||||||||||||||||
Net income | 189 | 20 | 1 | 2 | 212 | |||||||||||||||||||||||||||
Other comprehensive loss, net | (6,894 | ) | (6,894 | ) | ||||||||||||||||||||||||||||
Unit compensation expense | 204 | 2,402 | 2,606 | |||||||||||||||||||||||||||||
Distributions: | — | |||||||||||||||||||||||||||||||
$ 2.30 per unit | (66,633 | ) | (66,633 | ) | ||||||||||||||||||||||||||||
$ 1.65 per unit | (5,188 | ) | (5,188 | ) | ||||||||||||||||||||||||||||
$ 1.15 per unit | (397 | ) | (374 | ) | (771 | ) | ||||||||||||||||||||||||||
Balance as of September 30, 2003 | 30,671 | 3,142 | 345 | 326 | 210,636 | 1,571 | (1,628 | ) | (3,082 | ) | (17,721 | ) | 189,776 | |||||||||||||||||||
Issuance of units | 1,495 | 103 | 34,996 | 34,996 | ||||||||||||||||||||||||||||
Net loss | (5,222 | ) | (530 | ) | (54 | ) | (57 | ) | (5,863 | ) | ||||||||||||||||||||||
Other comprehensive income, net | 30,595 | 30,595 | ||||||||||||||||||||||||||||||
Unit compensation expense | 76 | 10 | 86 | |||||||||||||||||||||||||||||
Distributions: | — | |||||||||||||||||||||||||||||||
$ 2.30 per unit | (73,119 | ) | (73,119 | ) | ||||||||||||||||||||||||||||
$ 1.725 per unit | (5,540 | ) | (597 | ) | (563 | ) | (6,700 | ) | ||||||||||||||||||||||||
Balance as of September 30, 2004 | 32,166 | 3,245 | 345 | 326 | 167,367 | (4,489 | ) | (2,279 | ) | (3,702 | ) | 12,874 | 169,771 | |||||||||||||||||||
Issuance of units | 147 | 459 | 459 | |||||||||||||||||||||||||||||
Net loss | (23,073 | ) | (2,373 | ) | (248 | ) | (234 | ) | (25,928 | ) | ||||||||||||||||||||||
Other comprehensive income, net | 788 | 788 | ||||||||||||||||||||||||||||||
Unit compensation expense | 18 | 18 | ||||||||||||||||||||||||||||||
Balance as of September 30, 2005 | 32,166 | 3,392 | 345 | 326 | $ | 144,312 | $ | (6,403 | ) | $ | (2,527 | ) | $ | (3,936 | ) | $ | 13,662 | $ | 145,108 | |||||||||||||
Number of Units | |||||||||||||||||||||||||||||||||||
(in thousands, except per unit amounts) | Common | Sr. Sub. | Jr. Sub. | General Partner | Common | Sr. Sub. | Jr. Sub. | General Partner | Accum. Other Comprehensive Income (Loss) | Total Partners’ Capital | |||||||||||||||||||||||||
Balance as of September 30, 2003 | 30,671 | 3,142 | 345 | 326 | $ | 210,636 | $ | 1,571 | $ | (1,628 | ) | $ | (3,082 | ) | $ | (17,721 | ) | $ | 189,776 | ||||||||||||||||
Restatement adjustment (1) | 376 | 3 | (3 | ) | (6 | ) | (370 | ) | — | ||||||||||||||||||||||||||
Balance as of September 30, 2003 (restated) | 30,671 | 3,142 | 345 | 326 | 211,012 | 1,574 | (1,631 | ) | (3,088 | ) | (18,091 | ) | 189,776 | ||||||||||||||||||||||
Issuance of units | 1,495 | 103 | 34,996 | 34,996 | |||||||||||||||||||||||||||||||
Net income (restated) | 21,352 | 2,167 | 233 | 221 | 23,973 | ||||||||||||||||||||||||||||||
Other comprehensive income, net (restated) | 759 | 759 | |||||||||||||||||||||||||||||||||
Unit compensation expense | 76 | 10 | 86 | ||||||||||||||||||||||||||||||||
Distributions: | — | ||||||||||||||||||||||||||||||||||
$2.30 per unit | (73,119 | ) | (73,119 | ) | |||||||||||||||||||||||||||||||
$1.725 per unit | (5,540 | ) | (597 | ) | (563 | ) | (6,700 | ) | |||||||||||||||||||||||||||
Balance as of September 30, 2004 (restated) | 32,166 | 3,245 | 345 | 326 | 194,317 | (1,789 | ) | (1,995 | ) | (3,430 | ) | (17,332 | ) | 169,771 | |||||||||||||||||||||
Issuance of units | 147 | 459 | 459 | ||||||||||||||||||||||||||||||||
Net loss (restated) | (18,874 | ) | (1,943 | ) | (201 | ) | (191 | ) | (21,209 | ) | |||||||||||||||||||||||||
Other comprehensive income, net (restated) | (3,931 | ) | (3,931 | ) | |||||||||||||||||||||||||||||||
Unit compensation expense | 18 | 18 | |||||||||||||||||||||||||||||||||
Balance as of September 30, 2005 (restated) | 32,166 | 3,392 | 345 | 326 | 175,461 | (3,273 | ) | (2,196 | ) | (3,621 | ) | (21,263 | ) | 145,108 | |||||||||||||||||||||
Net income (loss) | (55,619 | ) | 1,376 | 140 | (160 | ) | (54,263 | ) | |||||||||||||||||||||||||||
Other comprehensive loss, net | 63 | 63 | |||||||||||||||||||||||||||||||||
Issuance of units (2) | 39,871 | 326 | 82,417 | 82,417 | |||||||||||||||||||||||||||||||
Exchange / retirement of units (2) | 3,737 | (3,392 | ) | (345 | ) | (326 | ) | (7,441 | ) | 1,897 | 2,056 | 3,488 | — | ||||||||||||||||||||||
Balance as of September 30, 2006 | 75,774 | — | — | 326 | $ | 194,818 | $ | — | $ | — | $ | (293 | ) | $ | (21,200 | ) | $ | 173,325 | |||||||||||||||||
(1) | See Note 2 - Restatement of Financial Information. |
(2) | See Note 3 - Recapitalization. |
See accompanying notes to consolidated financial statements.
F - 7
STAR GAS PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
Years Ended September 30, | ||||||||||||
(in thousands)
| 2003 | 2004 | 2005 | |||||||||
Cash flows provided by (used in) operating activities: | ||||||||||||
Net income (loss) | $ | 212 | $ | (5,863 | ) | $ | (25,928 | ) | ||||
Deduct: (Income) loss from discontinued operations | (19,786 | ) | (20,276 | ) | 4,552 | |||||||
(Gain) loss on sales of discontinued operations | — | 538 | (157,560 | ) | ||||||||
Add: Cumulative effect of change in accounting principles for the adoption of SFAS No. 142 for discontinued operations | 3,901 | — | — | |||||||||
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities: | ||||||||||||
Depreciation and amortization | 35,535 | 37,313 | 35,480 | |||||||||
Amortization of debt issuance cost | 2,038 | 3,480 | 2,540 | |||||||||
Loss (gain) on redemption of debt | (212 | ) | — | 42,082 | ||||||||
Loss on derivative instruments, net | 306 | 1,673 | 2,144 | |||||||||
Unit compensation expense (income) | 9,001 | (4,382 | ) | (2,185 | ) | |||||||
Provision for losses on accounts receivable | 6,601 | 7,646 | 9,817 | |||||||||
Goodwill impairment charge | — | — | 67,000 | |||||||||
Gain on sales of fixed assets, net | (52 | ) | (281 | ) | (43 | ) | ||||||
Changes in operating assets and liabilities net of amounts related to acquisitions: | ||||||||||||
Increase in receivables | (20,735 | ) | (6,178 | ) | (13,845 | ) | ||||||
Decrease (increase) in inventories | 3,155 | (10,067 | ) | (18,248 | ) | |||||||
Decrease (increase) in other assets | (13,917 | ) | 7,627 | (7,070 | ) | |||||||
Increase (decrease) in accounts payable | 7,923 | 5,832 | (5,230 | ) | ||||||||
Increase (decrease) in other current and long-term liabilities | 1,395 | (3,393 | ) | 11,579 | ||||||||
Net cash provided by (used in) operating activities | 15,365 | 13,669 | (54,915 | ) | ||||||||
Cash flows provided by (used in) investing activities: | ||||||||||||
Capital expenditures | (12,851 | ) | (3,984 | ) | (3,153 | ) | ||||||
Proceeds from sales of fixed assets | 306 | 1,462 | 3,398 | |||||||||
Cash proceeds from sale of discontinued operations | — | 12,495 | 467,186 | |||||||||
Acquisitions | (35,850 | ) | (3,526 | ) | — | |||||||
Net cash provided by (used in) investing activities | (48,395 | ) | 6,447 | 467,431 | ||||||||
Cash flows provided by (used in) financing activities: | ||||||||||||
Working capital facility borrowings | 136,000 | 128,000 | 292,200 | |||||||||
Working capital facility repayments | (153,000 | ) | (126,000 | ) | (293,638 | ) | ||||||
Acquisition facility borrowings | 50,000 | 3,000 | — | |||||||||
Acquisition facility repayments | (17,000 | ) | (36,000 | ) | — | |||||||
Proceeds from the issuance of debt | 197,333 | 70,512 | — | |||||||||
Repayment of debt | (119,668 | ) | (8,471 | ) | (259,559 | ) | ||||||
Debt extinguishment costs | — | — | (37,688 | ) | ||||||||
Distributions | (72,592 | ) | (79,819 | ) | — | |||||||
Proceeds from the issuance of common units, net | 34,180 | 34,996 | — | |||||||||
Increase in deferred charges | (7,204 | ) | (6,092 | ) | (8,009 | ) | ||||||
Net cash provided by (used in) financing activities | 48,049 | (19,874 | ) | (306,694 | ) | |||||||
Net cash provided by (used in) discontinued operations | (62,866 | ) | 194 | (11,366 | ) | |||||||
Net increase (decrease) in cash | (47,847 | ) | 436 | 94,456 | ||||||||
Cash and equivalent at beginning of period | 52,103 | 4,256 | 4,692 | |||||||||
Cash and equivalent at end of period | $ | 4,256 | $ | 4,692 | $ | 99,148 | ||||||
Years Ended September 30, | ||||||||||||
(in thousands) | 2006 | 2005 | 2004 | |||||||||
(restated) | (restated) | |||||||||||
Cash flows provided by (used in) operating activities of continuing operations: | ||||||||||||
Net income (loss) | $ | (54,263 | ) | $ | (21,209 | ) | $ | 23,973 | ||||
Deduct: (Income) loss from discontinued operations | — | 6,189 | (22,176 | ) | ||||||||
(Gain) loss on sales of discontinued operations | — | (157,560 | ) | 538 | ||||||||
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities: | ||||||||||||
Change in fair value of derivative instruments | 45,677 | (6,081 | ) | (25,811 | ) | |||||||
Depreciation and amortization | 34,853 | 38,020 | 40,793 | |||||||||
Cumulative effect of change in accounting principle | 344 | — | — | |||||||||
Loss on redemption of debt | 6,603 | 42,082 | — | |||||||||
Unit compensation expense | — | (2,185 | ) | (4,382 | ) | |||||||
Provision for losses on accounts receivable | 6,105 | 9,817 | 7,646 | |||||||||
Goodwill impairment charge | — | 67,000 | — | |||||||||
Gain on sales of fixed assets, net | (956 | ) | (43 | ) | (281 | ) | ||||||
Changes in operating assets and liabilities net of amounts related to acquisitions: | ||||||||||||
Increase in receivables | (3,809 | ) | (13,845 | ) | (6,178 | ) | ||||||
Increase in inventories | (23,830 | ) | (18,248 | ) | (10,067 | ) | ||||||
Decrease (increase) in other assets and assets held for sale, net | (8,833 | ) | (5,574 | ) | 812 | |||||||
Increase (decrease) in accounts payable | 1,764 | (5,230 | ) | 5,832 | ||||||||
Increase (decrease) in other current and long-term liabilities | 14,709 | 11,952 | 2,970 | |||||||||
Net cash provided by (used in) operating activities of continuing operations | 18,364 | (54,915 | ) | 13,669 | ||||||||
Cash flows provided by (used in) investing activities of continuing operations: | ||||||||||||
Capital expenditures | (5,433 | ) | (3,153 | ) | (3,984 | ) | ||||||
Proceeds from sales of fixed assets | 2,162 | 3,398 | 1,462 | |||||||||
Cash proceeds from sale of discontinued operations | — | 467,186 | 12,495 | |||||||||
Acquisitions | — | — | (3,526 | ) | ||||||||
Net cash provided by (used in) investing activities of continuing operations | (3,271 | ) | 467,431 | 6,447 | ||||||||
Cash flows provided by (used in) financing activities of continuing operations: | ||||||||||||
Working capital facility borrowings | 46,336 | 292,200 | 128,000 | |||||||||
Working capital facility repayments | (52,898 | ) | (293,638 | ) | (126,000 | ) | ||||||
Acquisition facility borrowings | — | — | 3,000 | |||||||||
Acquisition facility repayments | — | — | (36,000 | ) | ||||||||
Proceeds from the issuance of debt | — | — | 70,512 | |||||||||
Repayment of debt | (66,138 | ) | (259,559 | ) | (8,471 | ) | ||||||
Debt extinguishment costs | — | (37,688 | ) | — | ||||||||
Distributions | — | — | (79,819 | ) | ||||||||
Proceeds from the issuance of common units, net | 50,174 | �� | — | 34,996 | ||||||||
Increase in deferred charges | (594 | ) | (8,009 | ) | (6,092 | ) | ||||||
Net cash used in financing activities of continuing operations | (23,120 | ) | (306,694 | ) | (19,874 | ) | ||||||
Cash flows of discontinued operations: | ||||||||||||
Operating activities | — | (21,402 | ) | 48,076 | ||||||||
Investing activities | — | (664 | ) | (18,589 | ) | |||||||
Financing activities | — | 10,700 | (29,293 | ) | ||||||||
Net cash provided by (used in) discontinued operations | — | (11,366 | ) | 194 | ||||||||
Net increase (decrease) in cash | (8,027 | ) | 94,456 | 436 | ||||||||
Cash and cash equivalents at beginning of period | 99,148 | 4,692 | 4,256 | |||||||||
Cash and cash equivalents at end of period | $ | 91,121 | $ | 99,148 | $ | 4,692 | ||||||
See accompanying notes to consolidated financial statements.
F - 8
STAR GAS PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1) Partnership Organization
Star Gas Partners, L.P. (“Star Gas”Gas Partners” or the “Partnership”) is a home heating oil distributor and services provider. Star Gas Partners is a master limited partnership, which at September 30, 20052006 had outstanding 32.275.8 million common units (NYSE: “SGU” representing an 88.8%99.6% limited partner interest in Star Gas) and 3.4 million senior subordinated units (NYSE: “SGH” representing a 9.4% limited partner interest in Star Gas). Additional Partnership interests include 0.3 million junior subordinated units (representing a 0.9% limited partner interest)Gas Partners) and 0.3 million general partner units (representing a 0.9%an 0.4% general partner interest)interest in Star Gas Partners).
The Partnership is organized as follows:
• | Star Gas Finance Company is a |
The Partnership was formerly engaged in the retail distribution of propane and related supplies and equipment to residential and commercial customers in the Midwest and Northeast regions of the United States and Florida and Georgia (the “propane segment”).equipment. In December 2004, the Partnership completed the sale ofsold all of its interests in theits propane segmentoperations to Inergy Propane, LLC (“Inergy”) for a purchase price of $481.3 million. The Partnership recorded a gain on this sale of approximately $157 million.
2) Restatement of Financial Information
On March 7,December 26, 2006, management and the audit committee determined that it was necessary to amend and restate the Partnership’s previously issued financial statements with respect to the accounting and disclosures for certain derivative transactions under Statement of Financial Accounting Standards (“SFAS”) No. 133 “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”).
The Partnership has determined that its documentation for certain hedged transactions related to the purchase of heating oil did not meet the requirements of paragraph 28(a)(2) of SFAS 133 which states that documentation shall include all relevant details including the date on or the period in which the forecasted transaction is expected to occur. The documentation of these hedges did not contain sufficient specificity to qualify for hedge accounting. In addition to not meeting the documentation requirements, the Partnership has also determined that its forward contracts did not meet the criteria as described in paragraph 65(a) of SFAS 133 which permits an entity to assume that a hedge of a forecasted purchase of a commodity with a forward contract will be highly effective and that there will be no ineffectiveness to be recognized.
Prior to the restatement, the changes in fair value of derivative instruments that were designated as cash flow hedges were recorded in accumulated other comprehensive income until the forecasted transaction affected earnings. As a result of the restatement, those changes in fair value of derivative instruments are now recorded in change in the fair value of derivative instruments in the statements of operations. In addition, the change in fair value of derivative instruments that were not designated as a hedge pursuant to SFAS 133, were previously classified in cost of product. As a result of the restatement, changes in fair value of derivative instruments that were previously included in cost of product are now classified in change in fair value of derivative instruments in the statements of operations. The fair value of derivative instruments were previously classified in prepaid expenses and other current assets. The Partnership has reclassified these amounts to fair asset value of derivative instruments and fair liability value of derivative instruments in the consolidated balance sheets.
Prior to June 30, 2006, the Partnership did not include the amortization of an unrecognized gain in the calculation of pension expense resulting in an overstatement of pension expense for fiscal years 1999 to 2005 (“of $1.7 million. We have also restated our results to record the Termination Date”), Star Gas LLCamortization of the unrecognized gain. The reduction to expense has been recorded as a reduction to general and Mr. Irik P. Sevin entered intoadministrative expense. In addition, we inappropriately grossed up our prepaid pension assets and minimum pension liability by $6.1 million and $6.4 million for fiscal years 2005 and 2004 respectively.
As a letter agreement and general release (the “Agreement”). In accordance withresult of the Agreement, Mr. Sevin confirmed his resignation from employment as the Chairman and Chief Executive Officer and President of Star Gas LLC (and its subsidiaries) under the employment agreement between Mr. Sevin and Star Gas LLC datedforegoing, we are restating herein our historical balance sheet as of September 30, 2001. In addition, Mr. Sevin transferred his member interests in Star Gas LLC to a voting trust2005; our statements of which Mr. Sevin is one of three trustees. Underoperations, cash flows and partners’ capital for fiscal 2005 and 2004; and financial information for the terms of the voting trust, those interests will be voted in accordance with the decision of a majority of the trustees. Pursuant to the Agreement, Mr. Sevin is entitled to an annual consulting fee totaling $395,000 for a period of five years following the Termination Date. In addition, the Agreement provides for Mr. Sevin to receive a retirement benefit equal to $350,000 per year for a 13-year period beginning with the month following the five-year anniversary of the Termination Date. Onfiscal quarters ended June 30, 2006, March 31, 2006, December 31, 2005, September 30, 2005, June 30, 2005, March 31, 2005 and December 31, 2004.
Effects of Restatement
The following tables set forth the effects of the restatement relating to derivative transactions and pension expense on affected line items within our previously reported financial statements for fiscal 2005 and 2004. For fiscal 2005, the effect of derivative transactions reduced the net loss by $4.7 million, as a liability of $4.1 million was reflectedpositive adjustment to the change in the Partnership’sfair value of derivative instruments of $6.1 million for continuing operations was reduced by a decrease in income from discontinued operations of $1.6 million. In fiscal 2005, general and administrative expenses were reduced by $0.2 million, as the unamortized pension gain was recorded.
As of September 30, 2005, the balance in prepaid expenses and other current assets was reduced by $41.2 million to reflect a reclassification of $35.1 million to fair asset value of derivative instruments and a reduction to prepaid pension expense of $6.1 million. Long-term liabilities were reduced by $6.1 million, as the $6.1 million reclassification from prepaid pension expense was netted against the minimum pension obligation. Partners’ capital increased by $34.9 million and accumulated other comprehensive income decreased by $34.9 million to reflect the effects relating to derivative transactions of $33.4 million and the cumulative unrecognized pension gain of $1.5 million.
F - 9
For fiscal 2004, the effect of derivative transactions positively impacted net income by $29.4 million, which resulted from a positive adjustment to the change in the fair value of derivative instruments of $25.8 million for continuing operations, a $1.7 million decrease in cost of product and increased income from discontinued operations of $1.9 million. In fiscal 2004, general and administrative expenses were reduced by $0.4 million, as the unamortized pension gain was recorded.
Fiscal 2005 | Fiscal 2004 | |||||||||||||||
(In thousands except per unit amounts) | As Previously Reported | Restated | As Previously Reported | Restated | ||||||||||||
Statement of Operations | ||||||||||||||||
Cost of product | $ | 786,349 | $ | 786,302 | $ | 594,153 | $ | 592,428 | ||||||||
Change in the fair value of derivative instruments | — | (6,081 | ) | — | (25,811 | ) | ||||||||||
General and administrative expenses | 43,418 | 43,190 | 19,937 | 19,537 | ||||||||||||
Operating income (loss) | (101,780 | ) | (95,424 | ) | 15,801 | 43,737 | ||||||||||
Income (loss) from continuing operations | (178,936 | ) | (172,580 | ) | (25,601 | ) | 2,335 | |||||||||
Income (loss) from discontinued operations | (4,552 | ) | (6,189 | ) | 20,276 | 22,176 | ||||||||||
Net income (loss) | (25,928 | ) | (21,209 | ) | (5,863 | ) | 23,973 | |||||||||
Basic and diluted loss from continuing operations per unit | (4.95 | ) | (4.77 | ) | (0.72 | ) | 0.07 | |||||||||
Basic and diluted net income loss per unit | (0.72 | ) | (0.59 | ) | (0.16 | ) | 0.67 | |||||||||
Consolidated Balance Sheets | ||||||||||||||||
Fair asset value of derivative instruments | — | 35,140 | ||||||||||||||
Prepaid expenses and other current assets | 70,120 | 28,867 | ||||||||||||||
Current assets | 311,432 | 305,319 | ||||||||||||||
Other long-term liabilities | 31,129 | 25,016 | ||||||||||||||
Partners’ capital (deficit) | 131,446 | 166,371 | ||||||||||||||
Partners’ capital accumulated other comprehensive income (loss) | 13,662 | (21,263 | ) |
The effect of the restatement on opening partners’ capital as of September 30, 2003 was a net adjustment of $(0.4) million from accumulated other comprehensive income to the common, senior subordinated and junior subordinated unitholders and the general partner; reflecting $(0.9) million adjustment for cumulative unrecognized pension gain and $0.5 million adjustment for the effects relating to derivative transactions.
Quarterly Information (unaudited)
The following tables set forth the effects of the restatement relating to derivatives transactions on affected line items within our previously reported financial statements for fiscal quarters ended June 30, 2006; March 30, 2006; and December 31, 2005.
For three months ended June 30, 2006, the presentnet loss declined due to the effect of derivative transactions by $2.0 million, as the change in the fair value of the remainingderivative instruments was positively impacted by $2.3 million and cost of product increased by $0.3 million. As of June 30, 2006, the Agreement. balance in prepaid expenses and other current assets was reduced by $11.9 million to reflect a reclassification of $5.9 million to fair asset value of derivative instruments, a reclassification of $0.1 million to fair liability value of derivative instruments and a reduction to prepaid pension expense of $6.1 million. Long-term liabilities were reduced by $6.1 million, as the $6.1 million reclassification from prepaid pension expense was netted against the minimum pension obligation. Partners’ capital increased by $6.6 million and accumulated other comprehensive (loss) increased by $6.6 million to reflect the effects relating to derivative transactions of $5.1 million and the cumulative unrecognized pension gain of $1.5 million.
For three months ended March 31, 2006, net income increased by $10.5 million due to the yeareffect of derivative transactions, which positively impacted the change in the fair value of derivative instruments by $11.2 million and increased cost of product by $0.7 million. As of March 31, 2006, the balance in prepaid expenses and other current assets was reduced by $9.4 million to reflect a reclassification of $3.3 million to fair asset value of derivative instruments and a reduction to prepaid pension expense of $6.1 million. Long-term liabilities were reduced by $6.1 million, as the $6.1 million reclassification from prepaid pension expense was netted against the minimum pension obligation. Partners’ capital increased by $4.6 million and accumulated other comprehensive (loss) increased by $4.6 million to reflect the effects relating to derivative transactions of $3.1 million and the cumulative unrecognized pension gain of $1.5 million.
For three months ended December 31, 2005, net income was reduced by $40.9 million due to the effect of derivative transactions, which negatively impacted the change in the fair value of derivative instruments by $40.6 million and increased cost of product by $0.3 million. As of December 31, 2005, the balance in prepaid expenses and other current assets was reduced by $0.4 million to reflect a reclassification of $1.3 million to fair asset value of derivative instruments, a reclassification of $7.0 million to fair liability value of derivative instruments and a reduction to prepaid pension expense of $6.1 million. Long-term liabilities were reduced by $6.1 million, as the $6.1 million reclassification from prepaid pension expense was netted against the minimum pension obligation. Partners’ capital decreased by $5.9 million and accumulated other comprehensive (loss) decreased by $5.9 million to reflect the effects relating to derivative transactions of $7.4 million and the cumulative unrecognized pension gain of $1.5 million.
F - 10
Quarter Ending | ||||||||||||||||||||||||
June 30, 2006 | March 31, 2006 | December 31, 2005 | ||||||||||||||||||||||
(In thousands except per unit amounts) | As Previously Reported | Restated | As Previously Reported | Restated | As Previously Reported | Restated | ||||||||||||||||||
Statement of Operations | ||||||||||||||||||||||||
Cost of product | $ | 114,900 | $ | 115,154 | $ | 367,870 | $ | 368,588 | $ | 261,972 | $ | 262,280 | ||||||||||||
Change in the fair value of derivative instruments | — | (2,257 | ) | — | (11,230 | ) | — | 40,563 | ||||||||||||||||
Operating income (loss) | (24,330 | ) | (22,327 | ) | 51,748 | 62,260 | 20,437 | (20,434 | ) | |||||||||||||||
Income (loss) from continuing operations | (36,079 | ) | (34,076 | ) | 43,557 | 54,069 | 12,874 | (27,997 | ) | |||||||||||||||
Net income (loss) | (36,079 | ) | (34,076 | ) | 43,557 | 54,069 | 12,530 | (28,341 | ) | |||||||||||||||
Basic and diluted loss from continuing operations per unit | (0.56 | ) | (0.53 | ) | 1.20 | 1.49 | 0.36 | (0.77 | ) | |||||||||||||||
Basic and diluted net income loss per unit | $ | (0.56 | ) | $ | (0.53 | ) | $ | 1.20 | $ | 1.49 | $ | 0.35 | $ | (0.78 | ) | |||||||||
Consolidated Balance Sheets | ||||||||||||||||||||||||
Fair asset value of derivative instruments | $ | — | $ | 5,856 | $ | — | $ | 3,331 | $ | — | $ | 1,258 | ||||||||||||
Prepaid expenses and other current assets | 48,176 | 36,262 | 47,058 | 37,614 | 62,806 | 62,445 | ||||||||||||||||||
Current assets | 292,800 | 286,742 | 314,043 | 307,930 | 322,026 | 322,923 | ||||||||||||||||||
Fair liability value of derivative instruments | — | 55 | — | — | — | 7,010 | ||||||||||||||||||
Total current liabilities | 159,877 | 159,932 | 147,462 | not restated | 218,316 | 225,326 | ||||||||||||||||||
Other long-term liabilities | 31,535 | 25,422 | 31,645 | 25,532 | 31,756 | 25,643 | ||||||||||||||||||
Partners’ capital (deficit) | 233,871 | 240,440 | 187,533 | 192,099 | 143,976 | 138,030 | ||||||||||||||||||
Partners’ capital accumulated other comprehensive income (loss) | (14,694 | ) | (21,263 | ) | (16,697 | ) | (21,263 | ) | (27,209 | ) | (21,263 | ) |
The following tables set forth the restatement relating to derivative transactions on affected line items within our previously reported financial statements for the fiscal quarters ended September 30, 2005, June 30, 2005, March 31, 2005 and December 31, 2004.
For three months ended September 30, 2005, the Partnership paid Mr. Sevin $0.2net loss was reduced by $23.2 million due to the effect of derivative transactions, which resulted from a positive adjustment to the change in the fair value of derivative instruments of $ 20.1 million, a reduction in cost of product of $ 3.1 million, and recorded $3.2 million ofa reduction in general and administrative expenses by $0.2 million, for the recognition of unamortized pension cost.
For three months ended June 30, 2005, the net loss increased by $8.0 million due to the effect of derivative transactions, which resulted from a negative adjustment to the change in the fair value of derivative instruments of $ 7.2 million and an increase in cost of product of $ 0.8 million. As of June 30, 2005, the balance in prepaid expenses and other current assets was reduced by $19.8 million to reflect a reclassification of $13.4 million to fair asset value of derivative instruments and a reduction to prepaid pension expense of $6.4 million. Long-term liabilities were reduced by $6.4 million, as the $6.4 million reclassification from prepaid pension expense was netted against the minimum pension obligation. Partners’ capital increased by $11.5 million and accumulated other comprehensive (loss) increased by $11.5 million to reflect the current quarter’s impact relating to derivative transactions of $10.2 million (including discontinued operations) and the Agreement. Thecumulative unrecognized pension gain of $1.3 million.
For three months ended March 31, 2005, net income was positively impacted by $14.4 million due to the effect of derivative transactions, which resulted from a positive adjustment to the change in the fair value of derivative instruments of $ 21.0 million and an increase in cost of product of $ 6.6 million. As of March 31, 2005, the balance in prepaid expenses and other current assets was reduced by $27.3 million to reflect a reclassification of $20.9 million to fair asset value of derivative instruments and a reduction to prepaid pension expense of $6.4 million. Long-term liabilities were reduced by $6.4 million, as the $6.4 million reclassification from prepaid pension expense was netted against the minimum pension obligation. Partners’ capital increased by $19.5 million and accumulated other comprehensive income decreased by $19.5 million to reflect the effects relating to derivative transactions of $18.2 million and the cumulative unrecognized pension gain of $1.3 million.
For three months ended December 31, 2004, net income was negatively impacted by $25.1 million due to the effect of derivative transactions, which resulted from a negative adjustment to the change in the fair value of derivative instruments of $ 27.9 million for continuing operations, the negative effect of derivative transactions on discontinued operations of $1.6 million and a reduction in cost of product of $ 4.4 million. As of December 31, 2004, the balance in prepaid expenses and other current assets was reduced by $10.0 million to reflect a reclassification of $6.3 million to fair asset value of derivative instruments, a reclassification of $2.7 million to fair liability value of derivative instruments and a reduction to prepaid pension expense of $6.4 million. Long-term liabilities were reduced by $6.4 million, as the $6.4 million reclassification from prepaid pension expense was netted against the minimum pension obligation. Partners’ capital increased by $5.1 million and accumulated other comprehensive (loss) increased by $5.1 million to reflect the effects relating to derivative transactions of $3.8 million and the cumulative unrecognized pension gain of $1.3 million.
F - 11
Quarterly Information (unaudited)
Quarter Ending | ||||||||||||||||||||||||||||||||
September 30, 2005 | June 30, 2005 | March 31, 2005 | December 31, 2004 | |||||||||||||||||||||||||||||
(In thousands except per unit | As Previously Reported | Restated | As Previously Reported | Restated | As Previously Reported | Restated | As Previously Reported | Restated | ||||||||||||||||||||||||
Statement of Operations | ||||||||||||||||||||||||||||||||
Cost of product | $ | 82,902 | $ | 79,841 | $ | 117,803 | $ | 118,610 | $ | 362,741 | $ | 369,385 | $ | 222,903 | $ | 218,466 | ||||||||||||||||
Change in the fair value of derivative instruments | — | (20,114 | ) | — | 7,216 | — | (21,049 | ) | — | 27,866 | ||||||||||||||||||||||
General and administrative expenses | 6,825 | 6,597 | 7,833 | not restated | 12,918 | not restated | 15,842 | not restated | ||||||||||||||||||||||||
Operating loss | (39,963 | ) | (16,560 | ) | (23,448 | ) | (31,471 | ) | (17,341 | ) | (2,936 | ) | (21,028 | ) | (44,457 | ) | ||||||||||||||||
Loss from continuing operations | (48,752 | ) | (25,349 | ) | (28,917 | ) | (36,940 | ) | (26,619 | ) | (12,214 | ) | (74,648 | ) | (98,077 | ) | ||||||||||||||||
Income (loss) from discontinued operations | — | — | — | — | — | — | (4,552 | ) | (6,189 | ) | ||||||||||||||||||||||
Net income (loss) | (46,952 | ) | (23,549 | ) | (29,321 | ) | (37,344 | ) | (24,099 | ) | (9,694 | ) | 74,444 | 49,378 | ||||||||||||||||||
Basic and diluted loss from continuing operations per unit | (1.35 | ) | (0.70 | ) | (0.80 | ) | (1.02 | ) | (0.74 | ) | (0.34 | ) | (2.07 | ) | (2.72 | ) | ||||||||||||||||
Basic and diluted net income loss per unit | $ | (1.30 | ) | $ | (0.65 | ) | $ | (0.81 | ) | $ | (1.03 | ) | $ | (0.67 | ) | $ | (0.27 | ) | $ | 2.06 | $ | 1.37 | ||||||||||
Consolidated Balance Sheets | ||||||||||||||||||||||||||||||||
Fair asset value of derivative instruments | $ | — | $ | 35,140 | $ | — | $ | 13,357 | $ | — | $ | 20,822 | $ | — | $ | 6,255 | ||||||||||||||||
Prepaid expenses and other current assets | 70,120 | 28,867 | 54,570 | 34,779 | 62,577 | 35,321 | 59,243 | 49,260 | ||||||||||||||||||||||||
Current assets | 311,432 | 305,319 | 318,205 | 311,771 | 445,148 | 438,714 | 393,630 | 389,902 | ||||||||||||||||||||||||
Fair liability value of derivative instruments | — | — | — | — | — | — | — | 2,706 | ||||||||||||||||||||||||
Total current liabilities | 185,607 | not restated | 271,015 | not restated | 369,410 | not restated | 298,065 | 300,771 | ||||||||||||||||||||||||
Other long-term liabilities | 31,129 | 25,016 | 27,576 | 21,142 | 27,634 | 21,200 | 23,766 | 17,332 | ||||||||||||||||||||||||
Partners’ capital (deficit) | 131,446 | 166,371 | 178,226 | 189,748 | 207,547 | 227,092 | 231,359 | 236,499 | ||||||||||||||||||||||||
Partners’ capital accumulated other comprehensive income (loss) | 13,662 | (21,263 | ) | (5,810 | ) | (17,332 | ) | 2,213 | (17,332 | ) | (12,192 | ) | (17,332 | ) |
Certain amounts in notes 5, 8, 16, 17 and 24 have been restated to reflect the restatement adjustments reflected above.
3) Recapitalization
Effective as of April 28, 2006 the Partnership had previously accrued approximately $1.1 million related to Mr. Sevin’s prior SERP, which was forfeited in lieucompleted a recapitalization of the new retirement benefit inPartnership pursuant to the terms of a unit purchase agreement dated as of December 5, 2005, as amended (the “unit purchase agreement”), by and among, the Partnership, Star Gas LLC (“Star Gas”), Kestrel and its wholly owned subsidiaries, Kestrel Heat, and KM2, LLC, a Delaware limited liability company. In connection with the Agreement.recapitalization:
2) Use of Excess Proceeds
During the year ended September 30, 2005, the Partnership has experienced high customer attrition and declining operating margins. Its loss from continuing operations totaled $178.9 million and cash flows used in operations totaled $54.9 million.
F - 12
The following table shows the amount of Net Proceeds in excess of $10 million not yet applied toward a Permitted Use totaled $93.2 million. As of December 2, 2005 all Excess Proceeds were applied toward a Permitted Use.units before and after the April 28, 2006 recapitalization.
Before Recapitalization* | After Recapitalization** | |||||||||
(in thousands) | Number | Percentage | Number | Percentage | ||||||
Common Units | ||||||||||
Existing common units | 32,166 | 88.8 | % | 32,166 | 42.3 | % | ||||
Issued to Kestrel entities | — | — | 6,750 | 8.9 | % | |||||
Issued in rights offering(1) | — | — | 19,687 | 25.9 | % | |||||
Issued to senior noteholders | — | — | 13,434 | 17.6 | % | |||||
Issued to subordinated unitholders | — | — | 3,737 | 4.9 | % | |||||
Subtotal | 32,166 | 88.8 | % | 75,774 | 99.6 | % | ||||
Subordinated Units | ||||||||||
Senior subordinated units | 3,392 | 9.4 | % | — | — | |||||
Junior subordinated units | 345 | 0.9 | % | — | — | |||||
Subtotal | 3,737 | 10.3 | % | — | — | |||||
General Partner Units | 326 | 0.9 | % | 326 | 0.4 | % | ||||
Total | 36,229 | 100 | % | 76,100 | 100 | % | ||||
* | As of March 31, 2006 |
** | As of April 28, 2006 |
(1) | Includes 6.0 million common units issued to Kestrel at $2.25 per share, pursuant to its standby commitment. As part of the recapitalization a total of 12.7 million common units were issued to Kestrel entities, representing approximately 16.7% of total units after the recapitalization. |
3)4) Summary of Significant Accounting Policies
Basis of Presentation
The Consolidated Financial Statements include the accounts of Star Gas Partners, L.P. and its subsidiaries. All material intercompany items and transactions have been eliminated in consolidation.
The Partnership completed the sale of its propane segmentoperations on December 17, 2004 and its natural gas and electricity operations (“TG&E segment&E”) on March 31, 2004. As a result of the sale of TG&E and the propane segment, theThe results of operations of TG&E and propane segmentsthese sold operations have been classified as discontinued operations in accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.”
F - 13
Reclassification
Certain prior year amounts have been reclassified to conform with the current year presentation.
Use of Estimates
The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period. Actual results could differ from those estimates.
Revenue Recognition
Sales of heating oil and air conditioning equipmentother fuels are recognized at the time of delivery of the product to the customer orand sales of heating and air conditioning equipment are recognized at the time of sale or installation. Revenue from repairs and maintenance service is recognized upon completion of the service. Payments received from customers for heating oil equipment service contracts are deferred and amortized into income over the terms of the respective service contracts, on a straight-line basis, which generally do not exceed one year.
To the extent that the Partnership anticipates that future costs for fulfilling its contractual obligations under its service maintenance contracts will exceed the amount of deferred revenue currently attributable to these contracts, the Partnership recognizes a loss in current period earnings equal to the amount that anticipated future costs exceed related deferred revenues.
Basic and Diluted Net Income (Loss) per Limited Partner Unit
Net Income (Loss)income (loss) per Limited Partner Unitlimited partner unit is computed by dividing net income (loss), after deducting the General Partner’sgeneral partner’s interest, by the weighted average number of Common Units, Senior Subordinated Unitscommon units, senior subordinated units and Junior Subordinated Unitsjunior subordinated units outstanding.
Each unit in each of the partnership’s ownership classes participates in net income (loss) equally.
Cash Equivalents
The Partnership considers all highly liquid investments with a maturity of three months or less, when purchased, to be cash equivalents.
Inventories
Inventories areAt September 30, 2005, the Partnership’s inventory of heating oil and other fuels were stated at the lower of cost or market and are computed on athe first-in, first-out basis.
(FIFO) method. Effective October 1, 2005, the Partnership changed from the FIFO method to the weighted average cost (WAC) method. All other inventories, representing parts and equipment have been and continue to be stated at the lower of cost or market using the FIFO method. (See Note 8. Change in Accounting Principle and Note 10. Inventories)
Property, Plant, and Equipment
Property, plant, and equipment are stated at cost. Depreciation is computed over the estimated useful lives of the depreciable assets using the straight-line method.
F - 14
Goodwill and Intangible Assets
Goodwill and intangible assets include goodwill, customer lists and covenants not to compete.
Goodwill is the excess of cost over the fair value of net assets in the acquisition of a company. On October 1, 2002, the Partnership adopted the provisionsIn accordance with Statements of SFASFinancial Accounting Standards (“SFAS”) No. 142 “Goodwill and Other Intangible Assets.Assets,” SFAS No. 142 requires that goodwill and intangible assets with indefinite useful lives no longer beare not amortized, but instead beare annually tested for impairment at least annually. SFAS No. 142 also requiresimpairment. Also in accordance with this standard, intangible assets with definite useful lives beare amortized over their respective estimated useful lives to their estimated residual values, and reviewed for impairment. On October 1, 2002, the Partnership ceased amortization of all goodwill. The Partnership also recorded a non-cash charge of $3.9 million in its first fiscal quarter of 2003 to reduce the carrying value of the discontinued TG&E segment’s goodwill. This charge is reflected as a cumulative effect of change in accounting principle in the Partnership’s consolidated statement of operations for the year ended September 30, 2003. The Partnership performs its annual impairment review during its fiscal fourth quarter or more frequently if events or circumstances indicate that the value of goodwill might be impaired The Partnership performed such animpaired. During its interim review during its fiscalthe second quarter which resulted in a writedown of its2005, the Partnership wrote-down goodwill by $67 million. See Note 9.
12.
Customer lists are the names and addresses of the acquired company’s patrons. Based on the historical retention experience, of these lists the heating oil segment amortizes customer listsare amortized on a straight-line basis over seven to ten years.
Covenants not to compete are non-compete agreements established with the owners of an acquired company and are amortized over the respective lives of the covenants on a straight-line basis, which are generally five years.
Impairment of Long-lived Assets
It is the Partnership’s policy to review intangible assets and other long-lived assets in accordance with SFAS No. 144 “Accounting for the Impairment or Disposal of Long-Lived Assets,” for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. The Partnership determines whether the carrying values of such assets are recoverable over their remaining estimated lives through undiscounted future cash flow analysis. If such a review should indicate that the carrying amount of the assets is not recoverable, it is the Partnership’s policy to reduce the carrying amount of such assets to fair value.
Deferred Charges
Deferred charges represent the costs associated with the issuance of debt instruments and are amortized over the lives of the related debt instruments.
Advertising Expense
Advertising costs are expensed as they are incurred. Advertising expenses were $6.6$5.9 million, $9.2 million and $6.9 million in 2006, 2005 and $9.2 million in 2003, 2004, and 2005, respectively.
Customer Credit Balances
Customer credit balances represent payments received in advance from customers pursuant to a budget payment plan (whereby customers pay their estimated annual usage on a fixed monthly basis) and the payments made have exceeded the charges for heating oil deliveries.
Environmental Costs
The Partnership expenses, on a current basis, costsCosts associated with managing hazardous substances and pollution in ongoing operations. The Partnership also accruesare expensed on a current basis. Accruals are made for costs associated with the remediation of environmental pollution when it becomes probable that a liability has been incurred and the amount can be reasonably estimated.
Insurance Reserves
The Partnership accrues for workers’ compensation, general liability and autoautomobile claims not covered under its insurance policies and establishes estimates based upon actuarial assumptions as to what its ultimate liability will be for these claims. The Partnership recorded $38.8 million and $33.8 million to accrued expenses at September 30, 2006 and 2005 respectively, representing its anticipated liability for claims not covered under its insurance policies.
Employee Unit Incentive PlanF - 15
When applicable, the Partnership accounts for stock-based compensation arrangements in accordance with APB No. 25. Compensation costs for fixed awards on pro-rata vesting are recognized on a straight-line basis over the vesting period. The Partnership adopted an employee and director unit incentive plan to grant certain employees and directors senior subordinated limited partner units (“incentive units”), as an incentive for increased efforts during employment and as an inducement to remain in the service of the Partnership. Grants of incentive units vest as follows: twenty percent immediately, with the remaining amount vesting annually over four consecutive installments if the Partnership achieves annual targeted distributable cash flow. The Partnership records an expense for the incentive units granted, which require no cash contribution, over the vesting period for those units which are probable of being issued.
Income Taxes
The Partnership is a master limited partnership. As a result,partnership and is not subject to tax at the entity level for Federalfederal and state income tax purposes, earnings orpurposes. Rather, any income and losses of the Partnership are allocated directly to the individual partners. Except for the Partnership’s corporate subsidiaries, no recognition has been given to Federalfederal income taxes in the accompanying financial statements of the Partnership. While the Partnership’s corporate subsidiaries will generate non-qualifying Master Limited Partnership revenue, dividendsdistributions from the corporate subsidiaries to the Partnership are generally included in the determination of qualified Master Limited Partnership income. In addition,All or a portion of the dividendsdistributions received by the Partnership from the corporate subsidiaries willcould be taxable as either a dividend or capital gain to the partners. Net earnings for financial statement purposes will differ significantly from taxable income reportable to partners as a result of differences between the tax basis and financial reporting basis of assets and liabilities and due to the taxable income allocation requirements of the Partnership agreement.
The accompanying financial statements are reported on a fiscal year, however, the Partnership and its Corporate subsidiaries file state and Federalfederal income tax returns on a calendar year.
For corporate subsidiaries of the Partnership, a consolidated Federal income tax return is filed. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amount of assets and liabilities and their respective tax bases and operating loss carry-forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled.
Sales, Use and Value Added Taxes
Taxes are assessed by various governmental authorities on many different types of transactions. Sales reported for product, installation and service excludes taxes.
Derivatives and Hedging
The Partnership usesSFAS No. 133, established accounting and reporting standards requiring that derivative instruments to manage the majority of its exposure to market risk related to changesbe recorded at fair value and included in the current and future market price of home heating oil purchased for resale to protected-price customers. It isconsolidated balance sheet as assets or liabilities. To the Partnership’s objective to hedge the cash flow variability associated with forecasted purchases of its inventory held for resale to protected-price customers through the use ofextent derivative instruments when appropriate. To a lesser extent, the Partnership may hedge the fair value of inventory on hand or firm commitments to purchase inventory. To meet these objectives, it is the Partnership’s policy to enter into various types of derivative instruments to (i) manage the variability of cash flows resulting from the price risk associated with forecasted purchases of home heating oil purchased for resale to protected-price customers, (ii) hedge the downside price risk of firm purchase commitments and in some cases physical inventory on hand.
All derivative instruments are recognized on the balance sheet at their fair market value. On the date the derivative contract is entered into, the Partnership designates the derivative as either a hedge of the fair value of a recognized asset or liability or of an unrecognized firm commitment (fair value hedge), or a hedge of a forecasted purchase or the variability of cash flows to be received or paid related to a recognized asset or liability (cash flow hedge). The Partnership formally documents all relationships between hedging instruments and hedged items, as well as its risk-management objective and strategy for undertaking various hedge transactions. This process includes linking all derivatives that are designated as fair value or cash flow hedges to specific assetsare effective and liabilities on the balance sheet or to specific firm commitments or forecasted transactions. The Partnership also formally assesses, both at the hedge’s inception and on an ongoing basis, whether the derivatives that are used in hedging transactions are highly effective in offsettingSFAS 133 documentation requirements have been met, changes in fair value or cash flows of hedged items.
Changesare recognized in the fair value of a derivative that is highly effective and that is designated and qualifies as a fair value hedge, along with the loss or gain on the hedged asset or liability or unrecognized firm commitment of the hedged item that is attributable to the hedged risk are recorded in earnings. Changes in the fair value of a derivative that is highly effective and that is designated and qualifies as a cash-flow hedge are recorded in accumulated other comprehensive income until earnings are affected by the variabilityunderlying hedged item is recognized in cash flowsearnings. Currently, none of the designated hedged item. The ineffective portion of a derivative’s changePartnership’s derivatives qualify for hedge accounting treatment. Therefore, the Partnership could experience great volatility in fair value is immediately recognized in earnings.earnings as these currently outstanding derivative instruments are marked to market.
When it is determined that a derivative is not highly effective as a hedge or that is has ceased to be a highly effective hedge, the Partnership discontinues hedge accounting prospectively. When hedge accounting is discontinued because it is determined that the derivative no longer qualifies as an effective hedge, the Partnership continues to carry the derivative on the balance sheet at its fair value, and recognized changes in the fair value of the derivative through current-period earnings.F - 16
Recent Accounting Pronouncements
In December 2004,July 2006, the FASB issued Financial Interpretation No. 48 “Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 123 (revised 2004)109” (“FIN 48”), “Share-Based Payment” (“SFAS No. 123R”). SFAS No. 123R, which clarifies the criteria that must be met prior to recognition of the financial statement benefit of a position taken in a tax return. Using a two-step approach, FIN 48 requires an entity to determine whether it is effective formore likely than not that a tax position will be sustained upon examination, based on the first annual period beginning after June 15, 2005. SFAS No. 123Rtechnical merits of the position. A tax position that meets the more-likely-than-not recognition threshold is then measured to determine the amount of benefit to recognize in the financial statements. The tax position is measured at the largest amount of benefit that is greater than 50 percent likely of being realized upon ultimate settlement. FIN 48 also requires all share-based payments to employees, including grantsthe recognition of stock options, to beliabilities created by differences between tax positions taken in a tax return and amounts recognized in the financial statements based on their fair values. In addition, two transition alternatives are permitted at the time of adoption of this statement, restating prior year financial statements or recognizing adjustments to share-based liabilities as the cumulative effect of a change in accounting principle. Currently, the Partnership accounts for unit appreciation rights and other unit based compensation arrangements using the intrinsic value method under the provisions of APB 25. The Partnership will be required to adopt SFAS No. 123R effective October 1, 2005. In March 2005, the SEC issued Staff Accounting Bulletin No. 107 (“SAB 107”) regarding the SEC’s interpretation of SFAS No. 123R. The Partnership is currently evaluating the requirements of SFAS No. 123R and SAB 107. The Partnership has not yet determined the method of adoption or the effect of adopting SFAS No. 123R. However, it believes that SFAS No. 123R will not have a material effect on its results of operations financial position or liquidity, upon adoption.
In May 2005, the FASB issued Statement No. 154, “Accounting Changes and Error Corrections” (“SFAS No. 154”), whichstatements. FIN 48 is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005.2006. We are required to adopt FIN 48 in fiscal 2008. The Partnership is currently assessing the impact of adopting FIN 48.
In September 2006, the FASB issued Statement No. 157 “Fair Value Measurements” (“SFAS 157”), which defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. SFAS 157 is effective in fiscal years beginning after November 15, 2007. We are required to adopt SFAS 157 in fiscal 2009. It is expected that adoption of this standard will not have a significant impact on the Partnership’s financial statements.
In September 2006, the FASB issued Statement No. 154158 “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans” (“SFAS 158”), which requires an employer to (i) measure the funded status of a defined benefit postretirement plan as of the date of its fiscal year-end statement of financial position, (ii) to recognize the overfunded or underfunded status of this plan as an asset or liability in its statement of financial position and (iii) to recognize changes in that funded status in the year which the changes occur through comprehensive income. The required date of adoption of the recognition and disclosure provisions of SFAS 158 differs for an employer that is an issuer of publicly traded equity securities and an employer that is not. An employer with publicly traded equity securities is required to recognize the funded status of a defined benefit postretirement plan and provide the required disclosures as of the end of the fiscal year ending after December 15, 2006. We are required to adopt this provision of SFAS 158 in fiscal 2007. The requirement to measure plan assets and benefit obligations as of the date of the employer’s fiscal year-end statement of financial position is effective for fiscal years ending after December 15, 2008. We are required to adopt this provision of SFAS 158 in fiscal 2009. The Partnership is currently assessing the impact of adopting SFAS 158.
In September 2006, the Securities and Exchange Commission (“SEC”) issued Staff Accounting Bulletin (“SAB”) No. 154 provides108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements”, which addresses the process of quantifying financial statement misstatements. SAB No. 108 states that companies should use both a balance sheet approach and an income statement approach when quantifying and evaluating the materiality of a misstatement. The interpretations in SAB No. 108 contain guidance on correcting errors under the dual approach as well as provide transition guidance for correcting errors. If the effect of the error is determined to be material, the cumulative effect may be reported as an adjustment to the beginning of the year retained earnings with disclosure of the nature and reportingamount of accounting changes andeach individual error corrections. It states that retrospective application, orbeing corrected in the latest practicable date,cumulative adjustment. SAB No. 108 is effective for fiscal years ending after November 15, 2006. We are required to adopt SAB No. 108 in fiscal 2007. The Partnership is currently assessing the required method for reporting a change in accounting principle and the reportingimpact of a correction of an error. The Partnership’s results of operations and financial condition will only be impacted following the adoption of SFASadopting SAB No. 154 if it implements changes in accounting principles that are addressed by the standard or corrects accounting errors in future periods.
4)5) Discontinued Operations
On December 17, 2004, the Partnership completed the sale of all of its interests in its propane segmentoperations to Inergy for a net purchase price of approximately $481.3 million. The propane segment was the Partnership’s principal distributor of propane and related supplies and equipment to residential, industrial, agricultural and motor fuel customers. Closing and other settlement costs totaled approximately $14 million and approximately $311 million was used to repay outstanding debt of the propane segment and the heating oil segment. $10 million of the proceeds were used to reimburse the heating oil segment for expenses paid by the heating oil segment on behalf of the Partnership. The remainder of the proceeds were contributed to the heating oil segment (Petro Holdings, Inc.) as a capital contribution.debt. In accordance with the purchase agreement, the effective date of the disposition was November 30, 2004. The Partnership recognized a gain on the sale of the propane segmentoperations totaling approximately $157 million net of income taxes of $1.3 million.
On March 31, 2004, the Partnership sold the stock and business of its natural gas and electricity segment (“TG&E”)operations to a private party for a purchase price of approximately $13.5 million. TG&E was the Partnership’s energy reseller that marketed natural gas and electricity to approximately 65,000 residential customers in deregulated markets in New York, New Jersey, Florida and Maryland. The Partnership realized a gain of approximately $0.2 million as a result of this transaction.
F - 17
The components of discontinued operations of the propane and TG&E segments for the years ended September 30, are as follows (in thousands):
2003 | 2004 | 2005 | |||||||||||||||||||||||||||||
TG&E | Propane | Total | TG&E | Propane | Total | TG&E | Propane | Total | |||||||||||||||||||||||
Sales | $ | 81,480 | $ | 279,300 | $ | 360,780 | $ | 52,413 | $ | 348,846 | $ | 401,259 | $ | — | $ | 58,722 | $ | 58,722 | |||||||||||||
Cost of sales | 71,789 | 145,015 | 216,804 | 46,867 | 197,000 | 243,867 | — | 38,442 | 38,442 | ||||||||||||||||||||||
Delivery and branch expenses | — | 76,279 | 76,279 | — | 92,701 | 92,701 | — | 17,796 | 17,796 | ||||||||||||||||||||||
Depreciation & amortization expenses | 667 | 16,958 | 17,625 | 258 | 20,030 | 20,288 | — | 3,481 | 3,481 | ||||||||||||||||||||||
General & administrative expenses | 7,780 | 10,568 | 18,348 | 4,255 | 10,090 | 14,345 | — | 2,096 | 2,096 | ||||||||||||||||||||||
1,244 | 30,480 | 31,724 | 1,033 | 29,025 | 30,058 | — | (3,093 | ) | (3,093 | ) | |||||||||||||||||||||
Net interest expense | 14 | 11,037 | 11,051 | — | 9,221 | 9,221 | — | 1,384 | 1,384 | ||||||||||||||||||||||
Other loss | — | 587 | 587 | — | 166 | 166 | — | 27 | 27 | ||||||||||||||||||||||
Income (loss) from discontinued operations before income taxes and cumulative effect of changes in accounting principles, net of income taxes | 1,230 | 18,856 | 20,086 | 1,033 | 19,638 | 20,671 | — | (4,504 | ) | (4,504 | ) | ||||||||||||||||||||
Income tax expense | — | 300 | 300 | 110 | 285 | 395 | — | 48 | 48 | ||||||||||||||||||||||
Income (loss) from discontinued operations before cumulative effect of changes in accounting principles, net of income taxes | 1,230 | 18,556 | 19,786 | 923 | 19,353 | 20,276 | — | (4,552 | ) | (4,552 | ) | ||||||||||||||||||||
Cumulative effect of change in accounting principles | (3,901 | ) | — | (3,901 | ) | — | — | — | — | — | — | ||||||||||||||||||||
Income (loss) from discontinued operations | $ | (2,671 | ) | $ | 18,556 | $ | 15,885 | $ | 923 | $ | 19,353 | $ | 20,276 | $ | — | $ | (4,552 | ) | $ | (4,552 | ) | ||||||||||
2005 | 2004 | ||||||||||||
Propane | Natural Electricity | Propane | Total | ||||||||||
(restated) | (restated) | (restated) | |||||||||||
Sales | $ | 58,722 | $ | 52,413 | $ | 348,846 | $ | 401,259 | |||||
Cost of sales | 40,079 | 46,867 | 195,100 | 241,967 | |||||||||
Delivery and branch expenses | 17,796 | — | 92,701 | 92,701 | |||||||||
Depreciation & amortization expenses | 3,481 | 258 | 20,030 | 20,288 | |||||||||
General & administrative expenses | 2,096 | 4,255 | 10,090 | 14,345 | |||||||||
(4,730 | ) | 1,033 | 30,925 | 31,958 | |||||||||
Net interest expense | 1,384 | — | 9,221 | 9,221 | |||||||||
Other loss | 27 | — | 166 | 166 | |||||||||
Income (loss) from discontinued operations before income taxes | (6,141 | ) | 1,033 | 21,538 | 22,571 | ||||||||
Income tax expense | 48 | 110 | 285 | 395 | |||||||||
Income (loss) from discontinued operations | $ | (6,189 | ) | $ | 923 | $ | 21,253 | $ | 22,176 | ||||
5)6) Quarterly Distribution of Available Cash (See Note 2.3.)
Partnership Distribution Provisions
InBeginning October 1, 2008, minimum quarterly distributions on the common units will start accruing at the rate of $0.0675 per quarter ($0.27 on an annual basis). If the Partnership elects to commence making distributions of available cash before October 1, 2008, minimum quarterly distributions will begin to accrue at such earlier date. Thereafter, in general, the Partnership has distributedintends to distribute to its partners on a quarterly basis, all of its available cash, if any, in the manner described below. “Available Cash.” Available Cashcash” generally means, with respect tofor any of its fiscal quarter,quarters, all cash on hand at the end of suchthat quarter, less the amount of cash reserves that are necessary or appropriate in the reasonable discretion of the General Partner to (1) general partners to:
Available cash reserves for distributions to the senior subordinated units unless the General Partner has determined that in its judgment the establishment of reserves will not prevent the Partnership from distributing the Minimum Quarterly Distribution (“MQD”) on all common units and any common unit arrearages thereon with respect to the next four quarters. Certain restrictions on distributions on senior subordinated units, junior subordinated units and general partner units could result in cash that would otherwise be Available Cash being reserved for other purposes. Cash distributions will be characterized as distributions from either Operating Surplus or Capital Surplus as defined in the Partnership agreement.
The senior subordinated units, the junior subordinated units, and general partner units are each a separate class of interest in Star Gas Partners, and the rights of holders of those interests to participate in distributions differ from the rights of the holders of the common units.
In general, Available Cash maygenerally be distributed per quarter based on the following priorities:as follows:
If distributions of Available Cash exceed target levels greater than $0.604, the senior subordinated units, junior subordinated units and general partner units will receive incentive distributions.
In August 2000, the Partnership commenced quarterly distributions on its senior subordinated units at an initial rate of $0.25 per unit. From February 2001 to July 2002, the Partnership increased the quarterly distributions on its senior subordinated units, junior subordinated units and general partner units to $0.575 per unit. In August 2002, the Partnership announced that it would decrease distributions to its senior subordinated units to $0.25 per unit and would eliminate the distributions to its junior subordinated units and general partner units. In April 2003, the Partnership announced that it would increase the distributions to its senior subordinated units to $0.575 per unit and that it would resume distributions of $0.575 per unit to its junior subordinated units and general partner units. In order for any subordinated unit to receive a distribution, common units must be paid all outstanding minimum quarterly distributions, including arrearages.
On October 18, 2004 the Partnership announced that it would not be permitted to make any distributions on its common units for the quarter ended September 30, 2004. The Partnership had previously announced the suspension of distributions on the senior subordinated units on July 29, 2004. The Partnership did not pay a distribution on any of its units in fiscal 2005. There are currently five quarterly arrearages on distributionssecond, 100% to the common units, aggregating $92.5 million. pro rata, until the Partnership distributes to each common unit any arrearages in payment of the minimum quarterly distribution on the common units for prior quarters;
The revolving credit facility and the MLP Notesindenture for the new notes both impose certain restrictions on the Partnership’s ability to pay distributions to unitholders (see Note 10). The Partnership believes it is unlikely that the Partnership will resume distributions on the common units, senior subordinated units, and junior subordinated units and general partner units for the foreseeable future.unitholders.
The subordination period will end once the Partnership has met the financial tests stipulated in the partnership agreement, but it generally cannot end before September 30, 2008. However, if the general partner is removed under some circumstances, the subordination period will end. When the subordination period ends, all senior subordinated units and junior subordinated units will convert into Class B common units on a one-for-one basis, and each common unit will be redesignated as a Class A common unit. The main difference between the Class A common units and Class B common units is that the Class B common units will continue to have the right to receive incentive distributions and additional units.F - 18
The subordination period will generally extend until the first day of any quarter after each of the following three events occur:
6)7) Segment Reporting
At September 30, 2006, 2005 and 2004 the Partnership had one reportable operating segment:segment, the retail distribution of heating oil. The administrative expenses and debt service costs for the public master limited partnership, Star Gas Partners, have not been allocated to the segment.
The heating oil segment is primarily engaged in the retail distribution of home heating oil, related equipment services, and equipment sales to residential and commercial customers. It operates primarily in the Northeast and Mid-Atlantic regions. Home heatingHeating oil is principally used by the Partnership’s residential and commercial customers to heat their homes and buildings, and as a result, weather conditions have a significant impact on the demand for home heating oil.
The public Master LimitedIn March 2004, the Partnership (“Partners & Others”) includessold the officestock and business of its natural gas and electricity segment to a private party. In December 2004, the Chief Executive OfficerPartnership completed the sale of all its interest in its propane segment to Inergy. In prior years, the administrative expenses and has the responsibility for, among other things, maintaining investor relations and investor reportingdebt service costs for the Partnership.public master limited partnership were not allocated to the existing segments and were disclosed separately.
The following are the statements of operations and balance sheets for the heating oil segment as of and for the periods indicated.
Years Ended September 30, | ||||||||||||||||||||||||||||||||||||
2003(1) | 2004(1) | 2005(1) | ||||||||||||||||||||||||||||||||||
(in thousands)
| Heating Oil | Partners & Others (2) | Consol. | Heating Oil | Partners & Others (2) | Consol. | Heating Oil | Partners & Others (2) | Consol. | |||||||||||||||||||||||||||
Statements of Operations | ||||||||||||||||||||||||||||||||||||
Sales: | ||||||||||||||||||||||||||||||||||||
Product | $ | 934,967 | $ | — | $ | 934,967 | $ | 921,443 | $ | — | $ | 921,443 | $ | 1,071,270 | $ | — | $ | 1,071,270 | ||||||||||||||||||
Installations and service | 168,001 | — | 168,001 | 183,648 | — | 183,648 | 188,208 | — | 188,208 | |||||||||||||||||||||||||||
Total sales | 1,102,968 | — | 1,102,968 | 1,105,091 | — | 1,105,091 | 1,259,478 | — | 1,259,478 | |||||||||||||||||||||||||||
Cost and expenses: | ||||||||||||||||||||||||||||||||||||
Cost of product | 598,397 | — | 598,397 | 594,153 | — | 594,153 | 786,349 | — | 786,349 | |||||||||||||||||||||||||||
Cost of installations and service | 195,146 | — | 195,146 | 204,902 | — | 204,902 | 197,430 | — | 197,430 | |||||||||||||||||||||||||||
Delivery and branch expenses | 217,244 | — | 217,244 | 232,985 | — | 232,985 | 231,581 | — | 231,581 | |||||||||||||||||||||||||||
Depreciation & amortization expenses | 35,535 | — | 35,535 | 37,313 | — | 37,313 | 35,480 | — | 35,480 | |||||||||||||||||||||||||||
General and administrative | 22,356 | 17,407 | 39,763 | 16,535 | 3,402 | 19,937 | 17,376 | 26,042 | 43,418 | |||||||||||||||||||||||||||
Goodwill impairment charge | — | — | — | — | — | — | 67,000 | — | 67,000 | |||||||||||||||||||||||||||
Operating income (loss) | 34,290 | (17,407 | ) | 16,883 | 19,203 | (3,402 | ) | 15,801 | (75,738 | ) | (26,042 | ) | (101,780 | ) | ||||||||||||||||||||||
Net interest expense | 22,760 | 6,770 | 29,530 | 28,038 | 8,644 | 36,682 | 21,780 | 10,058 | 31,838 | |||||||||||||||||||||||||||
Amortization of debt issuance costs | 1,655 | 383 | 2,038 | 2,750 | 730 | 3,480 | 1,718 | 822 | 2,540 | |||||||||||||||||||||||||||
(Gain) loss on redemption of debt | (212 | ) | — | (212 | ) | — | — | — | 24,192 | 17,890 | 42,082 | |||||||||||||||||||||||||
Income (loss) from continuing operations before income taxes | 10,087 | (24,560 | ) | (14,473 | ) | (11,585 | ) | (12,776 | ) | (24,361 | ) | (123,428 | ) | (54,812 | ) | (178,240 | ) | |||||||||||||||||||
Income tax expense (benefit) | 1,200 | — | 1,200 | 1,240 | — | 1,240 | 1,756 | (1,060 | ) | 696 | ||||||||||||||||||||||||||
Income (loss) from continuing operations | 8,887 | (24,560 | ) | (15,673 | ) | (12,825 | ) | (12,776 | ) | (25,601 | ) | (125,184 | ) | (53,752 | ) | (178,936 | ) | |||||||||||||||||||
Income (loss) from discontinued operations | — | 19,786 | 19,786 | — | 20,276 | 20,276 | — | (4,552 | ) | (4,552 | ) | |||||||||||||||||||||||||
Gain (loss) on sale of discontinued operations | — | — | — | — | (538 | ) | (538 | ) | — | 157,560 | 157,560 | |||||||||||||||||||||||||
Cumulative effect of change in accounting principles for discontinued operations | — | (3,901 | ) | (3,901 | ) | — | — | — | — | — | — | |||||||||||||||||||||||||
Net income (loss) | $ | 8,887 | $ | (8,675 | ) | $ | 212 | $ | (12,825 | ) | $ | 6,962 | $ | (5,863 | ) | $ | (125,184 | ) | $ | 99,256 | $ | (25,928 | ) | |||||||||||||
Capital expenditures | $ | 12,851 | $ | — | $ | 12,851 | $ | 3,984 | $ | — | $ | 3,984 | $ | 3,153 | $ | — | $ | 3,153 | ||||||||||||||||||
Total assets | $ | 622,005 | $ | 353,605 | $ | 975,610 | $ | 597,867 | $ | 363,109 | $ | 960,976 | $ | 620,872 | $ | 8,389 | $ | 629,261 | ||||||||||||||||||
6) Segment Reporting (continued)8) Change in Accounting Principle
September 30, 2004 (1) | September 30, 2005 (1) | ||||||||||||||||||||
(in thousands)
| Heating Oil | Partners & Other (2) | Consol. | Heating Oil | Partners & Other (2) | Consol. | |||||||||||||||
Balance Sheets | |||||||||||||||||||||
ASSETS | |||||||||||||||||||||
Current assets: | |||||||||||||||||||||
Cash and cash equivalents | $ | 4,561 | $ | 131 | $ | 4,692 | $ | 99,102 | $ | 46 | $ | 99,148 | |||||||||
Receivables, net | 84,005 | — | 84,005 | 89,703 | — | 89,703 | |||||||||||||||
Inventories | 34,213 | — | 34,213 | 52,461 | — | 52,461 | |||||||||||||||
Prepaid expenses and other current assets | 61,549 | (576 | ) | 60,973 | 67,908 | 2,212 | 70,120 | ||||||||||||||
Net current assets of discontinued operations | — | 50,288 | 50,288 | — | — | — | |||||||||||||||
Total current assets | 184,328 | 49,843 | 234,171 | 309,174 | 2,258 | 311,432 | |||||||||||||||
Property and equipment, net | 63,701 | — | 63,701 | 50,022 | — | 50,022 | |||||||||||||||
Long-term portion of accounts receivable | 5,458 | — | 5,458 | 3,788 | — | 3,788 | |||||||||||||||
Goodwill | 233,522 | — | 233,522 | 166,522 | — | 166,522 | |||||||||||||||
Intangibles, net | 103,925 | — | 103,925 | 82,345 | — | 82,345 | |||||||||||||||
Deferred charges & other assets, net | 6,933 | 6,952 | 13,885 | 9,021 | 6,131 | 15,152 | |||||||||||||||
Net long-term assets of discontinued operations | — | 306,314 | 306,314 | — | — | — | |||||||||||||||
Total assets | $ | 597,867 | $ | 363,109 | $ | 960,976 | $ | 620,872 | $ | 8,389 | $ | 629,261 | |||||||||
LIABILITIES AND PARTNERS’ CAPITAL | |||||||||||||||||||||
Current Liabilities: | |||||||||||||||||||||
Accounts payable | $ | 25,058 | $ | (48 | ) | $ | 25,010 | $ | 19,807 | $ | (27 | ) | $ | 19,780 | |||||||
Working capital facility borrowings | 8,000 | — | 8,000 | 6,562 | — | 6,562 | |||||||||||||||
Current maturities of long-term debt | 14,168 | 10,250 | 24,418 | 796 | — | 796 | |||||||||||||||
Accrued expenses and other current liabilities | 56,272 | 9,219 | 65,491 | 50,348 | 6,232 | 56,580 | |||||||||||||||
Due to affiliates | 1,329 | (1,329 | ) | — | (8,667 | ) | 8,667 | — | |||||||||||||
Unearned service contract revenue | 35,361 | — | 35,361 | 36,602 | — | 36,602 | |||||||||||||||
Customer credit balances | 53,927 | — | 53,927 | 65,287 | — | 65,287 | |||||||||||||||
Net current liabilities of discontinued operations | — | 50,676 | 50,676 | — | — | — | |||||||||||||||
Total current liabilities | 194,115 | 68,768 | 262,883 | 170,735 | 14,872 | 185,607 | |||||||||||||||
Long-term debt | 148,045 | 355,623 | 503,668 | 95 | 267,322 | 267,417 | |||||||||||||||
Due to affiliate | 165,684 | (165,684 | ) | — | 165,684 | (165,684 | ) | — | |||||||||||||
Other long-term liabilities | 24,654 | — | 24,654 | 27,377 | 3,752 | 31,129 | |||||||||||||||
Partners’ Capital: | |||||||||||||||||||||
Equity Capital | 65,369 | 104,402 | 169,771 | 256,981 | (111,873 | ) | 145,108 | ||||||||||||||
Total liabilities and partners’ capital | $ | 597,867 | $ | 363,109 | $ | 960,976 | $ | 620,872 | $ | 8,389 | $ | 629,261 | |||||||||
7) Inventories
The componentsAt September 30, 2005, the Partnership’s inventory of inventory were as follows (in thousands):
September 30, | ||||||
2004 | 2005 | |||||
Heating oil and other fuels | $ | 21,661 | $ | 39,858 | ||
Fuel oil parts and equipment | 12,552 | 12,603 | ||||
$ | 34,213 | $ | 52,461 | |||
Heatingheating oil and other fuelfuels were stated at the lower of cost or market computed on the first-in, first-out (FIFO) method.
Effective October 1, 2005, the Partnership changed from the FIFO method to the weighted average cost (WAC) method for its inventory of heating oil and other fuels. All other inventories, were comprisedrepresenting parts and equipment, have been and continue to be stated at the lower of 15.9cost or market using the FIFO method. The Partnership believes that the WAC methodology is preferable in the circumstances because it reflects a more accurate correlation between revenues and product costs experienced in the Partnerships business environment by normalizing the carrying cost of heating oil and other fuels given the increasing short-term volatility in the marketplace for these products. The cumulative effect of this change as of October 1, 2005 decreased net income by $0.3 million gallons and 21.3 million gallons onfor fiscal year ended September 30, 2004 and September 30, 2005, respectively.2006.
Pro forma amounts assuming the change in accounting principle is applied retroactively are:
Years Ended September 30, | |||||||||||
in thousands except per unit data | 2006 | 2005 | 2004 | ||||||||
(restated) | (restated) | ||||||||||
Net income (loss) as previously reported | $ | (54,263 | ) | $ | (21,209 | ) | $ | 23,973 | |||
Pro forma net income (loss) | $ | (53,919 | ) | $ | (21,346 | ) | $ | 24,632 | |||
General Partners interests in pro forma net income (loss) | $ | (159 | ) | $ | (192 | ) | $ | 227 | |||
Limited Partners interests in pro forma net income (loss) | $ | (53,760 | ) | $ | (21,154 | ) | $ | 24,405 | |||
Basic and fully diluted income (loss) per Limited Partner unit as previously reported | $ | (1.02 | ) | $ | (0.59 | ) | $ | 0.67 | |||
Pro forma basic and fully diluted income (loss) per Limited Partner unit | $ | (1.02 | ) | $ | (0.59 | ) | $ | 0.69 |
Inventory9) Derivative Instruments - Inventory
The Partnership periodically hedgesenters into derivatives in order to economically hedge a portion of its forecasted future home heating oil purchases through futures, options, collars and swap agreements.
Depending upon the fair value of these instruments by counterparty, the amount can be included in fair asset value of derivative instruments or fair liability value of derivative instruments. At September 30, 2006, $3.8 million was carried as a current asset in fair asset value of derivative instruments and $13.8 million carried as a current liability in fair liability value of derivative instruments. At September 30, 2005, $35.1 million was carried as a current asset in fair asset value of derivative instruments. None of the Partnerships derivative instruments qualify for hedge accounting treatment as explained in Note 4.
To economically hedge a substantial portion of the purchase price associated with heating oil gallons anticipated to be sold to its price plan customers under contract, the Partnership at September 30, 2006 had outstanding 44.9 million gallons of swap contracts to buy heating oil with a notional value of $97.8 million and a fair value of $(13.7) million; 23.7 million gallons of futures contracts to buy heating oil with a notional value of $47.9 million and a fair value of $(4.1) million; and 35.0 million gallons of purchased call option contracts to buy heating oil with a notional value of $77.5 million and a fair value of $1.7 million. To economically hedge its inventory, the Partnership at September 30, 2006 also had outstanding 4.9 million gallons of future contracts to buy heating oil with a notional value of $8.3 million and a fair value of $0.4 million; 38.5 million gallons of future contracts to sell heating oil with a notional value of $75.5 million and a fair value of $6.1 million. In addition, to economically hedge its internal fuel usage the Partnership had outstanding 1.9 million gallons of future contracts to buy gasoline with a notional value of $3.9 million and a fair value of $(0.4) million. The contracts expire at various times with no contract expiring later than October 31, 2007.
To economically hedge a substantial portion of the purchase price associated with heating oil gallons anticipated to be sold to its price plan customers under contract, the Partnership at September 30, 2005 had outstanding 26.2 million gallons of swap contracts to buy heating oil with a notional value of $41.8 million and a fair value of $13.8 million; 64.0 million gallons of futures contracts to buy heating oil with a notional value of $116.1 million and a fair value of $18.3 million;
F - 19
and 17.6 million gallons of purchased call option contracts to buy heating oil with a notional value of $38.6 million and a fair value of $4.2 million. The contracts expire at various times with no contract expiring later than September 30, 2006. The Partnership recognizes the fair value of these derivative instruments as assets.
To economically hedge a substantial portion of the purchase price associated with heating oil gallons anticipated to be sold to its price protected customers,inventory, the Partnership at September 30, 20042005 also had outstanding 74.11.0 million gallons of swapfuture contracts to buy heating oil with a notional value of $71.5$2.2 million and a fair value of $20.4$0.1 million; 30.720.5 million gallons of futuresfuture contracts to buysell heating oil with a notional value of $33.2$36.8 million and a fair value of $8.2 million; 6.6 million gallons of purchased call option contracts to buy heating oil with a notional value of $13.1 million and a fair value of $2.4$(1.3) million. TheThese contracts expired at various times with no contract expiring later than September 30, 2005. The Partnership recognizes the fair value of these derivative instruments as assets.
in fiscal 2006.
Given the staggered renewals of price-protectedprice protected contracts, the derivative instruments associated with price protected customers described in the two foregoing paragraphs represent a substantial majority of the volume anticipated to be required to satisfy the Partnership’s then established fixed and maximum price obligations for the twelve months following September 30, 20042006 and 2005, respectivelyrespectively.
ForTo the year ended September 30, 2005,extent that any derivative instruments do not meet the requirements of SFAS No. 133 to qualify for hedge accounting the Partnership recognizedrecords changes in the following for derivative instruments designated as cash flow hedges: $46.4 million gain in earnings due to instruments which settled or settled or expired during the fiscal year ended September 30, 2005, $33.4 million unrealized gain in accumulated other comprehensive income due to the effective portion of derivative instruments outstanding at September 30, 2005, and $0.8 million unrealized gain due to hedge ineffectiveness for derivative instruments outstanding at September 30, 2005. For derivative instruments accounted for as fair value hedges, the Partnership recognized a $6.9 million loss in earnings due to instruments which expired or settled during the current year, and a $1.5 million unrealized loss in earnings for the change in fair value of derivative instruments outstanding at September 30, 2005. For derivative instruments not designated as hedging instruments,in the Partnership recognized a $1.5 million unrealized lossstatement of operations in earnings for the change in fair value of derivative instruments outstanding at September 30, 2005.
For the year ended September 30, 2004, the Partnership recognized the following for derivative instruments designated as cash flow hedges: $20.6 million gain in earnings due to instruments expiring or settled during the current year, $27.3 million unrealized gain in accumulated other comprehensive income due to the effective portion of derivative instruments outstanding at September 30, 2004, and approximately $2.5 million unrealized gain in earnings resulting from hedge ineffectiveness for derivative instruments outstanding at September 30, 2004. For derivative instruments accounted for as fair value hedges, the Partnership recognized a $0.1 million loss in earnings due to instruments expiring or settled during the current year, and a $2.3 million unrealized loss in earnings for theline item change in the fair value of derivative instruments outstanding atinstruments. Realized gains and losses are recorded in cost of product with the related purchase of home heating oil for price protected customers. The following table summarizes the total derivative gains and losses included in the statement of operations.
Years Ended September 30, | ||||||||||||
2006 | 2005 | 2004 | ||||||||||
Change in the fair value of derivative instruments | $ | 45,677 | $ | (6,081 | ) | $ | (25,811 | ) | ||||
Realized (gains) and losses—included in cost of product | (17,431 | ) | (34,901 | ) | (10,870 | ) | ||||||
Total | $ | 28,246 | $ | (40,982 | ) | $ | (36,681 | ) | ||||
10) Inventories
The components of inventory were as follows (in thousands):
September 30, | ||||||
2006 | 2005 | |||||
Heating oil and other fuels | $ | 63,618 | $ | 39,858 | ||
Fuel oil parts and equipment | 12,241 | 12,603 | ||||
$ | 75,859 | $ | 52,461 | |||
Heating oil and other fuel inventories were comprised of 32.5 million gallons and 21.3 million gallons on September 30, 2004. For derivative instruments not designated as hedging instruments, the Partnership recognized a $1.9 million unrealized loss in earnings for the change in fair value of derivative instruments outstanding at2006 and September 30, 2004.2005, respectively.
The Partnership recorded $35.1 million for the fair value of all of its derivative instruments, to other current assets, at September 30, 2005. The balance of approximately $33.4 million in accumulated other comprehensive income, representing the effective portion of cash flow hedges outstanding, is expected to be reclassified into earnings, through cost of goods sold over the next 12 months.F - 20
8)11) Property, Plant and Equipment
The components of property, plant and equipment and their estimated useful lives were as follows (in thousands):
September 30, | ||||||||
2004 | 2005 | Useful Estimated Lives | ||||||
Land | $ | 11,232 | $ | 10,885 | — | |||
Buildings and leasehold improvements | 22,591 | 21,627 | 1 -40 years | |||||
Fleet and other equipment | 36,110 | 35,249 | 1 -16 years | |||||
Tanks and equipment | 7,907 | 7,438 | 8 -35 years | |||||
Furniture, fixtures and office equipment | 44,663 | 45,645 | 3 -12 years | |||||
Total | 122,503 | 120,844 | ||||||
Less accumulated depreciation | 58,802 | 70,822 | ||||||
Property and equipment, net | $ | 63,701 | $ | 50,022 | ||||
September 30, | Useful Estimated Lives | |||||||
2006 | 2005 | |||||||
Land | $ | 10,476 | $ | 10,885 | — | |||
Buildings and leasehold improvements | 21,534 | 21,627 | 1 -40 years | |||||
Fleet and other equipment | 36,487 | 35,249 | 1 -16 years | |||||
Tanks and equipment | 7,786 | 7,438 | 8 -35 years | |||||
Furniture, fixtures and office equipment | 46,219 | 45,645 | 3 -12 years | |||||
Total | 122,502 | 120,844 | ||||||
Less accumulated depreciation | 80,125 | 70,822 | ||||||
Property and equipment, net | $ | 42,377 | $ | 50,022 | ||||
Depreciation expense was $14.8$11.2 million, $15.3$13.5 million and $13.5$15.3 million for the fiscal years ended September 30, 2003,2006, 2005 and 2004, and 2005, respectively.
9)12) Goodwill and Other Intangible Assets
Under SFAS No. 142, goodwill impairment is deemed to exist if the net book value of a reporting unit exceeds its estimated fair value. If goodwill of a reporting unit is determined to be impaired, the amount of impairment is measured based on the excess of the net book value of the goodwill over the implied fair value of the goodwill. The Partnership has one reporting unit, the heating oil segment, see Note 6 – Segment Reporting.
The Partnership has selected August 31 of each year to perform its annual impairment review under SFAS No. 142. The evaluations utilize both an income and market valuation approach and contain reasonable and supportable assumptions and projections and reflect management’s best estimate of projected future cash flows. If the assumptions and estimates underlying the goodwill impairment evaluation are not achieved, a goodwill impairment charge may be necessary. On August 31, 2004, the Partnership, with the assistance of a third party valuation firm, performed its annual goodwill impairment evaluation for its reporting units and at that time determined that no impairment charge was necessary. During the second fiscal quarter of 2005, a number of events occurred that indicated a possible impairment of goodwill of the heating oil segment might exist. These events included: the Partnership’s determination in February 2005 that the Partnership could expect to generate significantly lower than expected operating results for the heating oil segment for the year and a significant decline in the Partnership’s unit price. As a result of these triggering events and circumstances, the Partnership completed an additional SFAS No. 142 impairment review of the heating oil segment with the assistance of a third party valuation firm as of February 28, 2005. The evaluation utilized both an income and market valuation approach and contained reasonable assumptions and reflected management’s best estimate of projected future cash flows. This review resulted in a non-cash goodwill impairment charge of approximately $67 million for fiscal year 2005, which reduced the carrying amount of goodwill of the heating oil segment. As ofgoodwill. On August 31, 2005, the Partnership performed its annual goodwill impairment valuation for its heating oil segment, with the assistance of a third party valuation firm. Based upon this analysis,firm and it was determined based on this analysis that there was no additional goodwill impairment.
The Partnership performed its annual goodwill impairment valuation as of August 31, 2005.
2006, and it was determined based on this analysis that there was no goodwill impairment.
A summary of changes in the Partnership’s goodwill during the fiscal years ended September 30, 20052006 and 20042005 are as follows (in thousands):
Balance as of September 30, 2003 | $ | 232,602 | ||||||
Fiscal 2004 acquisitions | 920 | |||||||
Balance as of September 30, 2004 | 233,522 | $ | 233,522 | |||||
Second fiscal quarter 2005 impairment charge | (67,000 | ) | (67,000 | ) | ||||
Balance as of September 30, 2005 | $ | 166,522 | 166,522 | |||||
Fiscal year 2006 activity | — | |||||||
Balance as of September 30, 2006 | $ | 166,522 | ||||||
F - 21
Intangible assets subject to amortization consist of the following (in thousands):
September 30, 2004 | September 30, 2005 | |||||||||||||||||
Gross Carrying Amount | Accum. Amortization | Net | Gross Carrying Amount | Accum. Amortization | Net | |||||||||||||
Customer lists | $ | 189,559 | $ | 86,332 | $ | 103,227 | $ | 189,559 | $ | 107,265 | $ | 82,294 | ||||||
Covenants not to compete | 4,736 | 4,038 | 698 | 4,755 | 4,704 | 51 | ||||||||||||
$ | 194,295 | $ | 90,370 | $ | 103,925 | $ | 194,314 | $ | 111,969 | $ | 82,345 | |||||||
Customer lists Covenants not to compete September 30, 2006 September 30, 2005 Gross
Carrying
Amount Accum.
Amortization Net Gross
Carrying
Amount Accum.
Amortization Net $ 187,604 $ 126,601 $ 61,003 $ 189,559 $ 107,265 $ 82,294 4,755 4,751 4 4,755 4,704 51 $ 192,359 $ 131,352 $ 61,007 $ 194,314 $ 111,969 $ 82,345
Amortization expense for intangible assets was $20.4$21.2 million, $21.7$21.6 million and $21.6$21.7 million for the fiscal years ended September 30, 2003,2006, 2005 and 2004, and 2005, respectively. Total estimated annual amortization expense related to intangible assets subject to amortization, for the year ended September 30, 20062007 and the four succeeding fiscal years ended September 30, is as follows (in thousands):
Amount | Amount | |||||
2006 | $ | 20,958 | ||||
2007 | $ | 20,340 | $ | 20,171 | ||
2008 | $ | 18,556 | $ | 18,386 | ||
2009 | $ | 11,706 | $ | 11,641 | ||
2010 | $ | 6,418 | $ | 6,442 | ||
2011 | $ | 4,367 |
13) Long-Term Assets Held for Sale
Prior to December 31, 2005, the Partnership received two separate offers to sell certain net assets of two separate heating oil locations in New England. The Partnership determined at that time that the assets being offered in these pending sales met the criteria as “Assets Held for Sale” in accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” Accordingly, in contemplation of the future sale of these heating oil locations, the carrying value of the assets and liabilities were reclassified on the Partnership’s Consolidated Balance Sheet. The sale of one heating oil location closed on January 18, 2006 and the Partnership recognized a gain of approximately $0.8 million. In June 2006, the Partnership decided to retain the other heating oil location and no longer hold it out for sale. The Partnership has reclassified this heating oil location from assets held for sale and has resumed normal depreciation and amortization of these assets.
Prior to June 30, 2006, the Partnership authorized the sale of three facilities located in New Jersey, Massachusetts and Rhode Island with a total net book value of $1.1 million. The Partnership determined that these facilities meet the criteria as “Assets Held for Sale” in accordance with SFAS No. 144 . Accordingly, in contemplation of the future sale of these facilities, the carrying value of the assets and liabilities were reclassified on the Partnership’s Consolidated Balance Sheet. The sale of the Rhode Island facility was finalized in July 2006 and the Partnership recognized a gain of approximately $0.1 million. The remaining two facilities at September 30, 2006 have a total net book value of $1.0 million. The New Jersey facility is still on the market and the Partnership is negotiating with suitable buyers. The Massachusetts facility was sold in December 2006 and the Partnership recognized a gain of approximately $0.2 million. The Partnership cannot provide any assurance that its activities will ultimately lead to a sale of the New Jersey facility. In the event that a suitable buyer cannot be found, the Partnership will reclassify the New Jersey facility from assets held for sale and will resume normal depreciation of the asset. No impairment has been recorded in connection with the contemplated sale, as it is anticipated that proceeds from any future sale will exceed the net book value of the assets sold.
F - 22
10)14) Accrued Expenses and Other Current Liabilities
The components of accrued expenses and other current liabilities were as follows (in thousands):
September 30, | ||||||
2006 | 2005 | |||||
Accrued wages and benefits | $ | 12,731 | $ | 10,147 | ||
Accrued workers’ compensation, general liability and auto claims | 38,808 | 33,763 | ||||
Other accrued expenses and other current liabilities | 11,112 | 12,670 | ||||
$ | 62,651 | $ | 56,580 | |||
15) Long-Term Debt and Bank Facility Borrowings
Upon the closing of the sale of the Partnership’s propane segment on December 17, 2004 all the outstanding long-term debt and bank debt of the propane segment was repaid.
The Partnership’s long-term debt at September 30, 20042006 and 2005 is as follows (in thousands):
September 30, | ||||||||
2004 | 2005 | |||||||
Partners: | ||||||||
10.25% Senior Notes (a) | $ | 267,623 | $ | 267,322 | ||||
8.04% First Mortgage Notes(b) | 51,250 | — | ||||||
8.70% First Mortgage Notes(b) | 27,500 | — | ||||||
7.89% First Mortgage Notes(b) | 17,500 | — | ||||||
Parity Debt Facility Borrowings(c) | 2,000 | — | ||||||
Heating Oil Segment: | ||||||||
7.92% Senior Notes(d) | 53,000 | — | ||||||
8.25% Senior Notes (e) | 77,000 | — | ||||||
8.96% Senior Notes(f) | 30,000 | — | ||||||
Working Capital Facility Borrowings(g) | 8,000 | 6,562 | ||||||
Acquisition Notes Payable and other(h) | 459 | 225 | ||||||
Subordinated Debentures(i) | 1,754 | 666 | ||||||
Total debt | 536,086 | 274,775 | ||||||
Less current maturities | (24,418 | ) | (796 | ) | ||||
Less working capital facility borrowings | (8,000 | ) | (6,562 | ) | ||||
Total long-term portion debt | $ | 503,668 | $ | 267,417 | ||||
September 30, | ||||||||
2006 | 2005 | |||||||
10.25% Senior Notes (a) | $ | 174,056 | $ | 267,322 | ||||
Working Capital Facility Borrowings(b) | — | 6,562 | ||||||
Acquisition Notes Payable and other | 96 | 891 | ||||||
Total debt | 174,152 | 274,775 | ||||||
Less current maturities | (96 | ) | (796 | ) | ||||
Less working capital facility borrowings | — | (6,562 | ) | |||||
Total long-term portion debt | $ | 174,056 | $ | 267,417 | ||||
(a) |
InOn April 28, 2006, in connection with the saleclosing of the propane segmentrecapitalization of the Partnership, (see Note 3), the Partnership (i) repurchased $65.3 million of Senior Notes at face value, (ii) converted $26.9 million in face amount of Senior Notes into 13.4 million common units at a conversion price of $2.00 per unit and pursuant(iii) exchanged $165.3 million in principal amount of Senior Notes for a like amount of new 10.25% senior notes due 2013 (the “new notes”) that were issued under an indenture dated as of April 28, 2006 (the “new indenture”). The Senior Notes conversion price was $2.00 per unit while the closing price of the Partnership’s units on April 27, 2006 was $2.40 per unit. As such, the Partnership recorded a loss on the conversion of the existing debt in the amount of $6.6 million, consisting of $5.4 million attributable to the difference between the above unit prices, $2.0 million due to the write off of previously capitalized net deferred financing costs reduced by a $0.8 million basis adjustment to the carrying value of long-term debt.
The terms of the new indenture are substantially the same as the terms of the indenture relating tounder which the Partnership’s 10 1/4% Senior Notes due 2013 (“MLP Notes”were issued (the “existing indenture”), except that the new indenture permits restricted payments of $22 million and allows the Partnership is permitted, within 360 daysto make acquisitions of up to $60 million without passing certain financial tests. In addition, the new indenture provides that proceeds of asset sales may not be invested in current assets for purposes of the sale, to apply“asset sale” covenant. The repurchase, conversion and exchange of the net proceeds (“Net Proceeds”)existing notes in connection with the recapitalization has resolved any claims of the participating noteholders resulting from the sale of the Partnership’s propane segment eitherbusiness in December 2004, including the Partnership’s use of such proceeds to reduce indebtednesspurchase working capital inventory and Star Gas Partners’ determination that “excess proceeds” (as defined in the existing indenture) did not include any amounts invested in such inventory and the granting of liens or collateral to the lenders pursuant to the credit facility.
The Partnership also entered into an amended and restated indenture (the “amended indenture”) for $7.6 million in face amount of Senior Notes that remained outstanding that removed most of the Partnership or of a restricted subsidiary, or to make an investment in assets or capital expenditures useful torestrictive covenants from the businessexisting indenture.
F - 23
The closing of the Partnershiprecapitalization was deemed to be a “change of control” under the existing indenture for the remaining $7.6 million in face amount of Senior Notes that were not repurchased, converted into common units or any of its subsidiaries asexchanged for new notes in effect onconnection with the issue date of the MLP Notes (the “Issue Date”) or any business related, ancillary or complimentary to any of the businesses ofrecapitalization. Consequently, the Partnership on the Issue Date (each a “Permitted Use” and collectively the “Permitted Uses”). To the extent any Net Proceeds that are not so applied exceed $10 million on December 12, 2005 (“Excess Proceeds”), the indenture requires the Partnershipwas required to make an offer to all holders of MLPrepurchase such Senior Notes to purchase for cash that number of MLP Notes that may be purchased with Excess Proceeds at a purchase price equal to 100%101% of their face value. The Partnership completed such offer on June 22, 2006, at which time the principalPartnership purchased $0.1 million in face amount of the MLP Notes plus accrued and unpaid interest to the date of purchaseSenior Notes.
(b) | In December |
In December 2004 the heating oil segment executed a new $260 million revolving credit facility agreement with a group of lenders led by JPMorgan Chase Bank, N.A. The new revolving credit facility provides the heating oil segment with the ability to borrow up to $260 million for working capital purposes (subject to certain borrowing base limitations and coverage ratios), including the issuance of up to $75 million in letters of credit. On November 3, 2005, the revolving credit facility was amended to increase the facility size by $50 million to $310 million for the peak winter months from December through March of each year. The facility expires in December 2009. This facility replaced the existing credit facilities entered into in December 2003, which totaled $235 million. The former credit facilities consisted of a working capital facility, a letter of credit facility, and an
acquisition facility. Obligations under the new revolving credit facility are secured by liens on substantially all of the assets of the heating oil segment, accounts receivable, inventory, general intangibles, and real property. Obligations under the new revolving credit facility are guaranteed by the heating oil segment’s subsidiaries and by the Partnership.
The new revolving credit facility imposes certain restrictions on the heating oil segment,Petro, including restrictions on its ability to incur additional indebtedness, to pay distributions, make investments, grant liens, sell assets, make acquisitions and engage in certain other activities. In addition, the facility imposes certain restrictions on the use of proceeds from the sale of the propane segment. The revolving credit facility also requires the heating oil segmentPetro to maintain certain financial ratios, and contains borrowing conditions and customary events of default, including nonpayment of principal or interest, violation of covenants, inaccuracy of representations and warranties, cross-defaults to other indebtedness, bankruptcy and other insolvency events. The occurrence of an event of default or an acceleration under the revolving credit facility would result in the heating oil segment’sPartnership’s inability to obtain further borrowings under that facility, which could adversely affect its results of operations. An acceleration under the revolving credit facility would result in a default under the Partnership’s other funded debt.
The heating oil segment borrowed an initial $119 million under the new revolving credit facility on December 17, 2004, which it used to repay amounts outstanding under the heating oil segment’s existing credit facilities. The heating oil segment recognized a loss of approximately $3 million as a result of the early redemption of this debt. For the year ended September 30, 2005, the weighted average interest rate for borrowings under this facility was 5.0%. At September 30, 2005, the heating oil segment had approximately $6.6 million outstanding under this credit facility. The average interest rate on the borrowings outstanding was approximately 6.0%. On November 3, 2005 the Partnership executed an amendment to this credit facility which, among other things, increased the availability under the facility from $260 million to $310 million for the four month period December 1, through March 31 of each year.
The revolving credit facility requires the Partnership to furnish an unqualified audit report for each fiscal year. On November 30, 2005, this requirement was waived for fiscal 2005. As of September 30, 2005, the Partnership was in compliance with all remaining debt covenants.
Under the terms of the revolving credit facility, the heating oil segmentPartnership must maintain at all times either availability (borrowing base less amounts borrowed and letters of credit issued) of $25.0 million or a fixed charge coverage ratio (as defined in the credit agreement) of not less than 1.1 to 1.0. As of September 30, 2005,2006, availability was $74.6$140 million and the fixed charge coverage ratio (as defined in the credit agreement) was 0.562.65 to 1.0. At September 30, 2006, restricted net assets of Petro totaled approximately $214.0 million.
On December 17, 2004, Petro borrowed $119 million under this revolving credit facility, which was used to repay amounts outstanding under its previous credit facilities and recognized a loss of approximately $3 million in fiscal year 2005, as a result of the early redemption of this debt. At September 30, 2005, $6.6 million was borrowed at an average interest rate of 6.0%. At September 30, 2006, there were no amounts outstanding under this credit facility.
As of September 30, 2005,2006, the maturities including working capital borrowings during fiscal years ending September 30, are set forth in the following table:
(in thousands)
| ||||||
2006 | $ | 7,358 | ||||
2007 | $ | 95 | $ | 96 | ||
2008 | $ | — | $ | — | ||
2009 | $ | — | $ | — | ||
2010 | $ | — | $ | — | ||
2011 | $ | — | ||||
Thereafter | $ | 267,322 | $ | 174,056 |
F - 24
11)16) Acquisitions
DuringThe Partnership made no acquisitions in fiscal 2003, the Partnership acquired three retail heating oil dealers. The aggregate purchase price was approximately $35.9 million.
2006 and 2005.
During fiscal 2004, the Partnership acquired three retail heating oil dealers. The aggregate purchase price was approximately $3.5 million.
The Partnership made no acquisitions in fiscal 2005.
The following table indicates the allocation of the aggregate purchase price paid and the respective periods of amortization assigned for fiscal 2003 and fiscal 2004 (in thousands):
2003 | 2004 | Useful Lives | ||||||
Land | $ | 500 | $ | — | — | |||
Buildings | 4,982 | — | 30 years | |||||
Furniture and equipment | 855 | 1 | 10 years | |||||
Fleet | 4,709 | — | 1-30 years | |||||
Tanks and equipment | — | 426 | 5-30 years | |||||
Customer lists | 11,171 | 2,179 | 7-10 years | |||||
Restrictive covenants | 10 | — | 1-5 years | |||||
Goodwill | 13,570 | 920 | — | |||||
Working capital | 53 | — | — | |||||
Total | $ | 35,850 | $ | 3,526 | ||||
2004 | Useful Lives | ||||
Tanks and equipment | $ | 427 | 5-30 years | ||
Customer lists | 2,179 | 7 years | |||
Goodwill | 920 | — | |||
Total | $ | 3,526 | |||
Acquisitions are accounted for under the purchase method of accounting. Purchase prices have been allocated to the acquired assets and liabilities based on their respective fair values on the dates of acquisition. The purchase prices in excess of the fair values of net assets acquired are classified as goodwill in the Consolidated Balance Sheets. Sales and net income have been included in the Consolidated Statements of Operations from the respective dates of acquisition. Customer lists are amortized on a straight line basis over seven to ten years. The weighted average useful lives of customer lists acquired in fiscal 2003 and fiscal 2004 are 7 years.
The following un-audited pro forma information presents the results of operations of the Partnership, including the acquisitions previously described, as if the acquisitions had been acquired on October 1, of the year preceding the year of purchase. This pro forma information is presented for informational purposes; it is not indicative of future operating performance.
Years Ended September 30, | |||||||
in thousands (except per unit data)
| 2003 | 2004 | |||||
Sales | $ | 1,178,582 | $ | 1,110,826 | |||
Net income (loss) | $ | 13,621 | $ | (4,274 | ) | ||
General Partner’s interest in net income (loss) | 128 | (40 | ) | ||||
Limited Partners’ interest in net income (loss) | $ | 13,493 | $ | (4,234 | ) | ||
Basic net income (loss) per limited partner unit | $ | 0.38 | $ | (0.12 | ) | ||
Diluted net income (loss) per limited partner unit | $ | 0.38 | $ | (0.12 | ) | ||
in thousands (except per unit data) Year Ended September 30, Sales Net income General Partner’s interest in net income Limited Partners’ interest in net income Basic and Diluted net income per limited partner unit
2004 (restated) $ 1,110,826 $ 25,562 237 $ 25,325 $ 0.71
12)17) Employee Benefit Plans
The heating oil segmentPartnership has a 401(k) plan, which covers certain eligible non-union and union employees. Subject to IRS limitations, the 401(k) plan provides for each employee to contribute from 1.0% to 17.0% of compensation. The Partnership makes a 4% core contribution of a participant’s compensation and matches 2/3 of each amount a participant contributes up to a maximum of 2.0% of a participant’s compensation. The Partnership’s aggregate contributions to the heating oil segment’s 401(k) plan during fiscal 2003,2006, 2005 and 2004 and 2005 were $5.2$4.4 million, $5.1 million and $5.4 million, and $5.1 million, respectively.
As a result of the Petro acquisition, theThe Partnership assumed Petro’s pension liability. Effective December 31, 1996, the heating oil segment consolidated all of its defined contribution pension plans and froze the benefits for non-union personnel covered underhas two frozen defined benefit pension plans. In 1997, the heating oil segment froze the benefits of its New York City union defined benefit pension plan as a result of operation consolidations. Benefits under the frozen defined benefit plans were generally based on years of service and each employee’s compensation. As part of the Meenan Oil Company, Inc. (“Meenan”) acquisition, the Partnership assumed the pension plan obligations and assets for Meenan’s company sponsored plan. This plan was frozen and merged into the Partnership’s defined benefit pension for non-union personnel as of January 1, 2002. Since these plans are frozen, the projected benefit obligation and the accumulated benefit obligation are the same. The Partnership’s pension expense for all defined benefit plans during fiscal 2003,2005 and 2004 was $0.8 million and 2005 were $1.6 million, $1.0 million, respectively. For 2006, the Partnership’s pension expense was $0.9 million before recording the corrections to 2005 and $0.82004 pension expense of $0.6 million respectively.as described in Note 2.
F - 25
The following tables provide a reconciliation of the changes in the heating oil segment’s plan benefit obligations, fair value of assets, and a statement of the funded status at the indicated dates (using a measurement date of September 30):
Years Ended September 30, | ||||||||||||
(in thousands)
| 2004 | 2005 | ||||||||||
Reconciliation of Benefit Obligations | ||||||||||||
Benefit obligations at beginning of year | $ | 62,004 | $ | 60,321 | ||||||||
Service cost | — | — | ||||||||||
Interest cost | 3,593 | 3,501 | ||||||||||
Actuarial loss | 827 | 5,286 | ||||||||||
Benefit payments | (5,538 | ) | (5,627 | ) | ||||||||
Settlements | (565 | ) | — | |||||||||
Benefit obligation at end of year | $ | 60,321 | $ | 63,481 | ||||||||
Reconciliation of Fair Value of Plan Assets | ||||||||||||
Fair value of plan assets at beginning of year | $ | 52,395 | $ | 51,363 | ||||||||
Actual return on plan assets | 4,486 | 4,327 | ||||||||||
Employer contributions | 585 | 19 | ||||||||||
Benefit payments | (5,538 | ) | (5,627 | ) | ||||||||
Settlements | (565 | ) | — | |||||||||
Fair value of plan assets at end of year | $ | 51,363 | $ | 50,082 | ||||||||
Funded Status | ||||||||||||
Benefit obligation | $ | 60,321 | $ | 63,481 | ||||||||
Fair value of plan assets | 51,363 | 50,082 | ||||||||||
Amount included in accumulated other comprehensive income | (16,055 | ) | (19,758 | ) | ||||||||
Unrecognized net actuarial loss | 16,055 | 19,758 | ||||||||||
Accrued benefit cost | $ | 8,958 | $ | 13,399 | ||||||||
Years Ended September 30, | ||||||||||||
(in thousands)
| 2003 | 2004 | 2005 | |||||||||
Components of Net Periodic Benefit Cost | ||||||||||||
Interest cost | 3,810 | 3,593 | 3,501 | |||||||||
Expected return on plan assets | (3,542 | ) | (4,170 | ) | (4,062 | ) | ||||||
Net amortization | 1,288 | 1,486 | 1,393 | |||||||||
Settlement loss | 4 | 116 | — | |||||||||
Net periodic benefit cost | $ | 1,560 | $ | 1,025 | $ | 832 | ||||||
Years Ended September 30, | ||||||||||||
2003 | 2004 | 2005 | ||||||||||
Weighted-Average Assumptions Used in the Measurement of the Partnership’s Benefit Obligation as of the period indicated | ||||||||||||
Discount rate | 6.00 | % | 6.00 | % | 5.50 | % | ||||||
Expected return on plan assets | 8.25 | % | 8.25 | % | 8.25 | % | ||||||
Rate of compensation increase | N/A | N/A | N/A |
12) Employee Benefit Plans - (continued)
Years Ended September 30, | ||||||||
(in thousands) | 2006 | 2005 | ||||||
(restated) | ||||||||
Reconciliation of Benefit Obligations | ||||||||
Benefit obligations at beginning of year | $ | 63,481 | $ | 60,321 | ||||
Interest cost | 3,382 | 3,501 | ||||||
Actuarial loss | 203 | 5,286 | ||||||
Benefit payments | (4,227 | ) | (5,627 | ) | ||||
Settlements | — | — | ||||||
Benefit obligation at end of year | $ | 62,839 | $ | 63,481 | ||||
Reconciliation of Fair Value of Plan Assets | ||||||||
Fair value of plan assets at beginning of year | $ | 50,082 | $ | 51,363 | ||||
Actual return on plan assets | 2,732 | 4,327 | ||||||
Employer contributions | 400 | 19 | ||||||
Benefit payments | (4,227 | ) | (5,627 | ) | ||||
Settlements | — | — | ||||||
Fair value of plan assets at end of year | $ | 48,987 | $ | 50,082 | ||||
Funded Status | ||||||||
Benefit obligation | $ | 62,839 | $ | 63,481 | ||||
Fair value of plan assets | 48,987 | 50,082 | ||||||
Amount included in accumulated other comprehensive income | (21,200 | ) | (21,263 | ) | ||||
Unrecognized net actuarial loss | 21,200 | 21,263 | ||||||
Accrued benefit cost | $ | 13,852 | $ | 13,399 | ||||
Amounts included in the Consolidated Balance Sheets | ||||||||
Prepaid benefit cost | $ | 7,348 | $ | 7,864 | ||||
Accrued benefit liability | (21,200 | ) | (21,263 | ) | ||||
Net amount recognized as excess accrual | $ | (13,852 | ) | $ | (13,399 | ) | ||
Years Ended September 30, | ||||||||||||
(in thousands) | 2006 | 2005 | 2004 | |||||||||
(restated) | (restated) | |||||||||||
Components of Net Periodic Benefit Cost | ||||||||||||
Interest cost | $ | 3,382 | $ | 3,501 | $ | 3,593 | ||||||
Expected return on plan assets | (3,912 | ) | (4,062 | ) | (4,170 | ) | ||||||
Net amortization | 1,447 | 1,090 | 1,148 | |||||||||
Settlement loss | — | — | 120 | |||||||||
Net periodic benefit cost | $ | 917 | $ | 529 | $ | 691 | ||||||
Years Ended September 30, | ||||||||||||
2006 | 2005 | 2004 | ||||||||||
Weighted-Average Assumptions Used in the Measurement of the Partnership’s Benefit Obligation as of the period indicated | ||||||||||||
Discount rate | 5.75 | % | 5.50 | % | 6.00 | % | ||||||
Expected return on plan assets | 8.25 | % | 8.25 | % | 8.25 | % | ||||||
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–relatedmarket-related value of plan assets determined using fair value.
F - 26
The Partnership’s expected long-term rate of return on plan assets is updated at least annually, taking into consideration our asset allocation, historical returns on the types of assets held, and the current economic environment. Based on these factors, the Partnership expects its pension assets will earn an average of 8.25% per annum. The expected long-term rate of return assumption was decreased from 8.50% to 8.25% effective September 30, 2003.
The Partnership’s Pension Plan assets by category are as follows (in thousands):
Years Ended September 30, | ||||||
2004 | 2005 | |||||
Asset Categories: | ||||||
Equity Securities | $ | 33,892 | $ | 33,228 | ||
Debt Securities | 17,223 | 16,690 | ||||
Cash Equivalents | 248 | 164 | ||||
$ | 51,363 | $ | 50,082 | |||
Years Ended September 30, | ||||||
2006 | 2005 | |||||
Asset Categories: | ||||||
Equity Securities | $ | 29,147 | $ | 33,228 | ||
Debt Securities | 19,477 | 16,690 | ||||
Cash Equivalents | 363 | 164 | ||||
$ | 48,987 | $ | 50,082 | |||
The Plan’s objectives are to have the ability to pay benefit and expense obligations when due, to maintain the funded ratio of the Plan, to maximize return within reasonable and prudent levels of risk in order to minimize contributions and charges to the profit and loss statement, and to control costs of administering the Plan and managing the investments of the Plan. The strategic asset allocation of the Plan (currently 67%60% domestic equities and 33%40% domestic fixed income) is based on a long termlong-term perspective and the premise that the Plan can tolerate some interim fluctuations in market value and rates of return in order to achieve long-term objectives.
The Partnership recorded an additional minimum pension liability for under-funded plans of $16.1$21.2 million at September 30, 20042006 and $19.8$21.3 million at September 30, 2005 representing the excess of unfunded accumulated benefit obligations over plan assets. A corresponding amount is recognized as a reduction of the Partnership’s capital through a charge to accumulated other comprehensive income.
Expected benefit payments over each of the next five years will total approximately $4.0$4.2 million per year. Expected benefit payments for the five years thereafter will aggregate approximately $21.8 million.
In addition, the heating oil segmentPartnership made contributions to union-administered pension plans of $6.9$6.0 million for fiscal 2003,2006, $7.9 million for fiscal 2005 and $7.4 million for fiscal 2004 and $7.9 million for fiscal 2005
2004.
The discount rate used to determine net periodic pension expense was 5.5% in 2006, 6.0% in 2005 and 6.0% in 2003 and 2004. The discount rate used by the Partnership in determining pension expense and pension obligations reflects the yield of high quality (AA or better rating by a recognized rating agency) corporate bonds whose cash flows are expected to match the timing and amounts of projected future benefit payments. The discount rates to determine net periodic expense used in each of 2003 and 2004 (6.0%) and 2005 (5.50%) reflect the decline in bond yields over the past year.
13)18) Income Taxes
Income tax expense is comprised of the following for the indicated periods (in thousands):
Years Ended September 30, | Years Ended September 30, | |||||||||||||||||
2003 | 2004 | 2005 | 2006 | 2005 | 2004 | |||||||||||||
Current: | ||||||||||||||||||
Federal | $ | — | $ | — | $ | — | $ | 112 | $ | — | $ | — | ||||||
State | 1,200 | 1,240 | 696 | 365 | 696 | 1,240 | ||||||||||||
Deferred | — | — | — | — | — | — | ||||||||||||
$ | 1,200 | $ | 1,240 | $ | 696 | $ | 477 | $ | 696 | $ | 1,240 | |||||||
F - 27
The sources of the deferred income tax expense and the tax effects are as follows (in thousands):
Years Ended September 30, | ||||||||||||
2003 | 2004 | 2005 | ||||||||||
Depreciation | $ | (1,712 | ) | $ | 614 | $ | (3,605 | ) | ||||
Amortization expense | 859 | 2,155 | (14,657 | ) | ||||||||
Vacation expense | 63 | (140 | ) | 10 | ||||||||
Restructuring expense | 41 | 52 | 52 | |||||||||
Bad debt expense | 1,800 | 1,066 | (1,084 | ) | ||||||||
Hedge accounting | (132 | ) | (489 | ) | (247 | ) | ||||||
Supplemental benefit expense | 127 | — | — | |||||||||
Pension contribution | 2,628 | (387 | ) | (349 | ) | |||||||
Other, net | (36 | ) | (114 | ) | (90 | ) | ||||||
Recognition of tax benefit of net operating loss to the extent of current and previous recognized temporary differences | (4,422 | ) | (10,726 | ) | (15,620 | ) | ||||||
Change in valuation allowance | 784 | 7,969 | 35,590 | |||||||||
$ | — | $ | — | $ | — | |||||||
Years Ended September 30, | ||||||||||||
2006 | 2005 | 2004 | ||||||||||
(restated) | (restated) | |||||||||||
Depreciation | $ | (1,293 | ) | $ | (3,017 | ) | $ | 614 | ||||
Amortization expense | 1,510 | (14,657 | ) | 2,155 | ||||||||
Vacation expense | (96 | ) | 10 | (140 | ) | |||||||
Restructuring expense | 28 | 52 | 52 | |||||||||
Bad debt expense | 196 | (1,084 | ) | 1,066 | ||||||||
Hedge accounting | (18,066 | ) | 2,321 | 8,015 | ||||||||
Pension | (182 | ) | (1,776 | ) | 260 | |||||||
Insurance expense | (6,098 | ) | — | — | ||||||||
Inventory valuation adjustment | (947 | ) | — | — | ||||||||
Other, net | (1,312 | ) | (90 | ) | (114 | ) | ||||||
Recognition of tax benefit of net operating loss to the extent of current and previous recognized temporary differences | 7,599 | (15,620 | ) | (10,726 | ) | |||||||
Change in valuation allowance | 18,661 | 33,861 | (1,182 | ) | ||||||||
$ | — | $ | — | $ | — | |||||||
The components of the net deferred taxes and the related valuation allowance for the years ended September 30, 20042006 and September 30, 2005 using current tax rates are as follows (in thousands):
Years Ended September 30, | ||||||||
2004 | 2005 | |||||||
Deferred Tax Assets: | ||||||||
Net operating loss carryforwards | $ | 57,051 | $ | 72,671 | ||||
Vacation accrual | 2,151 | 2,141 | ||||||
Restructuring accrual | 80 | 28 | ||||||
Bad debt expense | 1,725 | 2,809 | ||||||
Amortization | — | 12,772 | ||||||
Excess of book over tax hedge accounting | 611 | 858 | ||||||
Other, net | 231 | 321 | ||||||
Total deferred tax assets | 61,849 | 91,600 | ||||||
Valuation allowance | (47,469 | ) | (83,059 | ) | ||||
Net deferred tax assets | $ | 14,380 | $ | 8,541 | ||||
Deferred Tax Liabilities: | ||||||||
Amortization | $ | 1,885 | $ | — | ||||
Depreciation | 7,027 | 3,422 | ||||||
Pension contribution | 5,468 | 5,119 | ||||||
Total deferred tax liabilities | $ | 14,380 | $ | 8,541 | ||||
Net deferred taxes | $ | — | $ | — | ||||
Years Ended September 30, | ||||||||
2006 | 2005 | |||||||
(restated) | ||||||||
Deferred Tax Assets: | ||||||||
Net operating loss carryforwards | $ | 65,072 | $ | 72,671 | ||||
Vacation accrual | 2,237 | 2,141 | ||||||
Restructuring accrual | — | 28 | ||||||
Bad debt expense | 2,613 | 2,809 | ||||||
Amortization | 11,262 | 12,772 | ||||||
Excess of book over tax hedge accounting | 4,010 | — | ||||||
Insurance accrual | 6,098 | — | ||||||
Inventory valuation | 947 | — | ||||||
Pension | 5,541 | 5,360 | ||||||
Other, net | 1,633 | 321 | ||||||
Total deferred tax assets | 99,413 | 96,102 | ||||||
Valuation allowance | (96,696 | ) | (78,036 | ) | ||||
Net deferred tax assets | $ | 2,717 | $ | 18,066 | ||||
Deferred Tax Liabilities: | ||||||||
Depreciation | $ | 2,717 | $ | 4,010 | ||||
Excess of tax over book hedge accounting | — | 14,056 | ||||||
Total deferred tax liabilities | $ | 2,717 | $ | 18,066 | ||||
Net deferred taxes | $ | — | $ | — | ||||
In order to fully realize the net deferred tax assets, the Partnership’s corporate subsidiaries will need to generate future taxable income. A valuation allowance is provided when it is more likely than not that some portion of the deferred tax asset will not be realized. Based upon the level of current taxable income and projections of future taxable income of the Partnership’s corporate subsidiaries over the periods which the deferred tax assets are deductible, management believes it is more likely than not that the Partnership will not realize the full benefit of its deferred tax assets at September 30, 20042006 and 2005.
F - 28
At September 30, 2005, the Partnership2006, Star/Petro had a total federal net income taxoperating loss carryforwards for Federal income tax reporting purposescarryforward of approximately $181.7$162.7 million, of which approximately $50.1$47.9 million was limited. These carryforwards will expire between 2018 and 2024 and are limited in accordance with Federal income tax law. The losses aregenerally available to offset any future Federal taxable income through 2025.income.
It is possibleFollowing an evaluation, the Partnership has determined that the issuance of units purchased as partin its April 2006 recapitalization should not have resulted in an "ownership change" of Star/Petro under Section 382 of the recapitalization transactionInternal Revenue Code of 1986. The determination of whether or units purchased by one or more 5% unitholders would trigger an IRC Section 382 limitation related to certain net operating loss carryforwards. An ownership change occurs for purposes of Section 382 when there is a direct or indirect sale or exchange of more than 50% by one or more 5% shareholders. Ifnot an ownership change under Section 382 has occurred in accordance with Section 382, future limitations in the utilization of net operating losses could be significant. It is possiblerequires that the Partnership’s subsidiary,Partnership evaluate certain acquisitions and dispositions of units that have occurred over a rolling three-year period. As a result, future acquisitions and dispositions of units could result in an ownership change of Star/Petro, Inc., will not be able to use any of its currently existing net income tax loss carry forwards in the future.
14)19) Lease Commitments
The Partnership has entered into certain operating leases for office space, trucks and other equipment.
The future minimum rental commitments at September 30, 2005,2006, under operating leases having an initial or remaining non-cancelable term of one year or more are as follows (in thousands):
2006 | $ | 9,155 | ||||
2007 | 7,114 | $ | 8,771 | |||
2008 | 6,091 | 7,395 | ||||
2009 | 6,174 | 7,478 | ||||
2010 | 3,896 | 5,812 | ||||
2011 | 4,143 | |||||
Thereafter | 15,027 | 22,195 | ||||
Total future minimum lease payments | $ | 47,457 | $ | 55,794 | ||
The Partnership’s rentRent expense for the fiscal years ended September 30, 2003,2006, 2005 and 2004 and 2005 was $11.0$13.4 million, $14.7 million and $12.8 million, and $14.7 million, respectively.
15)20) Unit Incentive Plans
The following table summarizes information concerning common and senior subordinated UARs of the Partnership outstanding at September 30, 2005:
Price | Number of Units Outstanding | Restriction Date | |||||
$ | 7.63 | 54,715 | December 31, 2005 | ||||
$ | 7.85 | 381,304 | December 31, 2005 | ||||
$ | 10.70 | 23,086 | October 1, 2005 | ||||
$ | 11.00 | 2,500 | July 1, 2006 | ||||
Total / Weighted Average | $ | 7.99 | 461,605 | ||||
The Partnership recorded $2.6income of $2.2 million and $4.5 million for unit appreciation rights during fiscal years 2005 and 2004, respectively. In addition, in fiscal year 2004 the Partnership recorded $0.1 million of general and administrative expense for restricted unit grants during fiscal years endedgrants. At September 30, 2003 and September 30, 2004, respectively. The Partnership recorded an expense of $6.4 million and income of $4.5 million and $2.2 million for2006, there were no outstanding unit appreciation rights during fiscal years 2003, 2004 and 2005, respectively.
rights.
16)21) Supplemental Disclosure of Cash Flow Information
Years Ended September 30, | Years Ended September 30, | |||||||||||||||||||||||
(in thousands)
| 2003 | 2004 | 2005 | 2006 | 2005 | 2004 | ||||||||||||||||||
Cash paid during the period for: | ||||||||||||||||||||||||
Income taxes, net | $ | 945 | $ | 1,028 | $ | 3,022 | $ | 1,335 | $ | 3,022 | $ | 1,028 | ||||||||||||
Interest, net | 28,225 | 36,459 | 36,345 | $ | 22,392 | $ | 36,345 | $ | 36,459 | |||||||||||||||
Non-cash financing activities: | ||||||||||||||||||||||||
Decrease in other asset for interest rate swaps | 748 | 293 | — | $ | — | $ | — | $ | 293 | |||||||||||||||
Decrease in long-term debt - amortization of debt discount | (927 | ) | (293 | ) | 314 | |||||||||||||||||||
Increase (decrease) in interest expense | 179 | — | (314 | ) | ||||||||||||||||||||
Decrease in long-term debt—exchange Existing Notes | $ | (165,250 | ) | $ | — | $ | — | |||||||||||||||||
Increase in long-term debt—exchange New Notes | $ | 165,250 | $ | — | $ | — | ||||||||||||||||||
Decrease in long-term debt | $ | (27,135 | ) | $ | (314 | ) | $ | (293 | ) | |||||||||||||||
Increase Partner’s Capital—exchange debt for Common Units | $ | 32,242 | $ | — | $ | — | ||||||||||||||||||
Decrease in interest expense—amortization of debt discount | $ | 267 | $ | 314 | $ | — | ||||||||||||||||||
Increase in other current and long-term liabilities for capital leases | $ | (969 | ) | $ | — | $ | — | |||||||||||||||||
Increase in fixed assets for capital leases | $ | 969 | $ | — | $ | — |
F - 29
17)22) Commitments and Contingencies
On or about October 21, 2004, a purported class action lawsuit on behalf of a purported class of unitholders was filed against the Partnership and various subsidiaries and officers and directors in the United States District Court of the District of Connecticut entitledCarter v. Star Gas Partners, L.P., et al,No. 3:04-cv-01766-IBA, et.al.et al. Subsequently, 16 additional class action complaints, alleging the same or substantially similar claims, were filed in the same district court: (1) Feit v. Star Gas, et al. Civil Action No. 04-1832 (filed on 10/29/2004), (2) Lila Gold vs. Star Gas, et al, Civil Action No. 04-1791 (filed on 10/22/2004), (3) Jagerman v. Star Gas, et al, Civil Action No. 04-1855 (filed on 11/3/2004), (4) McCole, et al v. Star Gas, et al, Civil Action No. 04-1859 (filed on 11/3/2004), (5) Prokop vs. Star Gas, et al, Civil Action No. 04-1785 (filed on 10/22/2004), (6) Seigle v. Star Gas, et al, Civil Action No. 04-1803 (filed on 10/25/2004), (7) Strunk v. Star Gas, et al, Civil Action No. 04-1815 (filed on 10/27/2004), (8) Harriette S. & Charles L.
Tabas Foundation vs. Star Gas, et al, Civil Action No. 04-1857 (filed on 11/3/2004), (9) Weiss v. Star Gas, et al, Civil Action No. 04-1807 (filed on 10/26/2004), (10) White v. Star Gas, et al, Civil Action No. 04-1837 (filed on 10/9/2004), (11) Wood vs. Star Gas et al, Civil Action No. 04-1856 (filed on 11/3/2004), (12) Yopp vs. Star Gas, et al, Civil Action No. 04-1865 (filed on 11/3/2004), (13) Kiser v. Star Gas, et al, Civil Action No. 04-1884 (filed on 11/9/2004), (14) Lederman v. Star Gas, et al, Civil Action No. 04-1873 (filed on 11/5/2004), (15) Dinkes v. Star Gas, et al, Civil Action No. 04-1979 (filed 11/22/2004) and (16) Gould v. Star Gas, et al, Civil Action No. 04-2133 (filed on 12/17/2004) (including the Carter Complaint, collectively referred to herein as the “Class Action Complaints”). The class actions have been consolidated into one action entitled In re Star Gas Securities Litigation, No 3:04cv1766 (JBA).
The class action plaintiffs generally allege that the Partnership violated Sections 10(b) and 20(a) of the Securities Exchange Act of 1934, as amended, and Rule 10-b510b-5 promulgated thereunder,hereunder, by purportedly failing to disclose, among other things: (1) problems with the restructuring of Star Gas’s dispatch system and customer attrition related thereto; (2) that Star Gas’s heating oil segment’sGas’ business process improvement program was not generating the benefits allegedly claimed; (3) that Star Gas was struggling to maintain its profit margins in its heating oil segment;margins; (4) that Star Gas’s fiscal 2004 second quarter profit margins were not representative of its ability to pass on heating oil price increases; and (5) that Star Gas was facing an inability to pay its debts and that, as a result, its credit rating and ability to obtain future financing was in jeopardy. The class action plaintiffs seek an unspecified amount of compensatory damages including interest against the defendants jointly and severally and an award of reasonable costs and expenses. On February 23, 2005, the Court consolidated the Class Action Complaints and heard argument on motions for the appointment of lead plaintiff. On April 8, 2005, the Court appointed the lead plaintiff. Pursuant to the Court’s order, the lead plaintiff filed a consolidated amended complaint on June 20, 2005 (the “Consolidated Amended Complaint”). The Consolidated Amended Complaint named: (a) Star Gas Partners, L.P.; (b)��Star Gas LLC; (c) Irik Sevin; (d) Audrey Sevin; (e) Hanseatic Americas, Inc.; (f) Paul Biddelman; (g) Ami Trauber; (h) A.G. Edwards & Sons Inc.; (i) UBS Investment Bank; and (j) RBC Dain Rauscher Inc. as defendants. The Consolidated Amended Complaint added claims arising out of two registration statements and the same transactions under Sections 11, 12(a)(2) and 15 of the Securities Act of 1933 as well as certain allegations concerning the Partnership’s hedging practices. On September 23, 2005, defendants filed motions to dismiss the Consolidated Amended Complaint for failure to state a claim under the federal securities laws and failure to satisfy the applicable pleading requirements of the Private Securities Litigation Reform Act of 1995 (“PSLRA”),or PSLRA, and the Federal Rules of Civil Procedure. Plaintiffs filed their response to defendants’ motions to dismiss on or about November 23, 2005 and defendants are scheduled to filefiled their reply briefs on or about December 20, 2005. On July 27, 2006, the Court heard oral argument on the pending motions to dismiss. On August 21, 2006, the court issued its rulings on defendants’ motions to dismiss, granting the motions and dismissing the consolidated amended complaint in its entirety. On August 23, 2006, the court entered a judgment of dismissal. On September 7, 2006, the plaintiffs moved for reconsideration and to alter and reopen the court’s August 23, 2006 judgment of dismissal and for leave to file a second consolidated amended complaint. On October 20, 2006, defendants filed their memorandum of law in opposition to the plaintiffs’ motion. Plaintiffs filed their reply brief on or about November 20, 2006. The matter is now under consideration by the court. In the interim, discovery in the matter remains stayed pursuant to the mandatory stay provisions of the PSLRA. While no prediction may be made as to the outcome of litigation, we intend to defend against this class action vigorously.
In the event that the above action is decided adversely to the Partnership,us, it could have a material effect on our results of operations, financial condition and liquidity.
The Partnership’s operations are subject to all operating hazards and risks normally incidental to handling, storing and transporting and otherwise providing for use by consumers of combustible liquids such as propane and home heating oil.
As a result, at any given time the Partnership is a defendant in various legal proceedings and litigation arising in the ordinary course of business. The Partnership maintains insurance policies with insurers in amounts and with coverages and deductibles we believe are reasonable and prudent. However, the Partnership cannot assure that this insurance will be adequate to protect it from all material expenses related to potential future claims for personal and property damage or that
F - 30
these levels of insurance will be available in the future at economical prices. In addition, the occurrence of an explosion may have an adverse effect on the public’s desire to use the Partnership products. In the opinion of management, except as described above 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.
18)23) Disclosures About the Fair Value of Financial Instruments
Cash, Accounts Receivable, Notes Receivable, Inventory Derivative Instruments, Working Capital Facility Borrowings, and Accounts Payable
The carrying amount of cash, accounts receivable, notes receivable, working capital facility borrowings, and accounts payable approximates fair value because of the short maturity of these instruments or because they are carried at fair value.
instruments.
Derivative Instruments and Long-Term Debt
For fiscal 2004, the fair values of each of the Partnership’s long-term financing instruments, including current maturities are based on the amount of future cash flows associated with each instrument, discounted using the Partnership’s current borrowing rate for similar instruments of comparable maturity. For fiscal2006 and 2005, the fair value is based on open market or counterparty quotations.
The estimated fair value of the Partnership’s derivative instruments and long-term debt is summarized as follows (in thousands):
At September 30, 2004 | At September 30, 2005 | |||||||||||
Carrying Amount | Estimated Fair Value | Carrying Amount | Estimated Fair Value | |||||||||
Long-term debt | $ | 528,086 | $ | 557,792 | $ | 268,213 | $ | 216,866 |
At September 30, 2006 | At September 30, 2005 | |||||||||||
Carrying Amount | Estimated Fair Value | Carrying Amount | Estimated Fair Value | |||||||||
Derivative instruments included in fair asset value of derivative instruments | $ | 3,766 | $ | 3,766 | $ | 35,140 | $ | 35,140 | ||||
Derivative instruments included in fair liability value of derivative instruments | $ | 13,790 | $ | 13,790 | $ | — | $ | — | ||||
Long-term debt | $ | 174,152 | $ | 178,460 | $ | 268,213 | $ | 216,866 |
Limitations
Fair value estimates are made at a specific point in time, based on relevant market information and information about the financial instrument. These estimates are subjective in nature and involve uncertainties and matters of significant judgment and therefore cannot be determined with precision. Changes in assumptions could significantly affect the estimates.
19)24) Earnings Per Limited Partner Units
Years Ended September 30, | ||||||||||||
(in thousands, except per unit data)
| 2003 | 2004 | 2005 | |||||||||
Loss from continuing operations per Limited Partner unit: | ||||||||||||
Basic | $ | (0.48 | ) | $ | (0.72 | ) | $ | (4.95 | ) | |||
Diluted | $ | (0.48 | ) | $ | (0.72 | ) | $ | (4.95 | ) | |||
Income (loss) from discontinued operations before cumulative | ||||||||||||
Basic | $ | 0.61 | $ | 0.57 | $ | (0.13 | ) | |||||
Diluted | $ | 0.61 | $ | 0.57 | $ | (0.13 | ) | |||||
Income (loss) on sale of discontinued operations, net of income taxes per Limited Partner unit: | ||||||||||||
Basic | $ | — | $ | (0.01 | ) | $ | 4.36 | |||||
Diluted | $ | — | $ | (0.01 | ) | $ | 4.36 | |||||
Cumulative effect of change in accounting principle for adoption of SFAS No. 142 for discontinued operations per Limited Partner unit: | ||||||||||||
Basic | $ | (0.12 | ) | $ | — | $ | — | |||||
Diluted | $ | (0.12 | ) | $ | — | $ | — | |||||
Net income (loss) per Limited Partner unit: | ||||||||||||
Basic | $ | 0.01 | $ | (0.16 | ) | $ | (0.72 | ) | ||||
Diluted | $ | 0.01 | $ | (0.16 | ) | $ | (0.72 | ) | ||||
Basic Earnings Per Unit: | ||||||||||||
Net income (loss) | $ | 212 | $ | (5,863 | ) | $ | (25,928 | ) | ||||
Less: General Partners’ interest in net income (loss) | 2 | (57 | ) | (234 | ) | |||||||
Limited Partner’s interest in net income (loss) | $ | 210 | $ | (5,806 | ) | $ | (25,694 | ) | ||||
Common Units | 29,175 | 31,647 | 32,166 | |||||||||
Senior Subordinated Units | 3,139 | 3,213 | 3,310 | |||||||||
Junior Subordinated Units | 345 | 345 | 345 | |||||||||
Weighted average number of Limited Partner units outstanding | 32,659 | 35,205 | 35,821 | |||||||||
Basic earnings (loss) per unit | $ | 0.01 | $ | (0.16 | ) | $ | (0.72 | ) | ||||
Diluted Earnings Per Unit: | ||||||||||||
Effect of dilutive securities | $ | — | $ | — | $ | — | ||||||
Limited Partners’ interest in net income (loss) | $ | 210 | $ | (5,806 | ) | $ | (25,694 | ) | ||||
Effect of dilutive securities | 108 | — | — | |||||||||
Weighted average number of Limited Partner units outstanding | 32,767 | 35,205 | 35,821 | |||||||||
Diluted earnings (loss) per unit | $ | 0.01 | $ | (0.16 | ) | $ | (0.72 | ) | ||||
Years Ended September 30, | ||||||||||||
(in thousands, except per unit data) | 2006 | 2005 | 2004 | |||||||||
(restated) | (restated) | |||||||||||
Income (loss) from continuing operations per Limited Partner unit: | ||||||||||||
Basic and Diluted | $ | (1.01 | ) | $ | (4.77 | ) | $ | 0.07 | ||||
Income (loss) from discontinued operations, net of income taxes per Limited Partner Unit: | ||||||||||||
Basic and Diluted | $ | — | $ | (0.18 | ) | $ | 0.62 | |||||
Gain (loss) on sale of discontinued operations, net of income taxes per Limited Partner unit: | ||||||||||||
Basic and Diluted | $ | — | $ | 4.36 | $ | (0.02 | ) | |||||
Cumulative effect of change in accounting principles-change in inventory pricing method per Limited Partner unit: | ||||||||||||
Basic and Diluted | $ | (0.01 | ) | $ | — | $ | — | |||||
Net income (loss) per Limited Partner unit: | ||||||||||||
Basic and Diluted | $ | (1.02 | ) | $ | (0.59 | ) | $ | 0.67 | ||||
Basic and Diluted Earnings Per Limited Partner Unit: | ||||||||||||
Net income (loss) | $ | (54,263 | ) | $ | (21,209 | ) | $ | 23,973 | ||||
Less: General Partners’ interest in net income (loss) | (160 | ) | (191 | ) | 221 | |||||||
Limited Partner’s interest in net income (loss) | $ | (54,103 | ) | $ | (21,018 | ) | $ | 23,752 | ||||
Common Units | 50,804 | 32,166 | 31,647 | |||||||||
Senior Subordinated Units | 1,942 | 3,310 | 3,213 | |||||||||
Junior Subordinated Units | 198 | 345 | 345 | |||||||||
Weighted average number of Limited Partner units outstanding | 52,944 | 35,821 | 35,205 | |||||||||
F - 31
20)25) Selected Quarterly Financial Data (unaudited)
The seasonal nature of the Partnership’s business results in the sale by the Partnership of approximately 30% of its volume in the first fiscal quarter and 45% of its volume in the second fiscal quarter of each year. The Partnership generally realizes net income in both of these quarters and net losses during the quarters ending June and September.
Three Months Ended | Three Months Ended | Total | ||||||||||||||||||||||||||||||||||||||
(in thousands - except per unit data)
| Dec. 31, 2004 | Mar. 31, 2005 | Jun. 30, 2005 | Sep. 30, 2005 | Total | Dec. 31, 2005 | Mar. 31, 2006 | Jun. 30, 2006 | Sep. 30, 2006 | |||||||||||||||||||||||||||||||
(restated) | (restated) | (restated) | ||||||||||||||||||||||||||||||||||||||
Sales | $ | 414,381 | $ | 539,121 | $ | 191,514 | $ | 151,496 | $ | 1,296,512 | ||||||||||||||||||||||||||||||
Operating income (loss) | (20,434 | ) | 62,260 | (22,327 | ) | (42,697 | ) | (23,198 | ) | |||||||||||||||||||||||||||||||
Income (loss) from continuing operations before income taxes | (27,747 | ) | 54,509 | (33,608 | ) | (46,596 | ) | (53,442 | ) | |||||||||||||||||||||||||||||||
Cumulative effect of changes in accounting principles-change in inventory pricing method | (344 | ) | — | — | — | (344 | ) | |||||||||||||||||||||||||||||||||
Net income (loss) | (28,341 | ) | 54,069 | (34,076 | ) | (45,915 | ) | (54,263 | ) | |||||||||||||||||||||||||||||||
Limited Partner interest in net income (loss) | (28,082 | ) | 53,581 | (33,887 | ) | (45,715 | ) | (54,103 | ) | |||||||||||||||||||||||||||||||
Net income (loss) per Limited Partner unit: | ||||||||||||||||||||||||||||||||||||||||
Basic and diluted(a) | $ | (0.78 | ) | $ | 1.49 | $ | (0.53 | ) | $ | (0.60 | ) | $ | (1.02 | ) | ||||||||||||||||||||||||||
Three Months Ended | Total | |||||||||||||||||||||||||||||||||||||||
(in thousands - except per unit data) | Dec. 31, 2004 | Mar. 31, 2005 | Jun. 30, 2005 | Sep. 30, 2005 | ||||||||||||||||||||||||||||||||||||
(restated) | (restated) | (restated) | (restated) | (restated) | ||||||||||||||||||||||||||||||||||||
Sales | $ | 350,694 | $ | 555,317 | $ | 202,768 | $ | 150,699 | $ | 1,259,478 | $ | 350,694 | $ | 555,317 | $ | 202,768 | $ | 150,699 | $ | 1,259,478 | ||||||||||||||||||||
Operating loss | (21,028 | ) | (17,341 | ) | (23,448 | ) | (39,963 | ) | (101,780 | ) | (44,457 | ) | (2,936 | ) | (31,471 | ) | (16,560 | ) | (95,424 | ) | ||||||||||||||||||||
Loss from continuing operations before income taxes | (74,317 | ) | (25,950 | ) | (31,317 | ) | (46,656 | ) | (178,240 | ) | (97,746 | ) | (11,545 | ) | (39,340 | ) | (23,253 | ) | (171,884 | ) | ||||||||||||||||||||
Gain (loss) on sale of segments, net of income taxes | 153,644 | 2,520 | (404 | ) | 1,800 | 157,560 | ||||||||||||||||||||||||||||||||||
Net income (loss) | 74,444 | (24,099 | ) | (29,321 | ) | (46,952 | ) | (25,928 | ) | |||||||||||||||||||||||||||||||
Limited Partner interest in net income (loss) | 73,772 | (23,881 | ) | (29,056 | ) | (46,529 | ) | (25,694 | ) | |||||||||||||||||||||||||||||||
Net income (loss) per Limited Partner unit: | ||||||||||||||||||||||||||||||||||||||||
Basic and diluted | $ | 2.06 | $ | (0.67 | ) | $ | (0.81 | ) | $ | (1.30 | ) | $ | (0.72 | ) | ||||||||||||||||||||||||||
Three Months Ended | ||||||||||||||||||||||||||||||||||||||||
(in thousands - except per unit data)
| Dec. 31, 2003 | Mar. 31, 2004 | Jun. 30, 2004 | Sep. 30, 2004 | Total | |||||||||||||||||||||||||||||||||||
Sales | $ | 316,070 | $ | 481,768 | $ | 179,342 | $ | 127,911 | $ | 1,105,091 | ||||||||||||||||||||||||||||||
Operating income (loss) | 14,281 | 64,366 | (22,806 | ) | (40,040 | ) | 15,801 | |||||||||||||||||||||||||||||||||
Income (loss) from continuing operations before income taxes | 4,583 | 53,967 | (32,545 | ) | (50,366 | ) | (24,361 | ) | ||||||||||||||||||||||||||||||||
Gain (loss) on sale of segment, net of income taxes | — | 230 | (247 | ) | (521 | ) | (538 | ) | 153,644 | 2,520 | (404 | ) | 1,800 | 157,560 | ||||||||||||||||||||||||||
Net income (loss) | 19,312 | 80,653 | (42,531 | ) | (63,297 | ) | (5,863 | ) | 49,378 | (9,694 | ) | (37,344 | ) | (23,549 | ) | (21,209 | ) | |||||||||||||||||||||||
Limited Partner interest in net income (loss) | 19,118 | 79,914 | (42,126 | ) | (62,712 | ) | (5,806 | ) | 48,934 | (9,607 | ) | (37,006 | ) | (23,339 | ) | (21,018 | ) | |||||||||||||||||||||||
Net income (loss) per Limited Partner unit: | ||||||||||||||||||||||||||||||||||||||||
Basic and diluted(a) | $ | 0.56 | $ | 2.27 | $ | (1.18 | ) | $ | (1.75 | ) | $ | (0.16 | ) | $ | 1.37 | $ | (0.27 | ) | $ | (1.03 | ) | $ | (0.65 | ) | $ | (0.59 | ) |
(a) | The sum of the quarters do not add-up to the total due to the weighting of Limited Partner Units outstanding. |
21) Subsequent Events
Recapitalization
On December 2, 2005 the board of directors of Star Gas LLC approved a strategic recapitalization of Star Gas Partners, if approved by unitholders and completed, would result in a reduction in the outstanding amount of the Partnership’s 10 1/4% Senior Notes due 2013 (or “Senior Notes”), of between approximately $87 million and $100 million.
The recapitalization includes a commitment by Kestrel Energy Partners, LLC (or “Kestrel”) and its affiliates to purchase $15 million of new equity capital and provide a standby commitment in a $35 million rights offering to the Partnership’s common unitholders, at a price of $2.00 per common unit. The Partnership would utilize the $50 million in new equity financing, together with an additional $10 million from operations, to repurchase at least $60 million in face amount of its Senior Notes and, at its option, up to approximately $73.1 million of Senior Notes. In addition, certain noteholders have agreed to convert approximately $26.9 million in face amount of Senior Notes into newly issued common units at a conversion price of $2.00 per unit in connection with the closing of the recapitalization.
The Partnership has entered into agreements with the holders of approximately 94% in principal amount of its Senior Notes which provide that: the noteholders commit to, and will, tender their Senior Notes at par (i) for a pro rata portion of $60 million or, at our option, up to approximately $73.1 million in cash, (ii) in exchange for approximately 13,434,000 new common units at a conversion price of $2.00 per unit (which new units would be acquired by exchanging approximately $26.9 million in face amount of Senior Notes), and (iii) in exchange for new notes representing the remaining face amount of the tendered notes. The principle terms of the new senior notes, such as the term and interest rate are the same as the Senior Notes. The closing of the tender offer is conditioned upon the closing of the transactions under the Kestrel unit purchase agreement, which is discussed below. Upon closing the transaction the Partnership will incur a gain or loss on the exchange of Senior Notes of common units based on the difference between the $2.00 per unit conversion price and the fair value per unit represented by the per unit price in the open market on the conversion date.
Subject to and until the transaction closing, the noteholders have agreed not to accelerate indebtedness due under the Senior Notes or initiate any litigation or proceeding with respect to the Senior Notes. The noteholders have further agreed to: waive any default under the indenture; not to tender the Senior Notes in the change of control offer which will be required to be made following the closing of the transactions under the unit purchase agreement with Kestrel; and to consent to certain amendments to the existing indenture. The agreement with the noteholders further provides for the termination of its provisions in the event that the Kestrel unit purchase agreement is no longer in effect. The understandings and agreements contemplated by these transactions will terminate if the transaction does not close prior to April 30, 2006.
The Partnership believes the proposed recapitalization would substantially strengthen its balance sheet and thereby assist in meeting its liquidity and capital requirements, which it believes would improve its future financial performance and enhance unitholder value. In addition to enhancing unitholder value we believe we will be able to operate more efficiently going forward with less long-term debt.
As part of the recapitalization transaction, the Partnership has entered into a definitive unit purchase agreement with Kestrel and its affiliates, which provides for, among other things: the receipt by the Partnership of $50 million in new equity financing through the issuance to Kestrel’s affiliates of 7,500,000 common units at $2.00 per unit for an aggregate of $15 million and the issuance of an additional 17,500,000 common units in a rights offering to the Partnership’s common unitholders at an exercise price of $2.00 per unit for an aggregate of $35 million. The rights will be non-transferable, and an affiliate of Kestrel has agreed to buy any common units not subscribed for in the rights offering. Under the terms of the unit purchase agreement, Kestrel Heat, LLC, or Kestrel Heat, a wholly owned subsidiary of Kestrel, will become the new general partner and Star Gas LLC, our current general partner, will receive no consideration for its removal as general partner.
In addition, the unit purchase agreement provides for the adoption of a second amended and restated agreement of limited partnership that will, among other matters:
The recapitalization is subject to certain closing conditions including, the approval of our unitholders, approval of the lenders under the Partnership’s revolving credit facility, and the successful completion of the tender offer for the Senior Notes.
As a result of the challenging financial and operating conditions that the Partnership has experienced since fiscal 2004, it have not been able to generate sufficient available cash from operations to pay the minimum quarterly distribution of $0.575 per unit on its securities. These conditions led to the suspension of distributions on its senior subordinated units, junior subordinated units and general partner units on July 29, 2004 and to the suspension of distributions on the common units on October 18, 2004.
The Partnership believes that the proposed amendments to the Partnership agreement will simplify its capital structure, provide internally generated funds for future investment and align the minimum quarterly distribution more closely with the levels of available cash from operations that it expects to generate in the future.
It is possible that the units purchased as part of the recapitalization transaction or units purchased by one or more 5% unitholders would trigger an IRC Section 382 limitation relating to certain net operating loss carryforwards. An ownership change occurs for purposes of Section 382 when there is a direct or indirect sale or exchange of more than 50% by one or more 5% shareholders. If an ownership change has occurred in accordance with Section 382, future limitations in the utilization of net operating losses could be significant. It is possible that the Partnership’s subsidiary, Star/Petro, Inc., will not be able to use any of its currently existing net income tax loss carry forwards in the future.
F - 32
STAR GAS PARTNERS, L.P. (PARENT COMPANY)
CONDENSED FINANCIAL INFORMATION OF REGISTRANT
(in thousands) | Sept. 30, 2006 | Sept. 30, 2005 | ||||
Balance Sheets | ||||||
ASSETS | �� | |||||
Current assets | ||||||
Cash and cash equivalents | $ | 8,009 | $ | 46 | ||
Prepaid expenses and other current assets | 3,026 | 1,796 | ||||
Total current assets | 11,035 | 1,842 | ||||
Investment in subsidiaries (a) | 340,632 | 414,441 | ||||
Deferred charges and other assets, net | 3,450 | 6,131 | ||||
Total Assets | $ | 355,117 | $ | 422,414 | ||
LIABILITIES AND PARTNERS’ CAPITAL | ||||||
Current liabilities | ||||||
Accrued expenses | $ | 4,198 | $ | 6,232 | ||
Total current liabilities | 4,198 | 6,232 | ||||
Long-term debt (b) | 174,056 | 267,322 | ||||
Other long-term liabilities | 3,538 | 3,752 | ||||
Partners’ capital | 173,325 | 145,108 | ||||
Total Liabilities and Partners’ Capital | $ | 355,117 | $ | 422,414 | ||
(a) | Investments in Star Petro, 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: 2007—$0; 2008—$0; 2009—$0; 2010—$0; 2011—$0 thereafter $174,056. |
F - 33
STAR GAS PARTNERS, L.P. (PARENT COMPANY)
CONDENSED FINANCIAL INFORMATION OF REGISTRANT
Years Ended September 30, | ||||||||||||
(in thousands) | 2006 | 2005 | 2004 | |||||||||
(restated) | (restated) | |||||||||||
Statements of Operations | ||||||||||||
Revenues | $ | — | $ | — | $ | — | ||||||
General and administrative expenses | 9,403 | 26,042 | 3,402 | |||||||||
Operating loss | (9,403 | ) | (26,042 | ) | (3,402 | ) | ||||||
Net interest expense | 22,720 | 27,041 | 22,442 | |||||||||
Amortization of debt issuance costs | 702 | 822 | 730 | |||||||||
Loss on redemption of debt | 6,603 | 2,053 | — | |||||||||
Loss from continuing operations | (39,428 | ) | (55,958 | ) | (26,574 | ) | ||||||
Income (loss) from discontinued operations, net of income taxes | — | (3,171 | ) | 26,736 | ||||||||
Gain on sale of discontinued operations, net of income taxes | — | 156,803 | — | |||||||||
Net income (loss) before equity income (loss) | (39,428 | ) | 97,674 | 162 | ||||||||
Equity income (loss) of Star Petro Inc. and subs | (14,835 | ) | (118,883 | ) | 23,811 | |||||||
Net income (loss) | $ | (54,263 | ) | $ | (21,209 | ) | $ | 23,973 | ||||
F - 34
STAR GAS PARTNERS, L.P. (PARENT COMPANY)
CONDENSED FINANCIAL INFORMATION OF REGISTRANT
Years Ended September 30, | ||||||||||||
(in thousands) | 2006 | 2005 | 2004 | |||||||||
Statements of Cash Flows | ||||||||||||
Cash flows provided by operating activities: | ||||||||||||
Net cash provided by (used in) operating activities of continuing operations (a) | $ | 23,171 | $ | (11,262 | ) | $ | 26,868 | |||||
Cash flows provided by (used in) investing activities: | ||||||||||||
Cash proceeds from sale of discontinued operations | — | 466,424 | — | |||||||||
Contributions to subsidiaries | — | (441,881 | ) | (49,733 | ) | |||||||
Net cash provided by (used in) investing activities of continuing operations | — | 24,543 | (49,733 | ) | ||||||||
Cash flows provided by (used in) financing activities: | ||||||||||||
Proceeds from issuance of debt | — | — | 70,512 | |||||||||
Repayment of debt | (65,382 | ) | (2,000 | ) | — | |||||||
Distributions | — | — | (79,819 | ) | ||||||||
Proceeds from the issuance of common units, net | 50,174 | — | 34,996 | |||||||||
Increase in deferred charges | — | — | (1,409 | ) | ||||||||
Net cash provided by (used in) financing activities of continuing operations | (15,208 | ) | (2,000 | ) | 24,280 | |||||||
Cash flows of discontinued operations: | ||||||||||||
Operating activities | — | (21,402 | ) | 46,586 | ||||||||
Investing activities | — | (664 | ) | (18,589 | ) | |||||||
Financing activities | — | 10,700 | (29,293 | ) | ||||||||
Net cash provided by (used in) discontinued operations | — | (11,366 | ) | (1,296 | ) | |||||||
Net increase (decrease) in cash | 7,963 | (85 | ) | 119 | ||||||||
Cash and cash equivalents at beginning of period | 46 | 131 | 12 | |||||||||
Cash and cash equivalents at end of period | $ | 8,009 | $ | 46 | $ | 131 | ||||||
(a) Includes distributions from subsidiaries | $ | 59,038 | $ | 42,820 | $ | 55,865 | ||||||
F - 35
STAR GAS PARTNERS, L.P. AND SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTS
Years Ended September 30, 2003,2006, 2005 and 2004 and 2005
(in thousands)
Year | Description | Balance at Beginning of Year | Charged to Costs & Expenses | Other Changes Add (Deduct) | Balance at End of Year | ||||||||||
2003 | Allowance for doubtful accounts | $ | 2,960 | $ | 6,601 | $ | (3,215 | ) (a) | $ | 6,346 | |||||
2004 | Allowance for doubtful accounts | $ | 6,346 | $ | 7,646 | $ | (8,370 | ) (a) | $ | 5,622 | |||||
2005 | Allowance for doubtful accounts | $ | 5,622 | $ | 9,817 | $ | (7,006 | ) (a) | $ | 8,433 |
Year | Description | Balance at Beginning of Year | Charged to Costs & Expenses | Other Changes Add (Deduct) | Balance at End of Year | ||||||||||
2006 | Allowance for doubtful accounts | $ | 8,433 | $ | 6,104 | $ | (8,005 | ) (a) | $ | 6,532 | |||||
2005 | Allowance for doubtful accounts | $ | 5,622 | $ | 9,817 | $ | (7,006 | ) (a) | $ | 8,433 | |||||
2004 | Allowance for doubtful accounts | $ | 6,346 | $ | 7,646 | $ | (8,370 | ) (a) | $ | 5,622 |
(a) | Bad debts written off (net of recoveries). |
F-34F - 36