UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
x | Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 |
For the fiscal year ended September 24, 2011
¨ | Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 |
Commission File Number: 1-14222
SUBURBAN PROPANE PARTNERS, L.P.
(Exact name of registrant as specified in its charter)
Delaware | 22-3410353 | |
(State or other jurisdiction of | (I.R.S. Employer | |
incorporation or organization) | Identification No.) |
240 Route 10 West
Whippany, NJ 07981
(973) 887-5300
(Address, including zip code, and telephone number,
including area code, of registrant’s principal executive offices)
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. Yesþx Noo¨
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yeso¨ Noþx
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. Yesþx Noo¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yesþx Noo¨
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.þ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer | x | Accelerated filer | ¨ | |||||
Non-accelerated filer | ||||||||
Smaller reporting company | ¨ |
Indicate by check mark whether registrant is a shell company (as defined in Rule 12b-2 of the Securities Exchange Act of 1934). Yes Yeso¨ Noþx
The aggregate market value as of March 25, 201130, 2013 of the registrant’s Common Units held by non-affiliates of the registrant, based on the reported closing price of such units on the New York Stock Exchange on such date ($55.7344.50 per unit), was approximately $1,972,717,000.
Documents Incorporated by Reference: None | Total number of pages (excluding Exhibits): |
Page | ||||||||
PART I | ||||||||
ITEM 1. | BUSINESS | 1 | ||||||
ITEM 1A. | ||||||||
10 | ||||||||
ITEM 1B. | UNRESOLVED STAFF COMMENTS | 22 | ||||||
PROPERTIES | ||||||||
ITEM 3. | LEGAL PROCEEDINGS | 23 | ||||||
MINE SAFETY DISCLOSURES | ||||||||
PART II | ||||||||
ITEM | ||||||||
ITEM 6. | SELECTED FINANCIAL DATA | 25 | ||||||
7. | ||||||||
ITEM 7A. | ||||||||
ITEM 8. | ||||||||
ITEM 9. | ||||||||
ITEM 9A. | CONTROLS AND PROCEDURES | 55 | ||||||
9B. | ||||||||
56 | ||||||||
PART III | ||||||||
ITEM 10. | DIRECTORS, EXECUTIVE OFFICERS AND PARTNERSHIP GOVERNANCE | 57 | ||||||
ITEM 11. | EXECUTIVE COMPENSATION | 63 | ||||||
ITEM 12. | SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS | |||||||
ITEM 13. | ||||||||
ITEM 14. | ||||||||
PART IV | ||||||||
ITEM 15. | EXHIBITS, FINANCIAL STATEMENT SCHEDULES | 91 | ||||||
92 | ||||||||
This Annual Report on Form 10-K contains forward-looking statements (“Forward-Looking Statements”) as defined in the Private Securities Litigation Reform Act of 1995 and Section 27A of the Securities Act of 1933, as amended, relating to future business expectations and predictions and financial condition and results of operations of Suburban Propane Partners, L.P. (the “Partnership”). Some of these statements can be identified by the use of forward-looking terminology such as “prospects,” “outlook,” “believes,” “estimates,” “intends,” “may,” “will,” “should,” “anticipates,” “expects” or “plans” or the negative or other variation of these or similar words, or by discussion of trends and conditions, strategies or risks and uncertainties. These Forward-Looking Statements involve certain risks and uncertainties that could cause actual results to differ materially from those discussed or implied in such Forward-Looking Statements (statements contained in this Annual Report identifying such risks and uncertainties are referred to as “Cautionary Statements”). The risks and uncertainties and their impact on the Partnership’s results include, but are not limited to, the following risks:
Some of these Forward-Looking Statements are discussed in more detail in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in this Annual Report. On different occasions, the Partnership or its representatives have made or may make Forward-Looking Statements in other filings with the SEC, press releases or oral statements made by or with the approval of one of the Partnership’s authorized executive officers. Readers are cautioned not to place undue reliance on Forward-Looking Statements, which reflect management’s view only as of the date made. The Partnership undertakes no obligation to update any Forward-Looking Statement or Cautionary Statement, except as required by law. 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 in this Annual Report and in future SEC reports. For a more complete discussion of specific factors which could cause actual results to differ from those in the Forward-Looking Statements or Cautionary Statements, see “Risk Factors” in this Annual Report.
Development of Business
Suburban Propane Partners, L.P. (the “Partnership”), a publicly traded Delaware limited partnership, is a nationwide marketer and distributor of a diverse array of products meeting the energy needs of our customers. We specialize in the distribution of propane, fuel oil and refined fuels, as well as the marketing of natural gas and electricity in deregulated markets. In support of our core marketing and distribution operations, we install and service a variety of home comfort equipment, particularly in the areas of heating and ventilation. We believe, based onLP/Gas Magazinedated February 2011,2013, and after considering the effect of, among other transactions in the propane industry, the Inergy Propane Acquisition (as defined below), that we are the fifththird largest retail marketer of propane in the United States, measured by retail gallons sold in the calendar year 2010.2012. As of September 24, 2011,28, 2013, we were serving the energy needs of approximately 750,000more than 1.2 million residential, commercial, industrial and agricultural customers through approximately 300750 locations in 30 states located primarily41 states. Our operations are concentrated in the east and west coast regions of the United States, including Alaska.Alaska and, as a result of the Inergy Propane Acquisition, we have expanded our operating territories in the midwest region of the United States. We sold approximately 298.9534.6 million gallons of propane and 37.253.7 million gallons of fuel oil and refined fuels to retail customers during the year ended September 24, 2011.28, 2013. Together with our predecessor companies, we have been continuously engaged in the retail propane business since 1928.
We conduct our business principally through Suburban Propane, L.P., a Delaware limited partnership, which operates our propane business and assets (the “Operating Partnership”), and its direct and indirect subsidiaries. Our general partner, and the general partner of our Operating Partnership, is Suburban Energy Services Group LLC (the “General Partner”), a Delaware limited liability company whose sole member is the Chief Executive Officer of the Partnership. Since October 19, 2006, the General Partner has had no economic interest in either the Partnership or the Operating Partnership (which means that the General Partner is not entitled to any cash distributions of either partnership, nor to any cash payment upon the liquidation of either partnership, nor any other economic rights in either partnership) other than as a holder of 784 Common Units of the Partnership. Additionally, under the Third Amended and Restated Agreement of Limited Partnership (the “Partnership Agreement”) of the Partnership, there are no incentive distribution rights for the benefit of the General Partner. The Partnership owns (directly and indirectly) all of the limited partner interests in the Operating Partnership. The Common Units represent 100% of the limited partner interests in the Partnership.
On August 1, 2012 (the “Acquisition Date”), we acquired the sole membership interest in Inergy Propane, LLC, including certain wholly-owned subsidiaries of Inergy Propane LLC, and the assets of Inergy Sales and Service, Inc. (the “Inergy Propane Acquisition”). The acquired interests and assets are collectively referred to as “Inergy Propane.” As of the Acquisition Date, Inergy Propane consisted of the former retail propane assets and operations, as well as the assets and operations of the refined fuels business, of Inergy, L.P. (“Inergy”), a publicly traded limited partnership at the time of the acquisition. On the Acquisition Date, Inergy Propane and its remaining wholly-owned subsidiaries which we acquired in the Inergy Propane Acquisition became subsidiaries of our Operating Partnership, but were merged into the Operating Partnership on April 30, 2013. The results of operations of Inergy Propane are included in the Partnership’s results of operations beginning on the Acquisition Date.
With the Inergy Propane Acquisition, we effectively doubled the size of our customer base and have expanded our geographic reach into eleven (11) new states, including establishing a presence in portions of the midwest region of the United States. The Inergy Propane Acquisition is consistent with key elements of our business strategy to focus on businesses that complement our existing business segments and that can extend our presence in strategically attractive markets. This acquisition has provided, and will continue to provide, us with an opportunity to apply our operational expertise and customer-oriented initiatives to a much larger enterprise in order to enhance our growth prospects and cash flow profile. The total cost of the Inergy Propane Acquisition, as measured by the fair value of the total consideration was approximately $1.9 billion.
Direct and indirect subsidiaries of the Operating Partnership include Suburban Heating Oil Partners, LLC, which owns and operates the assets of our fuel oil and refined fuels business; Agway Energy Services, LLC, which owns and operates the assets of our natural gas and electricity business; and, Suburban Sales and Service, Inc. (the “Service Company”), which conducts a portion of the Partnership’sour service work and appliance and parts businesses. The Service Company is the sole member of Gas Connection, LLC (d/b/a HomeTown Hearth & Grill), and Suburban Franchising, LLC. HomeTown Hearth & Grill sells and installs natural gas and propane gas grills, fireplaces and related accessories and supplies through two retail stores in the northwest and northeast regions as of September 24, 2011. Suburban Franchising creates and develops propane related franchising business opportunities.
Suburban Energy Finance Corporation,Corp., a direct 100%-owned subsidiary of the Partnership, was formed on November 26, 2003 to serve as co-issuer, jointly and severally with the Partnership, of the Partnership’s senior notes. Suburban Energy Finance CorporationCorp. has nominal assets and conducts no business operations.
In this Annual Report, unless otherwise indicated, the terms “Partnership,” “Suburban,” “we,” “us,” and “our” are used to refer to Suburban Propane Partners, L.P. and its consolidated subsidiaries, including the Operating Partnership. The Partnership and the Operating Partnership and the Service Company commenced operations in March 1996 in connection with the Partnership’s initial public offering of Common Units.
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Upon written request or through an information request link from our website atwww.suburbanpropane.com, we will provide, without charge, copies of our Annual Report on Form 10-K for the year ended September 24, 2011,28, 2013, each of the Quarterly Reports on Form 10-Q, current reports filed or furnished on Form 8-K and all amendments to such reports as soon as is reasonably practicable after such reports are electronically filed with or furnished to the SEC. Requests should be directed to: Suburban Propane Partners, L.P., Investor Relations, P.O. Box 206, Whippany, New Jersey 07981-0206.
Our Strategy
Our business strategy is to deliver increasing value to our Unitholders through initiatives, both internal and external, that are geared toward achieving sustainable profitable growth and steady or increased quarterly distributions. The following are key elements of our strategy:
Internal Focus on Driving Operating Efficiencies, Right-Sizing Our Cost Structure and Enhancing Our Customer Mix.We focus internally on improving the efficiency of our existing operations, managing our cost structure and improving our customer mix. Through investments in our technology infrastructure, we continue to seek to improve operating efficiencies and the return on assets employed. We have developed a streamlined operating footprint and management structure to facilitate effective resource planning and decision making. Our internal efforts are particularly focused in the areas of route optimization, forecasting customer usage, inventory control, cash management and customer tracking.
Growing Our Customer Base by Improving Customer Retention and Acquiring New Customers.We set clear objectives to focus our employees on seeking new customers and retaining existing customers by providing highly responsive customer service. We believe that customer satisfaction is a critical factor in the growth and success of our operations.“Our Business is Customer Satisfaction”is one of our core operating philosophies. We measure and reward our customer service centers based on a combination of profitability of the individual customer service center and net customer growth.
Selective Acquisitions of Complementary Businesses or Assets.Externally, we seek to extend our presence or diversify our product offerings through selective acquisitions. Our acquisition strategy is to focus on businesses with a relatively steady cash flow that will extend our presence in strategically attractive markets, complement our existing business segments or provide an opportunity to diversify our operations with other energy-related assets. While weWe are active in this area, we are also very patient and deliberate in evaluating acquisition candidates. During fiscal 2011, weConsistent with this strategy, the Inergy Propane Acquisition, completed an acquisitionon August 1, 2012, was a transformative event for Suburban by expanding our geographic reach, doubling the size of a mid-sized propane business in a market where we already have a strong presence. During fiscal 2010 we completed four acquisitions of mid-sized propane businesses; there were no acquisitions completed during fiscal 2009. These acquisitions complemented our existing operations, expanded our customer base and providing us with opportunities to achieve operational synergies by combining operations in overlapping territories and implementing our focusoperating model and systems platform on operational efficiencies, provided synergies through the blending of operations and assets into our existing facilities.
Selective Disposition of Non-Strategic Assets.We continuously evaluate our existing facilities to identify opportunities to optimize our return on assets by selectively divesting operations in slower growing markets, generating proceeds that can be reinvested in markets that present greater opportunities for growth. Our objective is to maximize the growth and profit potential of all of our assets.
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We manage and evaluate our operations in five operating segments, three of which are reportable segments: Propane, Fuel Oil and Refined Fuels and Natural Gas and Electricity. These business segments are described below. See the Notes to the Consolidated Financial Statements included in this Annual Report for financial information about our business segments.
Propane
Propane is aby-product of natural gas processing and petroleum refining. It is a clean burning energy source recognized for its transportability and ease of use relative to alternative forms ofstand-alone energy sources. Propane use falls into three broad categories:
industrial applications; and | |||
In the residential and commercial markets, propane is used primarily for space heating, water heating, clothes drying and cooking. Industrial customers use propane generally as a motor fuel to powerover-the-road vehicles, forklifts and stationary engines, to fire furnaces, as a cutting gas and in other process applications. In the agricultural market, propane is primarily used for tobacco curing, crop drying, poultry brooding and weed control.
Propane is extracted from natural gas or oil wellhead gas at processing plants or separated from crude oil during the refining process. It is normally transported and stored in a liquid state under moderate pressure or refrigeration for ease of handling in shipping and distribution. When the pressure is released or the temperature is increased, propane becomes a flammable gas that is colorless and odorless, although an odorant is added to allow its detection. Propane is clean burning and, when consumed, produces only negligible amounts of pollutants.
Product Distribution and Marketing
We distribute propane through a nationwide retail distribution network consisting of approximately 300750 locations in 3041 states as of September 24, 2011.28, 2013. Our operations are concentrated in the east and west coast regions of the United States, including Alaska.Alaska and, as a result of the Inergy Propane Acquisition, we expanded our operating territories into the midwest region of the United States. As of September 24, 2011,28, 2013, we serviced approximately 608,0001,062,000 propane customers. Typically, our customer service centers are located in suburban and rural areas where natural gas is not readily available. Generally, these customer service centers consist of an office, appliance showroom, warehouse and service facilities, with one or more 18,000 to 30,000 gallon storage tanks on the premises. Most of our residential customers receive their propane supply through an automatic delivery system. These deliveries are scheduled through computer technology, based upon each customer’s historical consumption patterns and prevailing weather conditions. Additionally, we offer our customers a budget payment plan whereby the customer’s estimated annual propane purchases and service contracts are paid for in a series of estimated equal monthly payments over a twelve-month period. From our customer service centers, we also sell, install and service equipment to customers who purchase propane from us including heating and cooking appliances, hearth products and supplies and, at some locations, propane fuel systems for motor vehicles.
We sell propane primarily to six customer markets: residential, commercial, industrial (including engine fuel), agricultural, other retail users and wholesale. Approximately 91%97% of the propane gallons sold by us in fiscal 20112013 were to retail customers: 45%49% to residential customers, 28%29% to commercial customers, 8%6% to industrial customers, 4%5% to agricultural customers and 15%11% to other retail users. The balance of approximately 9%3% of the propane gallons sold by us in fiscal 20112013 was for risk management activities and wholesale customers. No single customer accounted for 10% or more of our propane revenues during fiscal 2011.
2013.
3
Supply
Our propane supply is purchased from approximately 6165 oil companies and natural gas processors at approximately 110160 supply points located in the United States and Canada. We make purchases primarily under one-year agreements that are subject to annual renewal, and also purchase propane on the spot market. Supply contracts generally provide for pricing in accordance with posted prices at the time of delivery or the current prices established at major storage points, and some contracts include a pricing formula that typically is based on prevailing market prices. Some of these agreements provide maximum and minimum seasonal purchase guidelines. Propane is generally transported from refineries, pipeline terminals, storage facilities (including our storage facility in Elk Grove, California) and coastal terminals to our customer service centers by a combination of common carriers,owner-operators and railroad tank cars. See Item 2 of this Annual Report.
Historically, supplies of propane have been readily available from our supply sources. Although we make no assurance regarding the availability of supplies of propane in the future, we currently expect to be able to secure adequate supplies during fiscal 2012.2014. During fiscal 2011,2013, Inergy Services (a subsidiary of Inergy) and Targa Liquids Marketing and Trade (“Targa”) and Enterprise Products Operating L.P. (“Enterprise”) provided approximately 17%34% and 11%12% of our total propane purchases, respectively. No other single supplier accounted for more than 10% of our propane purchases in fiscal 2013. In connection with the Inergy Propane Acquisition, we entered into a supply agreement with Inergy for the supply of propane to the majority of the acquired Inergy Propane operations through April 2014. Pricing under the supply agreement with Inergy is similar to our existing annual supply arrangements in that it provides for formula pricing at the time of delivery based on major supply points. We expect Inergy to remain one of our largest propane suppliers in fiscal 2014. The availability of our propane supply is dependent on several factors, including the severity of winter weather and the price and availability of competing fuels, such as natural gas and fuel oil. We believe that if supplies from Targa or Enterprisethe aforementioned suppliers were interrupted, we would be able to secure adequate propane supplies from other sources without a material disruption of our operations. Nevertheless, the cost of acquiring such propane might be higher and, at least on a short-term basis, our margins could be affected. Approximately 96%99% of our total propane purchases were from domestic suppliers in fiscal 2011.
We seek to reduce the effect of propane price volatility on our product costs and to help ensure the availability of propane during periods of short supply. We are currently a party to forward and option contracts with various third parties to purchase and sell propane at fixed prices in the future. These activities are monitored by our senior management through enforcement of our Hedging and Risk Management Policy. See Items 7 and 7A of this Annual Report.
We own and operate a large propane storage facility in California. We also operate smaller storage facilities in other locations and have rights to use storage facilities in additional locations. These storage facilities enable us to buy and store large quantities of propane particularly during periods of low demand, which generally occur during the summer months. This practice helps ensure a more secure supply of propane during periods of intense demand or price instability. As of September 24, 2011,28, 2013, the majority of our storage capacity in California was leased to third parties.
Competition
According to the Energy Information Administration’s Short-Term Energy Outlook Model Documentation (November 2009),US Census Bureau’s 2012 American Community Survey, propane ranks as the fourth most important source of residential energy in the nation, with about 5% of all households using propane as their primary space heating fuel. This level has not changed materially over the previous two decades. As an energy source, propane competes primarily with natural gas, electricity and fuel oil, principally on the basis of price, availability and portability.
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Propane has some relative advantages over other energy sources. For example, in certain geographic areas, propane is generally less expensive to use than electricity for space heating, water heating, clothes drying and cooking. Utilization of fuel oil is geographically limited (primarily in the northeast), and even in that region, propane and fuel oil are not significant competitors because of the cost of converting from one to the other.
In addition to competing with suppliers of other energy sources, our propane operations compete with other retail propane distributors. The retail propane industry is highly fragmented and competition generally occurs on a local basis with other large full-service multi-state propane marketers, thousands of smaller local independent marketers and farm cooperatives. Based on industry statistics contained in20092011 Sales of Natural Gas Liquids and Liquefied Refinery Gases, as published by the American Petroleum Institute in December 2010,February 2013, andLP/Gas Magazine dated February 2011,2013, the ten largest retailers, including us, account for approximately 39%35% of the total retail sales of propane in the United States. For fiscal years 2009 through 2011, no single marketer had a greater than 10% share of the total retail propane market in the United States. Each of our customer service centers operates in its own competitive environment because retail marketers tend to locate in close proximity to customers in order to lower the cost of providing service. Our typical customer service center has an effective marketing radius of approximately 50 miles, although in certain areas the marketing radius may be extended by one or more satellite offices. Most of our customer service centers compete with five or more marketers or distributors.
Fuel Oil and Refined Fuels
Product Distribution and Marketing
We market and distribute fuel oil, kerosene, diesel fuel and gasoline to approximately 48,00068,000 residential and commercial customers primarily in the northeast region of the United States. Sales of fuel oil and refined fuels for fiscal 20112013 amounted to 37.253.7 million gallons. Approximately 71%65% of the fuel oil and refined fuels gallons sold by us in fiscal 20112013 were to residential customers, principally for home heating, 4%11% were to commercial customers, 1% were to agricultural and 5%2% to other users. Sales of diesel and gasoline accounted for the remaining 19%22% of total volumes sold in this segment during fiscal 2011.2013. Fuel oil has a more limited use, compared to propane, and is used almost exclusively for space and water heating in residential and commercial buildings. We sell diesel fuel and gasoline to commercial and industrial customers for use primarily to operate motor vehicles.
Approximately 46%43% of our fuel oil customers receive their fuel oil under an automatic delivery system. These deliveries are scheduled through computer technology, based upon each customer’s historical consumption patterns and prevailing weather conditions. Additionally, we offer our customers a budget payment plan whereby the customer’s estimated annual fuel oil purchases are paid for in a series of estimated equal monthly payments over a twelve-month period. From our customer service centers, we also sell, install and service equipment to customers who purchase fuel oil from us including heating appliances.
Deliveries of fuel oil are usually made to customers by means of tankwagon trucks, which have capacities ranging from 2,500 gallons to 3,000 gallons. Fuel oil is pumped from the tankwagon truck into a stationary storage tank that is located on the customer’s premises, which is owned by the customer. The capacity of customer storage tanks ranges from approximately 275 gallons to approximately 1,000 gallons. No single customer accounted for 10% or more of our fuel oil revenues during fiscal 2011.
2013.
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We obtain fuel oil and other refined fuels in pipeline, truckload or tankwagon quantities, and have contracts with certain pipeline and terminal operators for the right to temporarily store fuel oil at 1314 terminal facilities we do not own. We have arrangements with certain suppliers of fuel oil, which provide open access to fuel oil at specific terminals throughout the northeast. Additionally, a portion of our purchases of fuel oil are made at local wholesale terminal racks. In most cases, the supply contracts do not establish the price of fuel oil in advance; rather, prices are typically established based upon market prices at the time of delivery plus or minus a differential for transportation and volume discounts. We purchase fuel oil from more than 20approximately 40 suppliers at approximately 6050 supply points. While fuel oil supply is more susceptible to longer periods of supply constraint than propane, we believe that our supply arrangements will provide us with sufficient supply sources. Although we make no assurance regarding the availability of supplies of fuel oil in the future, we currently expect to be able to secure adequate supplies during fiscal 2012.
Competition
The fuel oil industry is a mature industry with total demand expected to remain relatively flat to moderately declining. The fuel oil industry is highly fragmented, characterized by a large number of relatively small, independently owned and operated local distributors. We compete with other fuel oil distributors offering a broad range of services and prices, from full service distributors to those that solely offer the delivery service. We have developed a wide range of sales programs and service offerings for our fuel oil customer base in an attempt to be viewed as a full service energy provider and to build customer loyalty. For instance, like most companies in the fuel oil business, we provide home heating equipment repair service to our fuel oil customers on a 24-hour a day basis. The fuel oil business unit also competes for retail customers with suppliers of alternative energy sources, principally natural gas, propane and electricity.
Natural Gas and Electricity
We market natural gas and electricity through our 100%-owned subsidiary, Agway Energy Services, LLC (“AES”), in the deregulated markets of New York and Pennsylvania primarily to residential and small commercial customers. Historically, local utility companies provided their customers with all three aspects of electric and natural gas service: generation, transmission and distribution. However, under deregulation, public utility commissions in several states are licensing energy service companies, such as AES, to act as alternative suppliers of the commodity to end consumers. In essence, we make arrangements for the supply of electricity or natural gas to specific delivery points. The local utility companies continue to distribute electricity and natural gas on their distribution systems. The business strategy of this business segment is to expand its market share by concentrating on growth in the customer base and expansion into other deregulated markets that are considered strategic markets.
We serve nearly 87,000 natural gas and electricity customers in New York and Pennsylvania. During fiscal 2011,2013, we sold approximately 4.14.2 million dekatherms of natural gas and 613.9550.6 million kilowatt hours of electricity through the natural gas and electricity segment. Approximately 75%82% of our customers were residential households and the remainder were small commercial and industrial customers. New accounts are obtained through numerous marketing and advertising programs, including telemarketing and direct mail initiatives. Most local utility companies have established billing service arrangements whereby customers receive a single bill from the local utility company which includes distribution charges from the local utility company, as well as product charges for the amount of natural gas or electricity provided by AES and utilized by the customer. We have arrangements with several local utility companies that provide billing and collection services for a fee. Under these arrangements, we are paid by the local utility company for all or a portion of customer billings after a specified number of days following the customer billing with no further recourse to AES.
Supply of natural gas is arranged through annual supply agreements with major national wholesale suppliers. Pricing under the annual natural gas supply contracts is based on posted market prices at the time of delivery, and some contracts include a pricing formula that typically is based on prevailing market prices. The majority of our electricity requirements isare purchased through the New York Independent System Operator (“NYISO”) under an annual supply agreement, as well as purchase arrangements through other national wholesale suppliers on the open market. Electricity pricing under the NYISO agreement is based on local market indices at the time of delivery. Competition is primarily with local utility companies, as well as other marketers of natural gas and electricity providing similar alternatives as AES.
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We sell, install and service various types of whole-house heating products, air cleaners, humidifiers, hearth products and space heaters to the customers of our propane, fuel oil, natural gas and electricity businesses. Our supply needs are filled through supply arrangements with several large regional equipment manufacturers and distribution companies. Competition in this business segment is primarily with small, local heating and ventilation providers and contractors, as well as, to a lesser extent, other regional service providers. The focus of our ongoing service offerings are in support of the service needs of our existing customer base within our propane, refined fuels and natural gas and electricity business segments. Additionally, we have entered into arrangements with third-party service providers to complement and, in certain instances, supplement our existing service capabilities.
Seasonality
The retail propane and fuel oil distribution businesses, as well as the natural gas marketing business, are seasonal because the primary use of these fuels is for heating residential and commercial buildings. Historically, approximatelytwo-thirds of our retail propane volume is sold during the six-month peak heating season from October through March. The fuel oil business tends to experience greater seasonality given its more limited use for space heating, and approximately three-fourths of our fuel oil volumes are sold between October and March. Consequently, sales and operating profits are concentrated in our first and second fiscal quarters. Cash flows from operations, therefore, are greatest during the second and third fiscal quarters when customers pay for product purchased during the winter heating season. We expect lower operating profits and either net losses or lower net income during the period from April through September (our third and fourth fiscal quarters).
Weather conditions have a significant impact on the demand for our products, in particular propane, fuel oil and natural gas, for both heating and agricultural purposes. Many of our customers rely on propane, fuel oil or natural gas primarily as a heating source. Accordingly, the volume sold is directly affected by the severity of the winter weather in our service areas, which can vary substantially from year to year. In any given area, sustained warmer than normal temperatures will tend to result in reduced propane, fuel oil and natural gas consumption, while sustained colder than normal temperatures will tend to result in greater consumption.
Trademarks and Tradenames
We utilize a variety of trademarks and tradenames owned by us, including “Suburban Propane,” “Gas Connection,”Propane” and “Suburban Cylinder Express” and “HomeTown Hearth & Grill.Express.” As part of the Inergy Propane Acquisition, we acquired a number of different tradenames, such as “Yates Gas,” under which Inergy Propane conducted its business as of the Acquisition Date. Additionally, we hold rights to certain trademarks and tradenames, including “Agway Propane,” “Agway” and “Agway Energy Products” in connection with the distribution of petroleum-based fuel and sales and service of heating and ventilation products. We regard our trademarks, tradenames and other proprietary rights as valuable assets and believe that they have significant value in the marketing of our products and services.
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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 hazardous materials and pollutants and establish standards for the handling, transportation, treatment, storage and disposal of solid and hazardous wastes and can require the investigation and cleanup of environmental contamination. 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 liability 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. Propane is not a hazardous substance within the meaning of CERCLA, whereas some constituents contained in fuel oil are considered hazardous substances. We own real property at locations where such hazardous substances may be present as a result of prior activities.
We expect that we will be required to expend funds to participate in the remediation of certain sites, including sites where we have been designated by the Environmental Protection Agency as a potentially responsible party under CERCLA or comparable state statutes and at sites with aboveground and underground fuel storage tanks. We will also incur other expenses associated with environmental compliance. We continually monitor our operations with respect to potential environmental issues, including changes in legal requirements and remediation technologies.
Through an acquisition in fiscal 2004, and in the Inergy Propane Acquisition, we acquired certain properties with either known or probable environmental exposure, some of which are currently in varying stages of investigation, remediation or monitoring. Additionally, we identified that certain of the active sites acquired contained environmental conditions which required further investigation, future remediation or ongoing monitoring activities. The environmental exposures included instances of soil and/or groundwater contamination associated with the handling and storage of fuel oil, gasoline and diesel fuel. With respect to certain of the properties acquired in the Inergy Propane Acquisition, Inergy is contractually obligated to indemnify us for the costs associated with the investigation, monitoring, remediation and/or resolution of identified conditions. As of September 24, 2011,28, 2013, we had accrued environmental liabilities of $0.6$0.7 million representing the total estimated future liability for remediation and monitoring.
Estimating the extent of our responsibility at a particular site, and the method and ultimate cost of remediation of that site, requires making numerous assumptions. As a result, the ultimate cost to remediate any site may differ from current estimates, and will depend, in part, on whether there is additional contamination, not currently known to us, at that site. However, we believe that our past experience provides a reasonable basis for estimating these liabilities. As additional information becomes available, estimates are adjusted as necessary. While we do not anticipate that any such adjustment would be material to our financial statements, the result of ongoing or future environmental studies or other factors could alter this expectation and require recording additional liabilities. We currently cannot determine whether we will incur additional liabilities or the extent or amount of any such liabilities.
National Fire Protection Association (“NFPA”) Pamphlet Nos. 54 and 58, which establish rules and procedures governing the safe handling of propane, or comparable regulations, have been adopted, in whole, in part or with state addenda, as the industry standard for propane storage, distribution and equipment installation and operation in all of the states in which we operate. In some states these laws are administered by state agencies, and in others they are administered on a municipal level.
NFPA Pamphlet Nos. 30, 30A, 31, 385 and 395, which establish rules and procedures governing the safe handling of distillates (fuel oil, kerosene and diesel fuel) and gasoline, or comparable regulations, have been adopted, in whole, in part or with state addenda, as the industry standard for fuel oil, kerosene, diesel fuel and gasoline storage, distribution and equipment installation/operation in all of the states in which we sell those products. In some states these laws are administered by state agencies and in others they are administered on a municipal level.
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The Department of Homeland Security (“DHS”) has published regulations under 6 CFR Part 27 Chemical Facility Anti-Terrorism Standards. We have 4741,180 facilities registered with the DHS, of which 4541,161 facilities have been determined to be “Not a High Risk Chemical Facility”. 20Nineteen facilities have been determined by DHS to be High Risk, Tier 4 (lowest level of security risk). Security Vulnerability Assessments for the 2019 facilities have been submitted to the DHS and the DHS has reviewed 17 of them, requiring us to submit Site Security Plans for those facilities. Pending DHS review,are being prepared when deemed necessary by the remaining 3 facilities may require Site Security Plans within 90 days of DHS notification.DHS. Because our facilities are currently operating under the security programs developed under guidelines issued by the Department of Transportation, Department of Labor and Environmental Protection Agency, we do not anticipate that we will incur significant costs in order to comply with these DHS regulations.
In December 2009, the U.S. Environmental Protection Agency (“EPA”) issued an “Endangerment Finding” under the Clean Air Act, determining that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) present an endangerment to public health and the environment because emissions of such gases may be contributing to warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of GHGs and require reporting by certain regulated facilities on an annual basis.
Both Houses of the United States Congress also have considered adopting legislation to reduce emissions of GHGs. In June 2009, the American Clean Energy and Security Act of 2009, also known as the Waxman-Markey Bill, passed in the U.S. House of Representatives, but the U.S. Senate’s version, The Clean Energy Jobs and American Power Act, or the Boxer-Kerry Bill, didHowever, Congress has not pass. Both bills sought to establish a “cap and trade” system for restricting GHG emissions. Under such system, certain sources of GHG emissions would be required to obtain GHG emission “allowances” corresponding to their annual emissions of GHGs. The number of emission allowances issued each year would decline as necessary to meet overall emission reduction goals. As the number of GHG emission allowances declines each year, the cost or value of allowances is expected to escalate significantly.
The adoption of federal or state climate change legislation or regulatory programs to reduce emissions of GHGs could require us to incur increased capital and operating costs, with resulting impact on product price and demand. We cannot predict whether or in what form cap-and-tradeclimate change legislation provisions and renewable energy standards may be enacted. In addition, a possible consequence of climate change is increased volatility in seasonal temperatures. It is difficult to predict how the market for our fuels would be affected by increased temperature volatility, although if there is an overall trend of warmer temperatures, it could adversely affect our business.
Future developments, such as stricter environmental, health or safety laws and regulations thereunder, could affect our operations. We do not anticipate that the cost of our compliance with environmental, health and safety laws and regulations, including CERCLA, as currently in effect and applicable to known sites will have a material adverse effect on our financial condition or results of operations. To the extent we discover any environmental liabilities presently unknown to us or environmental, health or safety laws or regulations are made more stringent, however, there can be no assurance that our financial condition or results of operations will not be materially and adversely affected.
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The Dodd-Frank Act requires the Commodity Futures Trading Commission (the “CFTC”) and the SEC to promulgate rules and regulations relating to, among other things, swaps, participants in the derivatives markets, clearing of swaps and reporting of swap transactions. In general, the Dodd-Frank Act subjects swap transactions and participants to greater regulation and supervision by the CFTC and the SEC and will require many swaps to be cleared through a registered CFTC- or SEC-clearing facility and executed on a designated exchange or swap execution facility. There are some exceptions to these requirements for entities that use swaps to hedge or mitigate commercial risk. While we may ultimately be eligible for such exceptions, the scope of these exceptions currently is somewhat uncertain, pending further definition through rulemaking.
Among the other provisions of the Dodd-Frank Act that may affect derivative transactions are those relating to establishment of capital and margin requirements for certain derivative participants; establishment of business conduct standards, recordkeeping and reporting requirements; and imposition of position limits.
The new legislation and regulations promulgated thereunder could increase the operational and transactional cost of derivatives contracts and affect the number and/or creditworthiness of counterparties available to us.
Employees
As of September 24, 2011,28, 2013, we had 2,3853,933 full time employees, of whom 477683 were engaged in general and administrative activities (including fleet maintenance), 3739 were engaged in transportation and product supply activities and 1,8713,211 were customer service center employees. As of September 24, 2011, 4428, 2013, 127 of our employees were represented by 516 different local chapters of labor unions. We believe that our relations with both our union andnon-union employees are satisfactory. From time to time, we hire temporary workers to meet peak seasonal demands.
Investing in our common units involves a high degree of risk. The most significant risks include those described below; however, additional risks that we currently do not know about may also impair our business operations. You should carefully consider the following risk factors, as well as the other information in this Annual Report. If any of the following risks actually occurs, our business, results of operations and financial condition could be materially adversely affected. In this case, the trading price of our common units would likely decline and you might lose part or all of the value in our common units. You should carefully consider the specific risk factors set forth below as well as the other information contained or incorporated by reference in this Annual Report. Some factors in this section are Forward-Looking Statements.Statements. See “Disclosure Regarding Forward-Looking Statements” aboveabove..
Risks Inherent in ourRelated to Our Business Operations
Since weather conditions may adversely affect demand for propane, fuel oil and other refined fuels and natural gas, our results of operations and financial condition are vulnerable to warm winters.
Weather conditions have a significant impact on the demand for propane, fuel oil and other refined fuels and natural gas for both heating and agricultural purposes. Many of our customers rely on propane, fuel oil or natural gas primarily as a heating source. The volume of propane, fuel oil and natural gas sold is at its highest during the six-month peak heating season of October through March and is directly affected by the severity of the winter. Typically, we sell approximately two-thirds of our retail propane volume and approximately three-fourths of our retail fuel oil volume during the peak heating season.
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Sudden increases in the price of propane, fuel oil and other refined fuels and natural gas due to, among other things, our inability to obtain adequate supplies from our usual suppliers, may adversely affect our operating results.
Our profitability in the retail propane, fuel oil and refined fuels and natural gas businesses is largely dependent on the difference between our product cost and retail sales price. Propane, fuel oil and other refined fuels and natural gas are commodities, and the unit price we pay is subject to volatile changes in response to changes in supply or other market conditions over which we have no control, including the severity of winter weather and the price and availability of competing alternative energy sources. In general, product supply contracts permit suppliers to charge posted prices at the time of delivery or the current prices established at major supply points, including Mont Belvieu, Texas, and Conway, Kansas. In addition, our supply from our usual sources may be interrupted due to reasons that are beyond our control. As a result, the cost of acquiring propane, fuel oil and other refined fuels and natural gas from other suppliers might be materially higher at least on a short-term basis. Since we may not be able to pass on to our customers immediately, or in full, all increases in our wholesale cost of propane, fuel oil and other refined fuels and natural gas, these increases could reduce our profitability. We engage in transactions to manage the price risk associated with certain of our product costs from time to time in an attempt to reduce cost volatility and to help ensure availability of product. We can give no assurance that future volatility in propane, fuel oil and natural gas supply costs will not have a material adverse effect on our profitability and cash flow, or that our available cash will be sufficient to pay principal and interest on our indebtedness and distributions to our Unitholders.
High prices for propane, fuel oil and other refined fuels and natural gas can lead to customer conservation, resulting in reduced demand for our product.
Prices for propane, fuel oil and other refined fuels and natural gas are subject to fluctuations in response to changes in wholesale prices and other market conditions beyond our control. Therefore, our average retail sales prices can vary significantly within a heating season or from year to year as wholesale prices fluctuate with propane, fuel oil and natural gas commodity market conditions. During periods of high propane, fuel oil and other refined fuels and natural gas product costs our selling prices generally increase. High prices can lead to customer conservation, resulting in reduced demand for our product.
Because of the highly competitive nature of the retail propane and fuel oil businesses, we may not be able to retain existing customers or acquire new customers, which could have an adverse impact on our operating results and financial condition.
The retail propane and fuel oil industries are mature and highly competitive. We expect overall demand for propane and fuel oil to be relatively flat to moderately declining over the next several years. Year-to-year industry volumes of propane and fuel oil are expected to be primarily affected by weather patterns and from competition intensifying during warmer than normal winters, as well as from the impact of a sustained higher commodity price environment on customer conservation and the impact of continued weakness in the economy on customer buying habits.
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In addition to competing with other sources of energy, our propane and fuel oil businesses compete with other distributors of those respective products principally on the basis of price, service and availability. Competition in the retail propane business is highly fragmented and generally occurs on a local basis with other large full-service multi-state propane marketers, thousands of smaller local independent marketers and farm cooperatives. Our fuel oil business competes with fuel oil distributors offering a broad range of services and prices, from full service distributors to those offering delivery only. In addition, our existing fuel oil customers, unlike our existing propane customers, generally own their own tanks, which can result in intensified competition for these customers.
As a result of the highly competitive nature of the retail propane and fuel oil businesses, our growth within these industries depends on our ability to acquire other retail distributors, open new customer service centers, add new customers and retain existing customers. We can give no assurance that we will be able to acquire other retail distributors, add new customers and retain existing customers.
Energy efficiency, general economic conditions and technological advances have affected and may continue to affect demand for propane and fuel oil by our retail customers.
The national trend toward increased conservation and technological advances, including installation of improved insulation and the development of more efficient furnaces and other heating devices, has adversely affected the demand for propane and fuel oil by our retail customers which, in turn, has resulted in lower sales volumes to our customers. In addition, continued weakness in the economy may lead to additional conservation by retail customers seeking to further reduce their heating costs, particularly during periods of sustained higher commodity prices. Future technological advances in heating, conservation and energy generation and continued economic weakness may adversely affect our volumes sold, which, in turn, may adversely affect our financial condition and results of operations.
Current conditions in the global capital and credit markets, and general economic pressures, may adversely affect our financial position and results of operations.
Our business and operating results are materially affected by worldwide economic conditions. Current conditions in the global capital and credit markets and general economic pressures have led to declining consumer and business confidence, increased market volatility and widespread reduction of business activity generally. As a result of this turmoil, coupled with increasing energy prices, our customers may experience cash flow shortages which may lead to delayed or cancelled plans to purchase our products, and affect the ability of our customers to pay for our products. In addition, disruptions in the U.S. residential mortgage market, increases in mortgage foreclosure rates and failures of lending institutions may adversely affect retail customer demand for our products (in particular, products used for home heating and home comfort equipment) and our business and results of operations.
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The propane and fuel oil industries are mature and highly fragmented with competition from other multi-state marketers and thousands of smaller local independent marketers. Demand for propane and fuel oil is expected to be affected by many factors beyond our control, including, but not limited to, the severity of weather conditions during the peak heating season, customer conservation driven by high energy costs and other economic factors, as well as technological advances impacting energy efficiency. Accordingly, our propane and fuel oil sales volumes and related gross margins may be negatively affected by these factors beyond our control. Our operating profits and ability to generate sufficient cash flow may depend on our ability to continue to control expenses in line with sales volumes. We can give no assurance that we will be able to continue to control expenses to the extent necessary to reduce the effect on our profitability and cash flow from these factors.
The risk of terrorism, political unrest and the current hostilities in the Middle East or other energy producing regions may adversely affect the economy and the price and availability of propane, fuel oil and other refined fuels and natural gas.
Terrorist attacks, political unrest and the current hostilities in the Middle East or other energy producing regions may adversely impact the price and availability of propane, fuel oil and other refined fuels and natural gas, as well as our results of operations, our ability to raise capital and our future growth. The impact that the foregoing may have on our industry in general, and on us in particular, is not known at this time. An act of terror could result in disruptions of crude oil or natural gas supplies and markets (the sources of propane and fuel oil), and our infrastructure facilities could be direct or indirect targets. Terrorist activity may also hinder our ability to transport propane, fuel oil and other refined fuels if our means of supply transportation, such as rail or pipeline, become damaged as a result of an attack. A lower level of economic activity could result in a decline in energy consumption, which could adversely affect our revenues or restrict our future growth. Instability in the financial markets as a result of terrorism could also affect our ability to raise capital. Terrorist activity, political unrest and hostilities in the Middle East or other energy producing regions could likely lead to increased volatility in prices for propane, fuel oil and other refined fuels and natural gas. We have opted to purchase insurance coverage for terrorist acts within our property and casualty insurance programs, but we can give no assurance that our insurance coverage will be adequate to fully compensate us for any losses to our business or property resulting from terrorist acts.
Our financial condition and results of operations may be adversely affected by governmental regulation and associated environmental and health and safety costs.
Our business is subject to a wide and ever increasing range of federal, state and local laws and regulations related to environmental and health and safety matters including those concerning, among other things, the investigation and remediation of contaminated soil and groundwater and transportation of hazardous materials. These requirements are complex, changing and tend to become more stringent over time. In addition, we are required to maintain various permits that are necessary to operate our facilities, some of which are material to our operations. There can be no assurance that we have been, or will be, at all times in complete compliance with all legal, regulatory and permitting requirements or that we will not incur significant costs in the future relating to such requirements. Violations could result in penalties, or the curtailment or cessation of operations.
Moreover, currently unknown environmental issues, such as the discovery of additional contamination, may result in significant additional expenditures, and potentially significant expenditures also could be required to comply with future changes to environmental laws and regulations or the interpretation or enforcement thereof. Such expenditures, if required, could have a material adverse effect on our business, financial condition or results of operations.
We are subject to operating hazards and litigation risks that could adversely affect our operating results to the extent not covered by insurance.
Our operations are subject to all operating hazards and risks normally associated with handling, storing and delivering combustible liquids such as propane, fuel oil and other refined fuels. We have been, and are likely to continue to be, a defendant in various legal proceedings and litigation arising in the ordinary course of business, both as a result of these operating hazards and risks and as a result of other aspects of our business. We are self-insured for general and product, workers’ compensation and automobile liabilities up to predetermined amounts above which third-party insurance applies. We cannot guarantee that our insurance will be adequate to protect us from all material expenses related to potential future claims for personal injury and property damage or that these levels of insurance will be available at economical prices, or that all legal matters that arise will be covered by our insurance programs.
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The retail propane and fuel oil industries are mature. We expect overall demand for propane and fuel oil to be relatively flat to moderately declining over the next several years. With respect to our retail propane business, it may be difficult for us to increase our aggregate number of retail propane customers except through acquisitions. As a result, we expect the success of our financial performance to depend, in part, upon our ability to acquire other retail propane and fuel oil distributors or other energy-related businesses and to successfully integrate them into our existing operations and to make cost saving changes. The competition for acquisitions is intense and we can make no assurance that we will be able to acquire other propane and fuel oil distributors or other energy-related businesses on economically acceptable terms or, if we do, to integrate the acquired operations effectively.
The adoption of climate change legislation could result in increased operating costs and reduced demand for the products and services we provide.
In December 2009, the EPA issued an “Endangerment Finding” under the Clean Air Act, determining that emissions of GHGs present an endangerment to public health and the environment because emissions of such gases may be contributing to warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of GHGs and require reporting by certain regulated facilities on an annual basis.
Both Houses of the United States Congress also have considered adopting legislation to reduce emissions of GHGs. In June 2009, the American Clean Energy and Security Act of 2009, also known as the Waxman-Markey Bill, passed in the U.S. House of Representatives, but the U.S. Senate’s version, The Clean Energy Jobs and American Power Act, or the Boxer-Kerry Bill, didHowever, Congress has not pass. Both bills sought to establish a “cap and trade” system for restricting GHG emissions. Under such system, certain sources of GHG emissions would be required to obtain GHG emission “allowances” corresponding to their annual emissions of GHGs. The number of emission allowances issued each year would decline as necessary to meet overall emission reduction goals. As the number of GHG emission allowances declines each year, the cost or value of allowances is expected to escalate significantly.
The adoption of federal or state climate change legislation or regulatory programs to reduce emissions of GHGs could require us to incur increased capital and operating costs, with resulting impact on product price and demand. We cannot predict whether or in what form cap-and-tradeclimate change legislation provisions and renewable energy standards may be enacted. In addition, a possible consequence of climate change is increased volatility in seasonal temperatures. It is difficult to predict how the market for our fuels would be affected by increased temperature volatility, although if there is an overall trend of warmer temperatures, it could adversely affect our business.
The adoption of derivatives legislation by Congress could have an adverse impact on our ability to hedge risks associated with our business.
On July 21, 2010, the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) was signed into law. The Dodd-Frank Act regulates derivative transactions, which include certain instruments used in our risk management activities.
The Dodd-Frank Act requires the CFTCCommodity Futures Trading Commission (the “CFTC”) and the SEC to promulgate rules and regulations relating to, among other things, swaps, participants in the derivatives markets, clearing of swaps and reporting of swap transactions. In general, the Dodd-Frank Act subjects swap transactions and participants to greater regulation and supervision by the CFTC and the SEC and will require many swaps to be cleared through a CFTC- or SEC-registered clearing facility and executed on a designated exchange or swap execution facility. There are some exceptions to these requirements for entities that use swaps to hedge or mitigate commercial risk. While we may ultimately be eligible for such exceptions, the scope of these exceptions currently is somewhat uncertain, pending further definition through rulemaking.
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The new legislation and regulations promulgated thereunder could increase the operational and transactional cost of derivatives contracts and affect the number and/or creditworthiness of counterparties available to us.
We depend on particular management information systems to effectively manage all aspects of our delivery of propane.
We depend on our management information systems to process orders, manage inventory and accounts receivable collections, maintain distributor and customer information, maintain cost-efficient operations and assist in delivering our products on a timely basis. In addition, our staff of management information systems professionals relies heavily on the support of several key personnel and vendors. Any disruption in the operation of those management information systems, loss of employees knowledgeable about such systems, termination of our relationship with one or more of these key vendors or failure to continue to modify such systems effectively as our business expands could negatively affect our business.
Risks Related to the Inergy Propane Acquisition and the Related Transactions
We may not be able to successfully integrate Inergy Propane’s operations with our operations, which could cause our business to suffer.
In order to obtain all of the anticipated benefits of the Inergy Propane Acquisition, we will need to combine and integrate the businesses and operations of Inergy Propane with ours. Although we have developed, and are implementing, a detailed integration plan, the combination of two large businesses is a complex and costly process. We will be required to continue to devote significant management attention and resources to integrating the business practices and operations of Suburban and Inergy Propane. Although we believe that it has not yet done so, the integration process may, in the future, divert the attention of our executive officers and management from day-to-day operations and disrupt the business of Suburban and, if implemented ineffectively, may preclude realization of the expected benefits of the transaction.
Our failure to meet the challenges involved in successfully completing the integration of Inergy Propane’s operations with our operations or otherwise to realize any of the anticipated benefits of the Inergy Propane Acquisition could adversely affect our results of operations. In addition, the overall integration of Suburban and Inergy Propane may yet result in unanticipated problems, expenses, liabilities and competitive responses. The loss of customer relationships may be above historical norms not only with respect to existing Suburban customers but also as to the Inergy Propane customers who are now being serviced by Suburban. Although not yet experienced to any significant degree, possible difficulties that may yet arise from our continuing efforts to combine our two operations could include, among others:
In addition, even if we are able to successfully complete the integration of our businesses and operations, we may not fully realize the expected benefits of the Inergy Propane Acquisition within the intended time frame, or at all. Further, our post-acquisition results of operations may be affected by factors different from those existing prior to the Inergy Propane Acquisition and may suffer as a result of the Inergy Propane Acquisition. As a result, we can give no assurance that the combination of our business and operations with Inergy Propane will result in the realization of the full benefits anticipated from the Inergy Propane Acquisition.
We incurred and continue to incur substantial expenses related to the integration of Inergy Propane.
We have incurred and expect to continue to incur substantial expenses in connection with the Inergy Propane Acquisition and integrating the business, operations, networks, systems, technologies, policies and procedures of Suburban and Inergy Propane. There are a large number of systems that must be integrated, including billing, management information, information systems, purchasing, accounting and finance, sales, payroll and benefits, fixed assets, lease administration and regulatory compliance. Although Suburban has assumed that a certain level of transaction and integration expenses would be incurred, there are a number of factors beyond our control that could affect the total amount or the timing of these integration expenses. Although integration expenses have been, to date, within the expected range, many of the expenses yet to be incurred are, by their nature, difficult to accurately estimate at the present time. Due to these factors, the total transaction and integration expenses associated with the Inergy Propane Acquisition could, particularly in the near term, exceed the savings that we expect to achieve from the elimination of duplicative expenses and the realization of economies of scale and cost savings related to the integration of the businesses. As a result of these expenses, Suburban has taken, and expects to continue to take, charges against its earnings relating to the acquisition and integration of Inergy Propane. The charges relating to the acquisition and integration of Inergy Propane have been and expect to continue to be significant, although the aggregate amount and timing of all such charges are uncertain at present.
The integration of Inergy Propane could cause disruptions in our business, which could have an adverse effect on both our business and financial results.
In response to the integration activities related to the Inergy Propane Acquisition, our or Inergy Propane’s customers may delay or defer purchasing decisions, or choose to switch to another competitor for the supply of propane. Any such delay, deferral or change of supplier by customers could negatively affect our business and results of operations. Similarly, our employees may experience uncertainty about their future roles with us until Inergy Propane is fully integrated. This may adversely affect our ability to attract and retain key management, marketing and technical personnel.
During and following the integration of Inergy Propane, we may be unable to retain key employees.
Our future success will depend in part upon our ability to retain key Suburban employees, including employees of Inergy Propane who became Suburban employees upon completion of the Inergy Propane Acquisition. Key employees may hereafter depart because of issues relating to the uncertainty and difficulty of integration, a desire not to remain with us or otherwise. Accordingly, no assurance can be given that Suburban will be able to retain key employees to the same extent as in the past.
Risks Inherent in the Ownership of Our Common Units
Cash distributions are not guaranteed and may fluctuate with our performance and other external factors.
Cash distributions on our Common Units are not guaranteed, and depend primarily on our cash flow and our cash on hand. Because they are not dependent on profitability, which is affected by non-cash items, our cash distributions might be made during periods when we record losses and might not be made during periods when we record profits.
The amount of cash we generate may fluctuate based on our performance and other factors, including:
Our Partnership Agreement gives our Board of Supervisors broad discretion in establishing cash reserves for, among other things, the proper conduct of our business. These cash reserves will affect the amount of cash available for distributions.
We have substantial indebtedness. Our debt agreements may limit our ability to make distributions to Unitholders, as well as our financial flexibility.
As of September 24, 2011, we had total outstanding28, 2013, our long-term debt borrowings consisted of $350.0$496.6 million consistingin aggregate principal amount of 7.5% senior notes due October 1, 2018 (excluding unamortized premium of $28.6 million), $250.0 million in aggregate principal amount of 7.375% senior notes issued by the Partnership and our 100%-owned subsidiary, Suburban Energy Finance Corporation,due March 15, 2020 (excluding unamortized discount of $1.4 million), $346.2 million in aggregate principal amount of 7.375% senior notes due August 1, 2021 (excluding unamortized premium of $25.3 million), and $100.0 million of borrowings outstanding under the Operating Partnership’sour senior secured revolving credit facility. The payment of principal and interest on our debt will reduce the cash available to make distributions on our Common Units.common units. In addition, we will not be able to make any distributions to holders of our Unitholderscommon units if there is, or after giving effect to such distribution, there would be, an event of default under the indentureindentures governing the senior notes. The amount of distributions that the Partnershipwe may make to its Unitholdersholders of our common units is limited by the senior notes, and the amount of distributions that the Operating Partnership may make to the Partnershipus is limited by theour revolving credit facility.
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The amount and terms of our debt may also adversely affect our ability to finance future operations and capital needs, limit our ability to pursue acquisitions and other business opportunities and make our results of operations more susceptible to adverse economic and industry conditions. In addition to our outstanding indebtedness, we may in the future require additional debt to finance acquisitions or for general business purposes; however, credit market conditions may impact our ability to access such financing. If we are unable to access needed financing or to generate sufficient cash from operations, we may be required to abandon certain projects or curtail capital expenditures. Additional debt, where it is available, could result in an increase in our leverage. Our ability to make principal and interest payments depends on our future performance, which is subject to many factors, some of which are beyond our control.
Unitholders have limited voting rights.
A Board of Supervisors managesgoverns our operations. Our Unitholders have only limited voting rights on matters affecting our business, including the right to elect the members of our Board of Supervisors every three years and the right to vote on the removal of the general partner.
It may be difficult for a third party to acquire us, even if doing so would be beneficial to our Unitholders.
Some provisions of our Partnership Agreement may discourage, delay or prevent third parties from acquiring us, even if doing so would be beneficial to our Unitholders. For example, our Partnership Agreement contains a provision, based on Section 203 of the Delaware General Corporation Law, that generally prohibits the Partnership from engaging in a business combination with a 15% or greater Unitholder for a period of three years following the date that person or entity acquired at least 15% of our outstanding Common Units, unless certain exceptions apply. Additionally, our Partnership Agreement sets forth advance notice procedures for a Unitholder to nominate a Supervisor to stand for election, which procedures may discourage or deter a potential acquirer from conducting a solicitation of proxies to elect the acquirer’s own slate of Supervisors or otherwise attempting to obtain control of the Partnership. These nomination procedures may not be revised or repealed, and inconsistent provisions may not be adopted, without the approval of the holders of at least 66-2/3% of the outstanding Common Units. These provisions may have an anti-takeover effect with respect to transactions not approved in advance by our Board of Supervisors, including discouraging attempts that might result in a premium over the market price of the Common Units held by our Unitholders.
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A number of states have not clearly established limitations on the liabilities of limited partners for the obligations of a limited partnership. Our Unitholders might be held liable for our obligations as if they were general partners if:
Unitholders may have liability to repay distributions.
Unitholders will not be liable for assessments in addition to their initial capital investment in the Common Units. Under specific circumstances, however, Unitholders may have to repay to us amounts wrongfully returned or distributed to them. Under Delaware law, we may not make a distribution to Unitholders if the distribution causes our liabilities to exceed the fair value of our assets. Liabilities to partners on account of their partnership interests and nonrecourse liabilities are not counted for purposes of determining whether a distribution is permitted. Delaware law provides that a limited partner who receives a distribution of this kind and knew at the time of the distribution that the distribution violated Delaware law will be liable to the limited partnership for the distribution amount for three years from the distribution date. Under Delaware law, an assignee who becomes a substituted limited partner of a limited partnership is liable for the obligations of the assignor to make contributions to the partnership. However, such an assignee is not obligated for liabilities unknown to him at the time he or she became a limited partner if the liabilities could not be determined from the partnership agreement.
If we issue additional limited partner interests or other equity securities as consideration for acquisitions or for other purposes, the relative voting strength of each Unitholder will be diminished over time due to the dilution of each Unitholder’s interests and additional taxable income may be allocated to each Unitholder.
Our Partnership Agreement generally allows us to issue additional limited partner interests and other equity securities without the approval of our Unitholders. Therefore, when we issue additional Common Units or securities ranking on a parity with the Common Units, each Unitholder’s proportionate partnership interest will decrease, and the amount of cash distributed on each Common Unit and the market price of Common Units could decrease. The issuance of additional Common Units will also diminish the relative voting strength of each previously outstanding Common Unit. In addition, the issuance of additional Common Units will, over time, result in the allocation of additional taxable income, representing built-in gains at the time of the new issuance, to those Unitholders that existed prior to the new issuance.
17
Our tax treatment depends on our status as a partnership for U.S. federal income tax purposes. The Internal Revenue Service (“IRS”) could treat us as a corporation, which would substantially reduce the cash available for distribution to Unitholders.
The anticipated after-tax economic benefit of an investment in our Common Units depends largely on our being treated as a partnership for U.S. federal income tax purposes. We believeIf less than 90% of the gross income of a publicly traded partnership, such as Suburban Propane Partners, L.P., for any taxable year is “qualifying income” within the meaning of Section 7704 of the Internal Revenue Code, that under current law, wepartnership will be classifiedtaxable as a partnershipcorporation for U.S. federal income tax purposes.purposes for that taxable year and all subsequent years.
If we were treated as a corporation for U.S. federal income tax purposes, then we would pay U.S. federal income tax on our income at the corporate tax rate, which is currently a maximum of 35%, and would likely pay additional state income tax at varying rates. Because a tax would be imposed upon us as a corporation, our cash available for distribution to Unitholders would be substantially reduced. Treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to Unitholders and thus would likely result in a substantial reduction in the value of our Common Units.
The tax treatment of publicly traded partnerships or an investment in our Common Units could be subject to potential legislative, judicial or administrative changes and differing interpretations thereof, possibly on a retroactive basis.
The present U.S. federal income tax treatment of publicly traded partnerships, including Suburban Propane Partners, L.P., or an investment in our Common Units may be modified by legislative, judicial or administrative changes and differing interpretations thereof at any time. Any modification to the U.S. federal income tax laws or interpretations thereof may or may not be applied retroactively. Moreover, any such modification could make it more difficult or impossible for us to meet the exception that allows publicly traded partnerships that generate qualifying income to be treated as partnerships (rather than as corporations) for U.S. federal income tax purposes, affect or cause us to change our business activities, or affect the tax consequences of an investment in our Common Units. For example, legislation proposed by members of Congress and the President has considered substantive changes to the definition of qualifying income. One of the requirements for such classification is that at least 90% of our gross income for each taxable year has been and will be “qualifying income” within the meaning of Section 7704 of the Internal Revenue Code. Whether we will continue to be classified as a partnership in part depends on our ability to meet this qualifying income test in the future. We have not requested, and do not plan to request, a ruling from the IRS on this or any other tax matter affecting us. The IRS may adopt positions that differ from the positions we take. In addition, current law may change so as to cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level federal income taxation. Members of Congress have proposed substantive changes to the current federal income tax laws that would affect certain publicly traded partnerships and legislation that would eliminate partnership tax treatment for certain publicly traded partnerships. Although no legislation is currently pending that would affect our tax treatment as a partnership, weWe are unable to predict whether any suchof these changes, or other proposals, will ultimately be enacted. Any modification to the U.S. tax laws and interpretations thereof may or may not be applied retroactively. If we were treated as a corporation for federal income tax purposes, we would be required to pay tax on our income at corporate tax rates (currently a maximum of U.S. federal rate of 35%) and likely would be required to pay state income tax at varying rates. Because a tax would be imposed upon us as a corporation, our cash available for distribution to our Unitholders would be substantially reduced. Therefore, our treatment as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to our Unitholders, likely causing a substantial reduction insuch changes could negatively impact the value of an investment in our Common Units. units.
In addition, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Any such changes could negatively impact our ability to make distributions and also impact the value of an investment in our Common Units.
A successful IRS contest of the U.S. federal income tax positions we take may adversely affect the market for our Common Units, and the cost of any IRS contest will reduce our cash available for distribution to our Unitholders.
We have not requested a ruling from the IRS with respect to our treatment as a partnership for U.S. federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with the positions we take. Any contest with the IRS may materially and adversely impact the market for our Common Units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our Unitholders because the costs will reduce our cash available for distribution.
A Unitholder’s tax liability could exceed cash distributions on its Common Units.
Because our Unitholders are treated as partners, to whom we allocate taxable income which could be different in amount than the cash we distribute, a Unitholder is required to pay U.S. federal income taxes and in some cases, state and local income taxes on its allocable share of our income, even if it receives nowithout regard to whether we make cash distributions from us.to the Unitholder. We cannot guarantee that a Unitholder will receive cash distributions equal to its allocable share of our taxable income or even the tax liability to it resulting from that income.
Ownership of Common Units may have adverse tax consequences for tax-exempt organizations and foreign investors.
Investment in Common Units by certain tax-exempt entities and foreign persons raises issues specific to them. For example, virtually all of our taxable income allocated to organizations exempt from U.S. federal income tax, including individual retirement accounts and other retirement plans, will be unrelated business taxable income and thus will be taxable to the Unitholder. Distributions to foreign persons will be reduced by withholding taxes at the highest applicable effective tax rate, and foreign persons will be required to file United StatesU.S. federal income tax returns and pay tax on their share of our taxable income. Tax-exempt entitiesorganizations and foreign persons should consult, and should depend on, their own tax advisors before investing in ouranalyzing the U.S. federal, state, local and foreign income tax and other tax consequences of the acquisition, ownership or disposition of Common Units.
18
The tax gain or loss on the disposition of Common Units could be different than expected.
A Unitholder who sells Common Units will recognize a gain or loss equal to the difference between the amount realized and its adjusted tax basis in the Common Units. Prior distributions in excess of cumulative net taxable income allocated to a Common Unit which decreased a Unitholder’s tax basis in that common unitCommon Unit will, in effect, become taxable income if the Common Unit is sold at a price greater than the Unitholder’s tax basis in that Common Unit, even if the price is less than the original cost of the Common Unit. A portion of the amount realized, if the amount realized exceeds the Unitholder’s adjusted basis in that Common Unit, will likely be characterized as ordinary income. Furthermore, should the IRS successfully contest some conventions used by us, a Unitholder could recognize more gain on the sale of Common Units than would be the case under those conventions, without the benefit of decreased income in prior years.
Reporting of partnership tax information is complicated and subject to audits.
We intend to furnish to each Unitholder, withwithin 90 days after the close of each calendar year, specific tax information, including a Schedule K-1 that sets forth its allocable share of income, gains, losses and deductions.deductions for our preceding taxable year. In preparing these schedules, we use various accounting and reporting conventions and adopt various depreciation and amortization methods. We cannot guarantee that these conventions will yield a result that conforms to statutory or regulatory requirements or to administrative pronouncements of the IRS. Further, our income tax return may be audited, which could result in an audit of a Unitholder’s income tax return and increased liabilities for taxes because of adjustments resulting from the audit.
We treat each purchaser of our Common Units as having the same tax benefits without regard to the actual Common Units purchased. The IRS may challenge this treatment, which could adversely affect the value of the Common Units.
Because we cannot match transferors and transferees of Common Units and because of other reasons, uniformity of the economic and tax characteristics of the Common Units to a purchaser of Common Units of the same class must be maintained. To maintain uniformity and for other reasons, we have adopted certain depreciation and amortization conventions whichthat may be inconsistent with Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to a Unitholder. It also could affect the timing of these tax benefits or the amount of gain from the sale of Common Units, and could have a negative impact on the value of our Common Units or result in audit adjustments to a Unitholder’s income tax return.
We prorate our items of income, gain, loss and deduction between transferors and transferees of our Common Units each month based upon the ownership of our Common Units on the first day of each month, instead of on the basis of the date a particular Common Unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our Unitholders.
We prorate our items of income, gain, loss and deduction between transferors and transferees of our Common Units each month based upon the ownership of our Common Units on the first day of each month, instead of on the basis of the date a particular Common Unit is transferred. The U.S. Treasury Department has issued proposed Treasury Regulations that provide a safe harbor pursuant to which publicly traded partnerships may use a similar monthly simplifying convention to allocate tax items among transferors and transferees of this proration method may not be permitted under existing Treasury Regulations. Ifour common units. However, if the IRS were to challenge thisour proration method, or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our Unitholders.
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If we default on any of our debt obligations, our lenders will have the right to sue us for non-payment. This could cause an investment loss and negative tax consequences for Unitholders through the realization of taxable income by Unitholders without a corresponding cash distribution. Likewise, if we were to dispose of assets and realize a taxable gain while there is substantial debt outstanding and proceeds of the sale were applied to the debt, Unitholders could have increased taxable income without a corresponding cash distribution.
The sale or exchange of 50% or more of our Common Unitscapital and profits interests during any twelve-month period will result in a deemedthe termination (and reconstitution) of the Partnershipour partnership for federal income tax purposes which would cause Unitholders to be allocated an increased amount of taxable income.purposes.
We will be deemedconsidered to have terminated (and reconstituted)as a partnership for U.S. federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our Common Unitscapital and profits within a twelve-month period. Were this to occur, itOur termination would, among other things, result in the closing of our taxable year for all Unitholders and could result in a deferral of depreciation deductions allowable in computing our taxable income. This wouldIn the case of a Unitholder reporting on a taxable year other than the calendar year, the closing of our taxable year may also result in Unitholdersmore than twelve months of our taxable income or loss being allocated an increased amountincludable in his taxable income for the year of taxable income.
There are state, local and other tax considerations for our Unitholders.
In addition to United StatesU.S. federal income taxes, Unitholders will likely be subject to other taxes, such as state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property, even if the Unitholder does not reside in any of those jurisdictions. A Unitholder will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of the various jurisdictions in which we do business or own property and may be subject to penalties for failure to comply with those requirements. It is the responsibility of each Unitholder to file all United StatesU.S. federal, state and local income tax returns that may be required of each Unitholder.
A Unitholder whose Common Units are loaned to a “short seller” to cover a short sale of Common Units may be considered as having disposed of those Common Units. If so, that Unitholder would no longer be treated for tax purposes as a partner with respect to those Common Units during the period of the loan and may recognize gain or loss from the disposition.
Because there is no tax concept of loaning a partnership interest, a Unitholder whose Common Units are loaned to a “short seller” to cover a short sale of Common Units may be considered as having disposed of the loaned Common Units. In that case, a Unitholder may no longer be treated for tax purposes as a partner with respect to those Common Units during the period of the loan to the short seller and may recognize gain or loss from such Unitholder.
ITEM 1B. | UNRESOLVED STAFF COMMENTS |
None.
As of September 24 2011,28, 2013, we owned approximately 66%70% of our customer service center and satellite locations and leased the balance of our retail locations from third parties. We own and operate a 22 million gallon refrigerated, aboveground propane storage facility in Elk Grove, California. Additionally, we own our principal executive offices located in Whippany, New Jersey.
The transportation of propane requires specialized equipment. The trucks and railroad tank cars utilized for this purpose carry specialized steel tanks that maintain the propane in a liquefied state. As of September 24 2011,28, 2013, we had a fleet of 619 transport truck tractors, of which we owned two,12, and 23 railroad tank cars, of which we owned none. In addition, as of September 24, 201128, 2013 we had 6681,466 bobtail and rack trucks, of which we owned 33%56%, 88150 fuel oil tankwagons, of which we owned 25%71%, and 8661,587 other delivery and service vehicles, of which we owned 41%62%. We lease the vehicles we do not own. As of September 24, 2011,28, 2013, we also owned 655,003981,468 customer propane storage tanks with typical capacities of 100 to 500 gallons, 139,81383,890 customer propane storage tanks with typical capacities of over 500 gallons and 217,842304,390 portable propane cylinders with typical capacities of five to ten gallons.
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Litigation
Our operations are subject to all operating hazards and risks normally incidental to handling, storing and delivering combustible liquids such as propane. We have been, and will continue to be, a defendant in various legal proceedings and litigation arising in the ordinary course of business, both as a result of these operating hazards and risks, and as a result of other aspects of our business. In this regard,During the fourth quarter of fiscal 2012, we entered into an agreement to settle a California action, in which were alleged several claims relating to two fees charged by us, on a classwide basis in return for the payment of a monetary sum and certain non-monetary consideration, and established an accrual of $4.5 million for the estimated cost of the settlement. This settlement, entered into to avoid both the continued expenses and burden of defending that action and the uncertainty inherent in all litigation, was approved by the trial court in May 2013, and we completed distribution of the settlement proceeds to the class members in the fourth quarter of fiscal 2013. We are currently are a defendant in a putative suitsclass action in which the court has denied class certification without prejudice. We believe such suit is without merit. In the putative class action, we have been successful in eliminating several states.of the claims such that only certain contractual and consumer statute claims remain. The complaints allege a numbersubject matter jurisdiction of the court to adjudicate certain of the contractual claims including as to our pricing, fee disclosureis on appeal. We are contesting this putative class action vigorously and tank ownership, under various consumer statutes, the Uniform Commercial Code, common law and antitrust law. Basedhave determined, based on the nature of the allegations under these suits, we believeand discovery to date, that the suits are without merit and we are contesting each of these suits vigorously. We are self-insuredno reserve for general and product, workers’ compensation and automobile liabilities up to predetermined amounts above which third party insurance applies. We believe that the self-insured retentions and coverage we maintain are reasonable and prudent. Although any litigation is inherently uncertain, based on past experience, the information currently available to us, and the amount of our self-insurance reserves for known and unasserted self-insurance claims (which was approximately $52.8 million at September 24, 2011), we do not believe that these pending or threatened litigation matters, or known claims or known contingent claims, will have a material adverse effect on our future results of operations, financial condition or cash flow, after considering our self-insurance reserves for known and unasserted claims, as well as existing insurance policies in force. For the portion of our estimated self-insurance liability that exceeds our deductibles, we record a corresponding asset related to the amount of the liability covered by insurance (which was approximately $17.5 million at September 24, 2011). With respect to the pending putative suits,loss contingency other than for legal defense fees and expenses based onis required. We are unable to reasonably estimate the meritspossible loss or range of the allegations, a liability for a loss, contingency is not required atif any, arising from this time.
None.
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ITEM 5. | MARKET FOR THE REGISTRANT’S COMMON UNITS, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF UNITS |
(a) Our Common Units, representing limited partner interests in the Partnership, are listed and traded on the New York Stock Exchange (“NYSE”) under the symbol SPH. As of November 21, 2011,25, 2013, there were 700706 Unitholders of record (based on the number of record holders and nominees for those Common Units held in street name). The following table presents, for the periods indicated, the high and low sales prices per Common Unit, as reported on the NYSE, and the amount of quarterly cash distributions declared and paid per Common Unit in respect of each quarter.
Cash Distribution | ||||||||||||
Common Unit Price Range | Declared per | |||||||||||
High | Low | Common Unit | ||||||||||
Fiscal 2011 | ||||||||||||
First Quarter | $ | 57.24 | $ | 51.50 | $ | 0.8525 | ||||||
Second Quarter | 58.99 | 49.30 | 0.8525 | |||||||||
Third Quarter | 57.89 | 49.90 | 0.8525 | |||||||||
Fourth Quarter | 53.23 | 40.25 | 0.8525 | |||||||||
Fiscal 2010 | ||||||||||||
First Quarter | $ | 47.12 | $ | 41.10 | $ | 0.8350 | ||||||
Second Quarter | 50.00 | 42.53 | 0.8400 | |||||||||
Third Quarter | 49.46 | 39.16 | 0.8450 | |||||||||
Fourth Quarter | 55.01 | 45.85 | 0.8500 |
Cash Distribution | ||||||||||||
Common Unit Price Range | Declared per | |||||||||||
High | Low | Common Unit | ||||||||||
Fiscal 2013 | ||||||||||||
First Quarter | $ | 44.82 | $ | 36.69 | $ | 0.8750 | ||||||
Second Quarter | 44.80 | 38.09 | 0.8750 | |||||||||
Third Quarter | 50.25 | 41.93 | 0.8750 | |||||||||
Fourth Quarter | 49.50 | 44.21 | 0.8750 | |||||||||
Fiscal 2012 | ||||||||||||
First Quarter | $ | 49.19 | $ | 44.50 | $ | 0.8525 | ||||||
Second Quarter | 48.25 | 40.25 | 0.8525 | |||||||||
Third Quarter | 44.52 | 34.58 | 0.8525 | |||||||||
Fourth Quarter | 45.61 | 36.75 | 0.8525 |
We make quarterly distributions to our partners in an aggregate amount equal to our Available Cash (as defined in our Partnership Agreement) with respect to such quarter. Available Cash generally means all cash on hand at the end of the fiscal quarter plus all additional cash on hand as a result of borrowings subsequent to the end of such quarter less cash reserves established by the Board of Supervisors in its reasonable discretion for future cash requirements.
We are a publicly traded limited partnership and, other than certain corporate subsidiaries that are taxed as corporations, we are not subject to corporate level federal income tax. Instead, Unitholders are required to report their allocable share of our earnings or loss, regardless of whether we make distributions.
(b) Not applicable.
(c) None.
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The following table presents our selected consolidated historical financial data as derived from our audited consolidated financial statements, certain of which are included elsewhere in this Annual Report. All amounts in the table below, except per unit data, are in thousands.
Year Ended | ||||||||||||||||||||
September | September | September | September | September | ||||||||||||||||
24, 2011 | 25, 2010 | 26, 2009 | 27, 2008 | 29, 2007 | ||||||||||||||||
Statement of Operations Data | ||||||||||||||||||||
Revenues | $ | 1,190,552 | $ | 1,136,694 | $ | 1,143,154 | $ | 1,574,163 | $ | 1,439,563 | ||||||||||
Costs and expenses | 1,045,324 | 980,508 | 932,539 | 1,424,035 | 1,270,213 | |||||||||||||||
Severance charges (a) | 2,000 | — | — | — | 1,485 | |||||||||||||||
Pension settlement charge (b) | — | 2,818 | — | — | 3,269 | |||||||||||||||
Operating income | 143,228 | 153,368 | 210,615 | 150,128 | 164,596 | |||||||||||||||
Interest expense, net | 27,378 | 27,397 | 38,267 | 37,052 | 35,596 | |||||||||||||||
Loss on debt extinguishment (c) | — | 9,473 | 4,624 | — | — | |||||||||||||||
Provision for income taxes | 884 | 1,182 | 2,486 | 1,903 | 5,653 | |||||||||||||||
Income from continuing operations | 114,966 | 115,316 | 165,238 | 111,173 | 123,347 | |||||||||||||||
Discontinued operations: | ||||||||||||||||||||
Gain on disposal of discontinued operations (d) | — | — | — | 43,707 | 1,887 | |||||||||||||||
Income from discontinued operations | — | — | — | — | 2,053 | |||||||||||||||
Net income | 114,966 | 115,316 | 165,238 | 154,880 | 127,287 | |||||||||||||||
Income from continuing operations per Common Unit — basic | 3.24 | 3.26 | 4.99 | 3.39 | 3.79 | |||||||||||||||
Net income per Common Unit — basic (e) | 3.24 | 3.26 | 4.99 | 4.72 | 3.91 | |||||||||||||||
Net income per Common Unit — diluted (e) | 3.22 | 3.24 | 4.96 | 4.70 | 3.89 | |||||||||||||||
Cash distributions declared per unit | $ | 3.41 | $ | 3.35 | $ | 3.26 | $ | 3.09 | $ | 2.76 | ||||||||||
Balance Sheet Data (f) | ||||||||||||||||||||
Cash and cash equivalents | $ | 149,553 | $ | 156,908 | $ | 163,173 | $ | 137,698 | $ | 96,586 | ||||||||||
Current assets | 297,822 | 296,427 | 307,556 | 359,551 | 295,940 | |||||||||||||||
Total assets | 956,459 | 970,914 | 978,168 | 1,036,367 | 988,947 | |||||||||||||||
Current liabilities, excluding short-term borrowings and current portion of long-term borrowings | 151,514 | 164,514 | 181,930 | 226,780 | 206,633 | |||||||||||||||
Total debt | 348,169 | 347,953 | 349,415 | 531,772 | 548,538 | |||||||||||||||
Total liabilities | 598,241 | 608,258 | 620,632 | 818,472 | 822,670 | |||||||||||||||
Partners’ capital — Common Unitholders | $ | 418,134 | $ | 419,882 | $ | 418,824 | $ | 262,050 | $ | 208,230 | ||||||||||
Statement of Cash Flows Data | ||||||||||||||||||||
Cash provided by (used in) | ||||||||||||||||||||
Operating activities | $ | 132,786 | $ | 155,797 | $ | 246,551 | $ | 120,517 | $ | 145,957 | ||||||||||
Investing activities | (19,505 | ) | (30,111 | ) | (16,852 | ) | 36,630 | (19,689 | ) | |||||||||||
Financing activities | $ | (120,636 | ) | $ | (131,951 | ) | $ | (204,224 | ) | $ | (116,035 | ) | $ | (90,253 | ) | |||||
Other Data | ||||||||||||||||||||
Depreciation and amortization — continuing operations | $ | 35,628 | $ | 30,834 | $ | 30,343 | $ | 28,394 | $ | 28,790 | ||||||||||
Depreciation and amortization — discontinued operations | — | — | — | — | 452 | |||||||||||||||
EBITDA (g) | 178,856 | 174,729 | 236,334 | 222,229 | 197,778 | |||||||||||||||
Adjusted EBITDA (g) | 179,425 | 192,420 | 239,245 | 220,465 | 210,087 | |||||||||||||||
Capital expenditures — maintenance and growth (h) | $ | 22,284 | $ | 19,131 | $ | 21,837 | $ | 21,819 | $ | 26,756 | ||||||||||
Retail gallons sold | ||||||||||||||||||||
Propane | 298,902 | 317,906 | 343,894 | 386,222 | 432,526 | |||||||||||||||
Fuel oil and refined fuels | 37,241 | 43,196 | 57,381 | 76,515 | 104,506 |
Year Ended | ||||||||||||||||||||
September | September | September | September | September | ||||||||||||||||
28, 2013 | 29, 2012 (a) | 24, 2011 | 25, 2010 | 26, 2009 | ||||||||||||||||
Statement of Operations Data | ||||||||||||||||||||
Revenues | $ | 1,703,606 | $ | 1,063,458 | $ | 1,190,552 | $ | 1,136,694 | $ | 1,143,154 | ||||||||||
Costs and expenses | 1,526,630 | 1,003,885 | 1,047,324 | 980,508 | 932,539 | |||||||||||||||
Acquisition-related costs (b) | — | 17,916 | — | — | — | |||||||||||||||
Pension settlement charge (c) | — | — | — | 2,818 | — | |||||||||||||||
Operating income | 176,976 | 41,657 | 143,228 | 153,368 | 210,615 | |||||||||||||||
Interest expense, net | 95,427 | 38,633 | 27,378 | 27,397 | 38,267 | |||||||||||||||
Loss on debt extinguishment (d) | 2,144 | 2,249 | — | 9,473 | 4,624 | |||||||||||||||
Provision for income taxes | 607 | 137 | 884 | 1,182 | 2,486 | |||||||||||||||
Net income | 78,798 | 638 | 114,966 | 115,316 | 165,238 | |||||||||||||||
Net income per Common Unit—basic (e) | 1.35 | 0.02 | 3.24 | 3.26 | 4.99 | |||||||||||||||
Net income per Common Unit—diluted (e) | 1.34 | 0.02 | 3.22 | 3.24 | 4.96 | |||||||||||||||
Cash distributions declared per unit | $ | 3.50 | $ | 3.41 | $ | 3.41 | $ | 3.35 | $ | 3.26 | ||||||||||
Balance Sheet Data | ||||||||||||||||||||
Cash and cash equivalents | $ | 107,232 | $ | 134,317 | $ | 149,553 | $ | 156,908 | $ | 163,173 | ||||||||||
Current assets | 293,322 | 337,515 | 297,822 | 296,427 | 307,556 | |||||||||||||||
Total assets | 2,727,987 | 2,883,850 | 956,459 | 970,914 | 978,168 | |||||||||||||||
Current liabilities | 233,894 | 253,715 | 151,514 | 164,514 | 181,930 | |||||||||||||||
Total debt | 1,245,237 | 1,422,078 | 348,169 | 347,953 | 349,415 | |||||||||||||||
Total liabilities | 1,598,861 | 1,793,351 | 598,241 | 608,258 | 620,632 | |||||||||||||||
Partners’ capital—Common Unitholders | $ | 1,176,479 | $ | 1,151,606 | $ | 418,134 | $ | 419,882 | $ | 418,824 | ||||||||||
Statement of Cash Flows Data | ||||||||||||||||||||
Cash provided by (used in) | ||||||||||||||||||||
Operating activities | $ | 214,306 | $ | 110,973 | $ | 132,786 | $ | 155,797 | $ | 246,551 | ||||||||||
Investing activities | (14,663 | ) | (239,758 | ) | (19,505 | ) | (30,111 | ) | (16,852 | ) | ||||||||||
Financing activities | $ | (226,728 | ) | $ | 113,549 | $ | (120,636 | ) | $ | (131,951 | ) | $ | (204,224 | ) | ||||||
Other Data | ||||||||||||||||||||
Depreciation and amortization | $ | 130,384 | $ | 47,034 | $ | 35,628 | $ | 30,834 | $ | 30,343 | ||||||||||
EBITDA (f) | 305,216 | 86,442 | 178,856 | 174,729 | 236,334 | |||||||||||||||
Adjusted EBITDA (f) | 329,253 | 108,536 | 179,425 | 192,420 | 239,245 | |||||||||||||||
Capital expenditures—maintenance and growth (g) | $ | 27,823 | $ | 17,476 | $ | 22,284 | $ | 19,131 | $ | 21,837 | ||||||||||
Retail gallons sold | ||||||||||||||||||||
Propane | 534,621 | 283,841 | 298,902 | 317,906 | 343,894 | |||||||||||||||
Fuel oil and refined fuels | 53,710 | 28,491 | 37,241 | 43,196 | 57,381 |
(a) | Fiscal 2012 includes 53 weeks of operations compared to 52 weeks in each of fiscal 2013, 2011, 2010, and 2009. In addition, on August 1, 2012, we acquired Inergy Propane. The results of operations of Inergy Propane have been included in the consolidated results from the Acquisition Date through September 29, 2012 and all of fiscal 2013, and the assets and liabilities of Inergy Propane have been included in the consolidated balance sheet since September 29, 2012. Refer to Note 3—Acquisition of Inergy Propane included within the Notes to the Consolidated Financial Statements section elsewhere in this Annual Report. |
(b) |
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(c) | We incurred non-cash pension settlement charges of $2.8 million |
On August 2, 2013, we repurchased pursuant to optional redemption $133.4 million of our 7.375% Senior Notes due August 1, 2021 using net proceeds from our May 2013 public offering and net proceeds from the underwriters’ exercise of their over-allotment option to purchase additional Common Units. In addition, on August 6, 2013, we repurchased $23.9 million of our 2021 Senior Notes in a private transaction using cash on hand. In connection with these repurchases, which totaled $157.3 million in aggregate principal amount, we recognized a loss on the extinguishment of debt of $2.1 million consisting of $11.7 million for the repurchase premium and related fees, as well as the write-off of $2.1 million and ($11.7) million in unamortized debt origination costs and unamortized premium, respectively. During fiscal 2012 we amended the Credit Agreement (the “Amended Credit Agreement”) to increase the five-year $250.0 million revolving credit facility (the “Revolving Credit Facility”) to $400.0 million, of which, $100.0 million was outstanding as of September 28, 2013, and also to extend the maturity date from June 25, 2013 to January 5, 2017. In connection with the execution of the Amended Credit Agreement, we recognized a non-cash charge of $0.5 million for the write-off of previously incurred debt origination costs associated with lenders who did not participate, or whose lending capacity decreased, in the amended facility. On August 1, 2012, we amended the Amended Credit Agreement to provide for a $250.0 million senior secured 364-day incremental term loan facility (the “364-Day Facility”). On August 1, 2012, in connection with the Inergy Propane Acquisition, we drew $225.0 million on the 364-Day Facility and on August 14, 2012, using the proceeds of our secondary offering of common units, we repaid the $225.0 million term loan facility, and wrote off $1.7 million of unamortized commitment fees associated with the 364-Day Facility. During fiscal 2010 we completed the issuance of $250.0 million of 7.375% senior notes maturing in March 2020 to replace the previously existing 6.875% senior notes that were set to mature in December 2013. In connection with the refinancing, we recognized a loss on debt extinguishment of $9.5 million in the second quarter of fiscal 2010, consisting of $7.2 million for the repurchase premium and related fees, as well as the write-off of $2.2 million in unamortized debt origination costs and unamortized discount. During fiscal 2009, we purchased $175.0 million aggregate principal amount of the 6.875% senior notes through a cash tender offer. In connection with the tender offer, we recognized a loss on the extinguishment of debt of $4.6 million in the fourth quarter of fiscal 2009, consisting of $2.8 million for the tender premium and related fees, as well as the write-off of $1.8 million in unamortized debt origination costs and unamortized discount. | ||
(e) | Computations of basic earnings per Common Unit were performed by dividing net income by the weighted average number of outstanding Common Units, and restricted units granted under our | |
(f) | ||
EBITDA represents net income before deducting interest expense, income taxes, depreciation and amortization. Adjusted EBITDA represents EBITDA excluding the unrealized net gain or loss from mark-to-market activity for derivative instruments |
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Fiscal | Fiscal | Fiscal | Fiscal | Fiscal | ||||||||||||||||
2011 | 2010 | 2009 | 2008 | 2007 | ||||||||||||||||
Net income | $ | 114,966 | $ | 115,316 | $ | 165,238 | $ | 154,880 | $ | 127,287 | ||||||||||
Add: | ||||||||||||||||||||
Provision for income taxes | 884 | 1,182 | 2,486 | 1,903 | 5,653 | |||||||||||||||
Interest expense, net | 27,378 | 27,397 | 38,267 | 37,052 | 35,596 | |||||||||||||||
Depreciation and amortization | ||||||||||||||||||||
Continuing operations | 35,628 | 30,834 | 30,343 | 28,394 | 28,790 | |||||||||||||||
Discontinued operations | — | — | — | — | 452 | |||||||||||||||
EBITDA | 178,856 | 174,729 | 236,334 | 222,229 | 197,778 | |||||||||||||||
Unrealized (non-cash) (gains) losses on changes in fair value of derivatives | (1,431 | ) | 5,400 | (1,713 | ) | (1,764 | ) | 7,555 | ||||||||||||
Severance charges | 2,000 | — | — | — | 1,485 | |||||||||||||||
Loss on debt extinguishment | — | 9,473 | 4,624 | — | — | |||||||||||||||
Pension settlement charge | — | 2,818 | — | — | 3,269 | |||||||||||||||
Adjusted EBITDA | 179,425 | 192,420 | 239,245 | 220,465 | 210,087 | |||||||||||||||
Add (subtract): | ||||||||||||||||||||
Provision for income taxes — current | (884 | ) | (1,182 | ) | (1,101 | ) | (626 | ) | (1,853 | ) | ||||||||||
Interest expense, net | (27,378 | ) | (27,397 | ) | (38,267 | ) | (37,052 | ) | (35,596 | ) | ||||||||||
Unrealized (non-cash) gains (losses) on changes in fair value of derivatives | 1,431 | (5,400 | ) | 1,713 | 1,764 | (7,555 | ) | |||||||||||||
Severance charges | (2,000 | ) | — | — | — | (1,485 | ) | |||||||||||||
Compensation cost recognized under Restricted Unit Plan | 3,922 | 4,005 | 2,396 | 2,156 | 3,014 | |||||||||||||||
(Gain) loss on disposal of property, plant and equipment, net | (2,772 | ) | 38 | (650 | ) | (2,252 | ) | (2,782 | ) | |||||||||||
Gain on disposal of discontinued operations | — | — | — | (43,707 | ) | (1,887 | ) | |||||||||||||
Changes in working capital and other assets and liabilities | (18,958 | ) | (6,687 | ) | 43,215 | (20,231 | ) | (15,986 | ) | |||||||||||
Net cash provided by operating activities | $ | 132,786 | $ | 155,797 | $ | 246,551 | $ | 120,517 | $ | 145,957 | ||||||||||
Fiscal | Fiscal | Fiscal | Fiscal | Fiscal | ||||||||||||||||
2013 | 2012 | 2011 | 2010 | 2009 | ||||||||||||||||
Net income | $ | 78,798 | $ | 638 | $ | 114,966 | $ | 115,316 | $ | 165,238 | ||||||||||
Add: | ||||||||||||||||||||
Provision for income taxes | 607 | 137 | 884 | 1,182 | 2,486 | |||||||||||||||
Interest expense, net | 95,427 | 38,633 | 27,378 | 27,397 | 38,267 | |||||||||||||||
Depreciation and amortization | 130,384 | 47,034 | 35,628 | 30,834 | 30,343 | |||||||||||||||
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EBITDA | 305,216 | 86,442 | 178,856 | 174,729 | 236,334 | |||||||||||||||
Unrealized (non-cash) losses (gains) on changes in fair value of derivatives | 4,318 | (4,649 | ) | (1,431 | ) | 5,400 | (1,713 | ) | ||||||||||||
Integration-related costs | 10,575 | — | — | — | — | |||||||||||||||
Multi-employer pension plan withdrawal charge | 7,000 | — | — | — | — | |||||||||||||||
Loss on debt extinguishment | 2,144 | 2,249 | — | 9,473 | 4,624 | |||||||||||||||
Acquisition-related costs | — | 17,916 | — | — | — | |||||||||||||||
Loss on legal settlement | — | 4,500 | — | — | — | |||||||||||||||
Loss on asset disposal | — | 2,078 | — | — | — | |||||||||||||||
Severance charges | — | — | 2,000 | — | — | |||||||||||||||
Pension settlement charge | — | — | — | 2,818 | — | |||||||||||||||
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Adjusted EBITDA | 329,253 | 108,536 | 179,425 | 192,420 | 239,245 | |||||||||||||||
Add (subtract): | ||||||||||||||||||||
Provision for income taxes—current | (607 | ) | (137 | ) | (884 | ) | (1,182 | ) | (1,101 | ) | ||||||||||
Interest expense, net | (95,427 | ) | (38,633 | ) | (27,378 | ) | (27,397 | ) | (38,267 | ) | ||||||||||
Unrealized (non-cash) (losses) gains on changes in fair value of derivatives | (4,318 | ) | 4,649 | 1,431 | (5,400 | ) | 1,713 | |||||||||||||
Integration-related costs | (10,575 | ) | — | — | — | — | ||||||||||||||
Multi-employer pension plan withdrawal charge | (7,000 | ) | — | — | — | — | ||||||||||||||
Acquisition-related costs | — | (17,916 | ) | — | — | — | ||||||||||||||
Loss on legal settlement | — | (4,500 | ) | — | — | — | ||||||||||||||
Severance charges | — | — | (2,000 | ) | — | — | ||||||||||||||
Compensation cost recognized under | ||||||||||||||||||||
Restricted Unit Plans | 3,888 | 4,059 | 3,922 | 4,005 | 2,396 | |||||||||||||||
(Gain) loss on disposal of property, plant and equipment, net | (3,543 | ) | (727 | ) | (2,772 | ) | 38 | (650 | ) | |||||||||||
Changes in working capital and other assets and liabilities | 2,635 | 55,642 | (18,958 | ) | (6,687 | ) | 43,215 | |||||||||||||
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Net cash provided by operating activities | $ | 214,306 | $ | 110,973 | $ | 132,786 | $ | 155,797 | $ | 246,551 | ||||||||||
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(g) | Our capital expenditures fall generally into two categories: (i) maintenance expenditures, which include expenditures for repair and replacement of property, plant and equipment; and (ii) growth capital expenditures which include new propane tanks and other equipment to facilitate expansion of our customer base and operating capacity. |
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The following is a discussion of our financial condition and results of operations, which should be read in conjunction with our consolidated financial statements and notes thereto included elsewhere in this Annual Report.
Executive Overview
The following are factors that regularly affect our operating results and financial condition. In addition, our business is subject to the risks and uncertainties described in Item 1A of this Annual Report.
Product Costs and Supply
The level of profitability in the retail propane, fuel oil, natural gas and electricity businesses is largely dependent on the difference between retail sales price and product cost. The unit cost of our products, particularly propane, fuel oil and natural gas, is subject to volatility as a result of supply and demand dynamics or other market conditions, including, but not limited to, economic and political factors impacting crude oil and natural gas supply or pricing. We enter into product supply contracts that are generally one-year agreements subject to annual renewal, and also purchase product on the open market. We attempt to reduce price risk by pricing product on a short-term basis. Our propane supply contracts typically provide for pricing based upon index formulas using the posted prices established at major supply points such as Mont Belvieu, Texas, or Conway, Kansas (plus transportation costs) at the time of delivery.
To supplement our annual purchase requirements, we may utilize forward fixed price purchase contracts to acquire a portion of the propane that we resell to our customers, which allows us to manage our exposure to unfavorable changes in commodity prices and to assure adequate physical supply. The percentage of contract purchases, and the amount of supply contracted for under forward contracts at fixed prices, will vary from year to year based on market conditions.
Product cost changes can occur rapidly over a short period of time and can impact profitability. There is no assurance that we will be able to pass on product cost increases fully or immediately, particularly when product costs increase rapidly. Therefore, average retail sales prices can vary significantly from year to year as product costs fluctuate with propane, fuel oil, crude oil and natural gas commodity market conditions. In addition, periods of sustained higher commodity prices can lead to customer conservation, resulting in reduced demand for our product.
Seasonality
The retail propane and fuel oil distribution businesses, as well as the natural gas marketing business, are seasonal because these fuels are primarily used for heating in residential and commercial buildings. Historically, approximatelytwo-thirds of our retail propane volume is sold during the six-month peak heating season from October through March. The fuel oil business tends to experience greater seasonality given its more limited use for space heating and approximately three-fourths of our fuel oil volumes are sold between October and March. Consequently, sales and operating profits are concentrated in our first and second fiscal quarters. Cash flows from operations, therefore, are greatest during the second and third fiscal quarters when customers pay for product purchased during the winter heating season. We expect lower operating profits and either net losses or lower net income during the period from April through September (our third and fourth fiscal quarters). To the extent necessary, we will reserve cash from the second and third quarters for distribution to holders of our Common Units in the fourth quarter and following fiscal year first quarter.
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Weather conditions have a significant impact on the demand for our products, in particular propane, fuel oil and natural gas, for both heating and agricultural purposes. Many of our customers rely heavily on propane, fuel oil or natural gas as a heating source. Accordingly, the volume sold is directly affected by the severity of the winter weather in our service areas, which can vary substantially from year to year. In any given area, sustained warmer than normal temperatures, will tend to result in reduced propane, fuel oil and natural gas consumption, while sustained colder than normal temperatures will tend to result in greater consumption.
Hedging and Risk Management Activities
We engage in hedging and risk management activities to reduce the effect of price volatility on our product costs and to ensure the availability of product during periods of short supply. We enter into propane forward, options and optionswap agreements with third parties, and use futures and optionoptions contracts traded on the New York Mercantile Exchange (“NYMEX”) to purchase and sell propane, fuel oil and crude oil at fixed prices in the future. The majority of the futures, forward and optionoptions agreements are used to hedge price risk associated with propane and fuel oil physical inventory, as well as, in certain instances, forecasted purchases of propane or fuel oil. In addition, we sell propane and fuel oil to customers at fixed prices, and enter into derivative instruments to hedge a portion of our exposure to fluctuations in commodity prices as a result of selling the fixed price contracts. Forward contracts are generally settled physically at the expiration of the contract whereas futures, options and optionswap contracts are generally settled in cash at the expiration of the contract. Although we use derivative instruments to reduce the effect of price volatility associated with priced physical inventory and forecasted transactions, we do not use derivative instruments for speculative trading purposes. Risk management activities are monitored by an internal Commodity Risk Management Committee, made up of five members of management and reporting to our Audit Committee, through enforcement of our Hedging and Risk Management Policy.
Critical Accounting Policies and Estimates
Our significant accounting policies are summarized in Note 2, “Summary2—Summary of Significant Accounting Policies” included within the Notes to Consolidated Financial Statements section elsewhere in this Annual Report.
Certain amounts included in or affecting our consolidated financial statements and related disclosures must be estimated, requiring management to make certain assumptions with respect to values or conditions that cannot be known with certainty at the time the financial statements are prepared. The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (“US GAAP”) 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 revenues and expenses during the reporting period. We are also subject to risks and uncertainties that may cause actual results to differ from estimated results. Estimates are used when accounting for depreciation and amortization of long-lived assets, employee benefit plans, self-insurance and litigation reserves, environmental reserves, allowances for doubtful accounts, asset valuation assessments and valuation of derivative instruments. We base our estimates on historical experience and on various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known to us. Management has reviewed these critical accounting estimates and related disclosures with the Audit Committee of our Board of Supervisors. We believe that the following are our critical accounting estimates:
Allowances for Doubtful Accounts. We maintain allowances for doubtful accounts for estimated losses resulting from the inability of our customers to make required payments. We estimate our allowances for doubtful accounts using a specific reserve for known or anticipated uncollectible accounts, as well as an estimated reserve for potential future uncollectible accounts taking into consideration our historical write-offs. If the financial condition of one or more of our customers were to deteriorate resulting in an impairment in their ability to make payments, additional allowances could be required. As a result of our large customer base, which is comprised of approximately 750,000more than 1.2 million customers, no individual customer account is material. Therefore, while some variation to actual results occurs, historically such variability has not been material. Schedule II, Valuation and Qualifying Accounts, provides a summary of the changes in our allowances for doubtful accounts during the period.
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Self-Insurance Reserves. Our accrued self-insurance reserves represent the estimated costs of known and anticipated or unasserted claims under our general and product, workers’ compensation and automobile insurance policies. Accrued insurance provisions for unasserted claims arising from unreported incidents are based on an analysis of historical claims data. For each unasserted claim, we record aself-insurance provision up to the estimated amount of the probable claim utilizing actuarially determined loss development factors applied to actual claims data. Our self-insurance provisions are susceptible to change to the extent that actual claims development differs from historical claims development. We maintain insurance coverage wherein our net exposure for insured claims is limited to the insurance deductible, claims above which are paid by our insurance carriers. For the portion of our estimated self-insurance liability that exceeds our deductibles, we record an asset related to the amount of the liability expected to be paid by the insurance companies. Historically, we have not experienced significant variability in our actuarial estimates for claims incurred but not reported. Accrued insurance provisions for reported claims are reviewed at least quarterly, and our assessment of whether a loss is probable and/or reasonably estimable is updated as necessary. Due to the inherently uncertain nature of, in particular, product liability claims, the ultimate loss may differ materially from our estimates. However, because of the nature of our insurance arrangements, those material variations historically have not, nor are they expected in the future to have, a material impact on our results of operations or financial position.
Loss Contingencies. In the normal course of business, we are involved in various claims and legal proceedings. We record a liability for such matters when it is probable that a loss has been incurred and the amounts can be reasonably estimated. The liability includes probable and estimable legal costs to the point in the legal matter where we believe a conclusion to the matter will be reached. When only a range of possible loss can be established, the most probable amount in the range is accrued. If no amount within this range is a better estimate than any other amount within the range, the minimum amount in the range is accrued.
Fair Values of Acquired Assets and Liabilities. From time to time, we enter into material business combinations. In accordance with accounting guidance associated with business combinations, the assets acquired and liabilities assumed are recorded at their estimated fair value as of the acquisition date. Fair values of assets acquired and liabilities assumed are based upon available information and may involve us engaging an independent third party to perform an appraisal. Estimating fair values can be complex and subject to significant business judgment. Estimates most commonly impact property, plant and equipment and intangible assets, including goodwill. Generally, we have, if necessary, up to one year from the acquisition date to finalize our estimates of acquisition date fair values.
Results of Operations and Financial Condition
For comparative purposes, fiscal 2013 included 52 weeks of operations compared to 53 weeks in fiscal 2012. In addition, the variances in year-over-year results were primarily attributable to the inclusion of Inergy Propane, acquired on August 1, 2012, as well as improvements in the operating performance in our legacy operations. Net income for fiscal 20112013 amounted to $115.0$78.8 million, or $3.24$1.35 per Common Unit, compared to $115.3$0.6 million, or $3.26$0.02 per Common Unit, in fiscal 2010.2012. Earnings before interest, taxes, depreciation and amortization (“EBITDA”) for fiscal 20112013 amounted to $178.9$305.2 million, compared to $174.7$86.4 million for fiscal 2010.
Net income and EBITDA for fiscal 2011 included a $2.02013 included: (i) $10.6 million charge for severance costs associated within expenses related to the realignmentongoing integration of Inergy Propane; (ii) $7.0 million in charges related to our voluntary withdrawal from multi-employer pension plans covering certain employees acquired in the Partnership’s field operations, as well as a non-cash charge of $2.9 million to accelerate depreciation expense on assets taken out of service. By comparison, net incomeInergy Propane Acquisition; and EBITDA for fiscal 2010 included: (i)(iii) a loss on debt extinguishment of $9.5$2.1 million. Net income and EBITDA for fiscal 2012 included: (i) $17.9 million in acquisition-related costs associated with the Inergy Propane Acquisition; (ii) a charge of $4.5 million associated with a refinancing of the Partnership’s senior notes; (ii) a non-cash pension settlement charge of $2.8 million; andlegal settlement; (iii) a $2.1 million non-cash charge from a loss on disposal of $1.8 million to accelerate depreciation expensean asset in our natural gas and electricity business; and (iv) a loss on assets taken outdebt extinguishment of service.$2.2 million. Excluding the effects of these charges, as well as the unrealized (non-cash) mark-to-market adjustments on derivative instruments in both years, Adjusted EBITDA (as defined and reconciled below) amounted to $179.4$329.3 million for fiscal 2013, compared to Adjusted EBITDA of $108.5 million in fiscal 2011, compared to $192.4 million in fiscal 2010.
Retail propane gallons sold for fiscal 2011 decreased 19.02013 increased 250.8 million gallons, or 6.0%88.4%, to 298.9534.6 million gallons from 317.9283.8 million gallons in fiscal 2010.2012. Sales of fuel oil and other refined fuels for fiscal 2011 decreased 6.0also increased 88.4%, to 53.7 million gallons or 13.9%, to 37.2 million gallons compared to 43.2from 28.5 million gallons in the prior year. SalesThe increase in volumes in both segments continued to be negatively affected by weakness in the economy, coupled with customer conservationsold was primarily attributable to the high commodity price environment relative to historical levels. Average posted pricesinclusion of the Inergy Propane operations for propane and fuel oil were 26.7% and 36.6% higher, respectively, compared to fiscal 2010,a full year, as commodity prices continued to rise throughout much of fiscal 2011. From a weather perspective,well as increases in our legacy operations resulting from average temperatures for fiscal 2011that were 1% warmer thancloser to normal compared to 5% warmer than normal in the prior year.
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During fiscal 2013, we made notable progress in our integration efforts and in executing our strategic financing initiatives, all of which have better positioned us operationally and financially to higher base commodity prices, offsetcontinue to an extent by lower volumes sold. Cost of products soldpursue further growth opportunities. To highlight a few key accomplishments for fiscal 2011 of $678.7 million increased $80.2 million, or 13.4%, compared2013:
Despite the increase in accelerated depreciationincreased size of our business and the increased working capital needs, for assets taken out of service referenced above.
As we look ahead to fiscal 2012,2014, our anticipated cash requirements include: (i) maintenance and growth capital expenditures of approximately $22.0$30.0 million; (ii) approximately $26.2$88.1 million of interest and income tax payments; and (iii) approximately $211.1 million of distributions to Unitholders, assuming distributions remain at the current annualized levelrate of $3.41$3.50 per Common Unit, approximately $121.2 million of distributions to Unitholders.Unit. Based on our current cash position, availability under the Revolving Credit AgreementFacility (unused borrowing capacity of $95.1$253.3 million at September 24, 2011)28, 2013) and expected cash flow from operating activities, we expect to have sufficient funds to meet our current and future obligations. Based on our current forecast of working capital requirements for fiscal 2012, we currently do not expect to borrow under our credit facility to fund those requirements.
Fiscal Year 20112013 Compared to Fiscal Year 20102012
Revenues
Percent | ||||||||||||||||
Fiscal | Fiscal | Increase/ | Increase/ | |||||||||||||
(Dollars in thousands) | 2011 | 2010 | (Decrease) | (Decrease) | ||||||||||||
Revenues | ||||||||||||||||
Propane | $ | 929,492 | $ | 885,459 | $ | 44,033 | 5.0 | % | ||||||||
Fuel oil and refined fuels | 139,572 | 135,059 | 4,513 | 3.3 | % | |||||||||||
Natural gas and electricity | 84,721 | 77,587 | 7,134 | 9.2 | % | |||||||||||
All other | 36,767 | 38,589 | (1,822 | ) | (4.7 | %) | ||||||||||
Total revenues | $ | 1,190,552 | $ | 1,136,694 | $ | 53,858 | 4.7 | % | ||||||||
(Dollars in thousands) | ||||||||||||||||
Fiscal | Fiscal | Percent | ||||||||||||||
2013 | 2012 | Increase | Increase | |||||||||||||
Revenues | ||||||||||||||||
Propane | $ | 1,357,102 | $ | 843,648 | $ | 513,454 | 60.9 | % | ||||||||
Fuel oil and refined fuels | 208,957 | 114,288 | 94,669 | 82.8 | % | |||||||||||
Natural gas and electricity | 79,432 | 67,419 | 12,013 | 17.8 | % | |||||||||||
All other | 58,115 | 38,103 | 20,012 | 52.5 | % | |||||||||||
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Total revenues | $ | 1,703,606 | $ | 1,063,458 | $ | 640,148 | 60.2 | % | ||||||||
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Total revenues increased $53.9$640.1 million, or 4.7%60.2%, to $1,190.6 million in fiscal 2011 compared to $1,136.7$1,703.6 million for fiscal 2010,2013 compared to $1,063.5 million for the prior year due to higher average selling prices associated with higher product costs, partiallyvolumes sold, offset to an extent by lower average propane, fuel oil and refined fuels and natural gas selling prices. The increase in sales volumes sold. From a weather perspective,was primarily due to the addition of the Inergy Propane business, as well as increases in our legacy operations resulting from colder average temperatures. As discussed above, average temperatures as(as measured in heating degree days, as reported by the National Oceanic and Atmospheric Administration (“NOAA”), indays) across all of our service territories duringfor fiscal 20112013 were 1%4% warmer than normal, and 4% coldercompared to 14% warmer than normal for the prior year.
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Revenues from the distribution of fuel oil and refined fuels of $139.6$209.0 million for fiscal 20112013 increased $4.5$94.7 million, or 3.3%82.8%, from $135.1$114.3 million for the prior year, primarily due to higher volumes sold, partially offset by lower average selling prices. Fuel oil and refined fuels gallons sold in fiscal 2013 increased 25.2 million gallons, or 88.4%, to 53.7 million gallons from 28.5 million gallons in the prior year, primarily as a result of higherthe addition of Inergy Propane, as well as increases in our legacy operations resulting from colder average selling prices associated with higher product costs, partially offset by lowertemperatures. Higher fuel oil and refined fuels volumes sold.sold resulted in an increase in revenues of $100.5 million for fiscal 2013 compared to the prior year. Average selling prices in our fuel oil and refined fuels segment in fiscal 2011 increased 20.1%2013 decreased 2.6% compared to the prior year, due to higher product costs, thereby havingresulting in a positive impact on revenues. Fuel oil and refined fuels gallons sold$5.8 million decrease in fiscal 2011 decreased 6.0 million gallons, or 13.8%, to 37.2 million gallons from 43.2 million gallons in the prior year. Lower volumes sold in our fuel oil and refined fuels segment were primarily attributable to our gasoline and diesel businesses and, to a lesser extent, our heating oil business.
Revenues in our natural gas and electricity segment increased $7.1$12.0 million, or 9.2%17.8%, to $84.7$79.4 million in fiscal 20112013 compared to $77.6$67.4 million in the prior year as a result of higher natural gas and, to a lesser extent, electricity volumes sold, coupled withand higher electricity average selling prices associated with higher product costs.
Cost of Products Sold
Percent | ||||||||||||||||
Fiscal | Fiscal | Increase/ | Increase/ | |||||||||||||
(Dollars in thousands) | 2011 | 2010 | (Decrease) | (Decrease) | ||||||||||||
Cost of products sold | ||||||||||||||||
Propane | $ | 506,481 | $ | 436,825 | $ | 69,656 | 15.9 | % | ||||||||
Fuel oil and refined fuels | 100,908 | 92,037 | 8,871 | 9.6 | % | |||||||||||
Natural gas and electricity | 61,495 | 57,892 | 3,603 | 6.2 | % | |||||||||||
All other | 9,835 | 11,697 | (1,862 | ) | (15.9 | %) | ||||||||||
Total cost of products sold | $ | 678,719 | $ | 598,451 | $ | 80,268 | 13.4 | % | ||||||||
As a percent of total revenues | 57.0 | % | 52.6 | % |
(Dollars in thousands) | ||||||||||||||||
Fiscal | Fiscal | Percent | ||||||||||||||
2013 | 2012 | Increase | Increase | |||||||||||||
Cost of products sold | ||||||||||||||||
Propane | $ | 612,240 | $ | 448,120 | $ | 164,120 | 36.6 | % | ||||||||
Fuel oil and refined fuels | 172,022 | 91,239 | 80,783 | 88.5 | % | |||||||||||
Natural gas and electricity | 55,995 | 46,915 | 9,080 | 19.4 | % | |||||||||||
All other | 21,648 | 12,785 | 8,863 | 69.3 | % | |||||||||||
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|
|
|
|
| |||||||||||
Total cost of products sold | $ | 861,905 | $ | 599,059 | $ | 262,846 | 43.9 | % | ||||||||
|
|
|
|
|
| |||||||||||
As a percent of total revenues | 50.6 | % | 56.3 | % |
The cost of products sold reported in the consolidated statements of operations represents the weighted average unit cost of propane, fuel oil and refined fuels, natural gas and electricity sold, including transportation costs to deliver product from our supply points to storage or to our customer service centers. Cost of products sold also includes the cost of appliances and related parts sold or installed by our customer service centers computed on a basis that approximates the average cost of the products. Unrealized (non-cash) gains or losses from changes in the fair value of derivative instruments that are not designated as cash flow hedges are recorded within cost of products sold. Cost of products sold excludes depreciation and amortization; these amounts are reported separately within the consolidated statements of operations.
30
Cost of products sold associated with the distribution of propane and related activities of $506.5$612.2 million for fiscal 20112013 increased $69.7$164.1 million, or 15.9%36.6%, compared to the prior year. Higher averageretail propane product costsvolumes sold resulted in an increase of $70.9$368.4 million in cost of products sold during fiscal 20112013 compared to the prior year. The impact of the increase in average propane product costsvolumes sold was partially offset by lower average propane volumes sold,costs, which resulted in a $25.5$190.0 million decrease in cost of products sold during fiscal 2011 compared to the prior year.year-over-year. Cost of products sold from other propane activities increased $24.6decreased $23.2 million in fiscal 20112013 compared to the prior year.
Cost of products sold associated with our fuel oil and refined fuels segment of $100.9$172.0 million for fiscal 20112013 increased $8.9$80.8 million, or 9.6%88.5%, compared to the prior year. Higher average fuel oil and refined fuel product costs resulted in an increase of $27.3 million in cost of products sold during fiscal 2011 comparedyear primarily due to the prior year. The impact of the increase in product costs was partially offset by lowerhigher fuel oil and refined fuels volumes sold, which resulted in an $11.9 million decrease in cost of products sold in fiscal 2011 compared to the prior year.
Cost of products sold in our natural gas and electricity segment of $61.5$56.0 million for fiscal 20112013 increased $3.6$9.1 million, or 6.2%19.4%, compared to the prior year, primarily due to higher natural gas and, to a lesser extent, electricity volumes sold, coupled with an increase in averageand higher electricity product costs.
Total cost of products sold as a percent of total revenues for fiscal 2011 increased 4.4decreased 5.7 percentage points to 57.0%50.6% in fiscal 2013 from 52.6%56.3% in the prior year. The increaseyear, primarily due to the decline in cost of products sold as a percentage of revenues was primarily attributable topropane wholesale product costs rising at a faster rate thanoutpacing the decline in propane average selling pricesprices. In addition, colder average temperatures and the inclusion of Inergy Propane operations resulted in a higher concentration of residential volumes sold in fiscal 20112013 compared to the prior year.
Operating Expenses
Fiscal | Fiscal | Percent | ||||||||||||||
(Dollars in thousands) | 2011 | 2010 | (Decrease) | (Decrease) | ||||||||||||
Operating expenses | $ | 279,329 | $ | 289,567 | $ | (10,238 | ) | (3.5 | %) | |||||||
As a percent of total revenues | 23.5 | % | 25.5 | % |
(Dollars in thousands) | ||||||||||||||||
Fiscal | Fiscal | Percent | ||||||||||||||
2013 | 2012 | Increase | Increase | |||||||||||||
Operating expenses | $ | 469,496 | $ | 298,772 | $ | 170,724 | 57.1 | % | ||||||||
As a percent of total revenues | 27.6 | % | 28.1 | % |
All costs of operating our retail distribution and appliance sales and service operations are reported within operating expenses in the consolidated statements of operations. These operating expenses include the compensation and benefits of field and direct operating support personnel, costs of operating and maintaining our vehicle fleet, overhead and other costs of our purchasing, training and safety departments and other direct and indirect costs of operating our customer service centers.
Operating expenses of $279.3$469.5 million for fiscal 2011 decreased $10.22013 increased $170.7 million, or 3.5%57.1%, compared to $289.6$298.8 million in the prior year, as a resultprimarily due to the addition of lower variable compensation associated with lower earnings,Inergy Propane, offset to an extent by lower payroll and benefit related expenses in our legacy operations resulting from operating efficiencies,efficiencies. In addition, operating expenses for fiscal 2013 included a $7.0 million charge related to our voluntary partial withdrawal from a multi-employer pension plan and lower insurance costs.full withdrawal from four multi-employer pension plans, and a charge of $4.6 million primarily for severance costs, both charges were associated with the integration of the Inergy Propane operations. These savingscharges were partially offset by an increaseexcluded from our calculation of Adjusted EBITDA below.
As a result of the progress on our efforts to integrate the operations of Inergy Propane, including the initial process of blending geographic territories and systems, which commenced at the beginning of the third quarter of fiscal 2013, we have realized certain synergies in fuel costs to operatethe combined operating expenses of Inergy Propane and our fleet.
legacy operations.
31
Fiscal | Fiscal | Percent | ||||||||||||||
(Dollars in thousands) | 2011 | 2010 | (Decrease) | (Decrease) | ||||||||||||
General and administrative expenses | $ | 51,648 | $ | 61,656 | $ | (10,008 | ) | (16.2 | %) | |||||||
As a percent of total revenues | 4.3 | % | 5.4 | % |
(Dollars in thousands) | ||||||||||||||||
Fiscal | Fiscal | Percent | ||||||||||||||
2013 | 2012 | Increase | Increase | |||||||||||||
General and administrative expenses | $ | 64,845 | $ | 59,020 | $ | 5,825 | 9.9 | % | ||||||||
As a percent of total revenues | 3.8 | % | 5.5 | % |
All costs of our back office support functions, including compensation and benefits for executives and other support functions, as well as other costs and expenses to maintain finance and accounting, treasury, legal, human resources, corporate development and the information systems functions are reported within general and administrative expenses in the consolidated statements of operations.
General and administrative expenses of $51.6$64.8 million for fiscal 2011 decreased $10.02013 increased $5.8 million or 16.2%, compared to $61.6$59.0 million for the prior year, primarily due to higher variable compensation associated with higher earnings, offset to an extent by a $2.2 million gain on the sale of an asset in fiscal 2013. In addition, general and administrative expenses for fiscal 2013 included $6.0 million of professional services and other expenses associated with the integration of the Inergy Propane operations. General and administrative expenses for fiscal 2012 included a $4.5 million charge associated with a legal settlement (see Item 3 and Note 12 included within the Notes to the Consolidated Financial Statements section elsewhere in this Annual Report for additional discussion), and a $2.1 million non-cash charge from a loss on disposal of an asset used in our natural gas and electricity business. These items were excluded from our calculation of Adjusted EBITDA below.
Acquisition-related Costs
During fiscal 2012 we recorded acquisition-related costs of $17.9 million related to the Inergy Propane Acquisition. These costs were primarily attributable to investment banker, legal, accounting and other consulting fees.
Depreciation and Amortization
(Dollars in thousands) | ||||||||||||||||
Fiscal | Fiscal | Percent | ||||||||||||||
2013 | 2012 | Increase | Increase | |||||||||||||
Depreciation and amortization | $ | 130,384 | $ | 47,034 | $ | 83,350 | 177.2 | % | ||||||||
As a percent of total revenues | 7.7 | % | 4.4 | % |
Depreciation and amortization expense of $130.4 million in fiscal 2013 increased $83.4 million, primarily as a result of the acquired tangible and identifiable intangible assets of Inergy Propane.
Interest Expense, net
(Dollars in thousands) | ||||||||||||||||
Fiscal | Fiscal | Percent | ||||||||||||||
2013 | 2012 | Increase | Increase | |||||||||||||
Interest expense, net | $ | 95,427 | $ | 38,633 | $ | 56,794 | 147.0 | % | ||||||||
As a percent of total revenues | 5.6 | % | 3.6 | % |
Net interest expense of $95.4 million for fiscal 2013 increased $56.8 million compared to $38.6 million in the prior year, primarily as a resultdue to the issuance of lower variable compensation associated with lower earnings and the impact of a $2.5 million gain on sale of assets during the second quarter of fiscal 2011, partially offset by an increase in litigation costs for uninsured legal matters.
Fiscal | Fiscal | Percent | ||||||||||||||
(Dollars in thousands) | 2011 | 2010 | Increase | Increase | ||||||||||||
Depreciation and amortization | $ | 35,628 | $ | 30,834 | $ | 4,794 | 15.5 | % | ||||||||
As a percent of total revenues | 3.0 | % | 2.7 | % |
Fiscal | Fiscal | Percent | ||||||||||||||
(Dollars in thousands) | 2011 | 2010 | (Decrease) | (Decrease) | ||||||||||||
Interest expense, net | $ | 27,378 | $ | 27,397 | $ | (19 | ) | (0.1 | %) | |||||||
As a percent of total revenues | 2.3 | % | 2.4 | % |
discussion.
32
On March 23, 2010,August 2, 2013, we repurchased, $250.0pursuant to an optional redemption, $133.4 million aggregate principal amount of our 7.375% senior notes due August 1, 2021 using net proceeds from our May 2013 public offering and net proceeds from the underwriters’ exercise of their over-allotment option to purchase additional Common Units. In addition, on August 6, 2013, Senior Notes throughwe repurchased $23.9 million of our 2021 senior notes in a private transaction using cash tender offer.on hand. In connection with the repurchase,these repurchases, which totaled $157.3 million in aggregate principal amount, we recognized a loss on the extinguishment of debt of $9.5$2.1 million in the second quarter of fiscal 2010, consisting of $7.2$11.7 million for the repurchase premium and related fees, as well as the write-off of $2.3$2.1 million and ($11.7) million in unamortized debt origination costs and unamortized discount.
During fiscal 2012, in connection with the execution of the amendment of our credit agreement on January 5, 2012, we recognized a non-cash charge of $0.5 million to write-off a portion of unamortized debt origination costs associated with the credit agreement during the first quarter of fiscal 2012. In addition, in connection with the repayment, on August 14, 2012, of borrowings under our 364-Day Facility (defined below) which was used as short-term financing to fund a portion of the Inergy Propane Acquisition, we recognized a non-cash charge of $1.7 million to write off unamortized debt origination costs associated with the 364-Day Facility during the fourth quarter of fiscal 2012. See Liquidity and Capital Resources below for additional discussion on the amendment to the credit agreement and other financing activities.
Net Income and Adjusted EBITDA
Net income of $115.0for fiscal 2013 amounted to $78.8 million, or $3.24$1.35 per Common Unit, compared to $0.6 million, or $0.02 per Common Unit, in fiscal 20112012. Earnings before interest, taxes, depreciation and amortization (“EBITDA”) for fiscal 2013 amounted to $305.2 million, compared to net income of $115.3$86.4 million or $3.26 per Common Unit in the prior year. Adjusted EBITDA amounted to $179.4 million infor fiscal 2011, compared to $192.4 million in fiscal 2010.
Net income and EBITDA for fiscal 2011 were negatively impacted by a $2.02013 included: (i) $10.6 million charge for severance costs associated with a realignmentin expenses related to the ongoing integration of Inergy Propane; (ii) $7.0 million in charges related to our field operations, as well as a non-cash charge of $2.9 to accelerate depreciation expense on assets taken out of service. By comparison, net incomevoluntary withdrawal from multi-employer pension plans covering certain employees acquired in the Inergy Propane Acquisition; and EBITDA for fiscal 2010 were negatively impacted by certain items, including: (i)(iii) a loss on debt extinguishment of $9.5$2.1 million. Net income and EBITDA for fiscal 2012 included: (i) $17.9 million in acquisition-related costs associated with the Inergy Propane Acquisition; (ii) a charge of $4.5 million associated with the refinancing of senior notes; (ii) a non-cash pension settlement charge of $2.8 million; andlegal settlement; (iii) a $2.1 million non-cash charge from a loss on disposal of $1.8an asset in our natural gas and electricity business; and (iv) a loss on debt extinguishment of $2.2 million. Excluding the effects of these charges, as well as the unrealized (non-cash) mark-to-market adjustments on derivative instruments in both years, Adjusted EBITDA amounted to $329.3 million for fiscal 2013, compared to accelerate depreciation expense on assets taken outAdjusted EBITDA of service.
Adjusted EBITDA represents EBITDA excluding the unrealized net gain or loss from mark-to-market activity for derivative instruments loss on debt extinguishment, pension settlement charge and severance charges.other certain items as provided in the table below. Our management uses EBITDA and Adjusted EBITDA as measures of liquidity and we are including them because we believe that they provide our investors and industry analysts with additional information to evaluate our ability to meet our debt service obligations and to pay our quarterly distributions to holders of our Common Units. In addition, certain of our incentive compensation plans covering executives and other employees utilize Adjusted EBITDA as the performance target. Moreover, our revolving credit agreement requires us to use Adjusted EBITDA as a component in calculating our leverage and interest coverage ratios. EBITDA and Adjusted EBITDA are not recognized terms under US GAAP and should not be considered as an alternative to net income or net cash provided by operating activities determined in accordance with US GAAP. Because EBITDA and Adjusted EBITDA as determined by us excludes some, but not all, items that affect net income, they may not be comparable to EBITDA and Adjusted EBITDA or similarly titled measures used by other companies.
33
Year Ended | ||||||||
September 24, | September 25, | |||||||
(Dollars in thousands) | 2011 | 2010 | ||||||
Net income | $ | 114,966 | $ | 115,316 | ||||
Add: | ||||||||
Provision for income taxes | 884 | 1,182 | ||||||
Interest expense, net | 27,378 | 27,397 | ||||||
Depreciation and amortization | 35,628 | 30,834 | ||||||
EBITDA | 178,856 | 174,729 | ||||||
Unrealized (non-cash) (gains) losses on changes in fair value of derivatives | (1,431 | ) | 5,400 | |||||
Severance charges | 2,000 | — | ||||||
Loss on debt extinguishment | — | 9,473 | ||||||
Pension settlement charge | — | 2,818 | ||||||
Adjusted EBITDA | 179,425 | 192,420 | ||||||
Add (subtract): | ||||||||
Provision for income taxes — current | (884 | ) | (1,182 | ) | ||||
Interest expense, net | (27,378 | ) | (27,397 | ) | ||||
Unrealized (non-cash) gains (losses) on changes in fair value of derivatives | 1,431 | (5,400 | ) | |||||
Severance charges | (2,000 | ) | — | |||||
Compensation cost recognized under Restricted Unit Plans | 3,922 | 4,005 | ||||||
(Gain) loss on disposal of property, plant and equipment, net | (2,772 | ) | 38 | |||||
Changes in working capital and other assets and liabilities | (18,958 | ) | (6,687 | ) | ||||
Net cash provided by operating activities | $ | 132,786 | $ | 155,797 | ||||
(Dollars in thousands) | Year Ended | |||||||
September 28, | September 29, | |||||||
2013 | 2012 | |||||||
Net income | $ | 78,798 | $ | 638 | ||||
Add: | ||||||||
Provision for income taxes | 607 | 137 | ||||||
Interest expense, net | 95,427 | 38,633 | ||||||
Depreciation and amortization | 130,384 | 47,034 | ||||||
|
|
|
| |||||
EBITDA | 305,216 | 86,442 | ||||||
Unrealized (non-cash) losses (gains) on changes in fair value of derivatives | 4,318 | (4,649 | ) | |||||
Integration-related costs | 10,575 | — | ||||||
Multi-employer pension plan withdrawal charge | 7,000 | — | ||||||
Loss on debt extinguishment | 2,144 | 2,249 | ||||||
Acquisition-related costs | — | 17,916 | ||||||
Loss on legal settlement | — | 4,500 | ||||||
Loss on asset disposal | — | 2,078 | ||||||
|
|
|
| |||||
Adjusted EBITDA | 329,253 | 108,536 | ||||||
Add (subtract): | ||||||||
Provision for income taxes | (607 | ) | (137 | ) | ||||
Interest expense, net | (95,427 | ) | (38,633 | ) | ||||
Unrealized (non-cash) (losses) gains on changes in fair value of derivatives | (4,318 | ) | 4,649 | |||||
Integration-related costs | (10,575 | ) | — | |||||
Multi-employer pension plan withdrawal charge | (7,000 | ) | — | |||||
Acquisition-related costs | — | (17,916 | ) | |||||
Loss on legal settlement | — | (4,500 | ) | |||||
Compensation cost recognized under Restricted Unit Plans | 3,888 | 4,059 | ||||||
Gain on disposal of property, plant and equipment, net | (3,543 | ) | (727 | ) | ||||
Changes in working capital and other assets and liabilities | 2,635 | 55,642 | ||||||
|
|
|
| |||||
Net cash provided by operating activities | $ | 214,306 | $ | 110,973 | ||||
|
|
|
|
Fiscal Year 20102012 Compared to Fiscal Year 20092011
Revenues
Percent | ||||||||||||||||
Fiscal | Fiscal | Increase/ | Increase/ | |||||||||||||
(Dollars in thousands) | 2010 | 2009 | (Decrease) | (Decrease) | ||||||||||||
Revenues | ||||||||||||||||
Propane | $ | 885,459 | $ | 864,012 | $ | 21,447 | 2.5 | % | ||||||||
Fuel oil and refined fuels | 135,059 | 159,596 | (24,537 | ) | (15.4 | )% | ||||||||||
Natural gas and electricity | 77,587 | 76,832 | 755 | 1.0 | % | |||||||||||
All other | 38,589 | 42,714 | (4,125 | ) | (9.7 | )% | ||||||||||
Total revenues | $ | 1,136,694 | $ | 1,143,154 | $ | (6,460 | ) | (0.6 | )% | |||||||
(Dollars in thousands) | Percent | |||||||||||||||
Fiscal | Fiscal | Increase/ | Increase/ | |||||||||||||
2012 | 2011 | (Decrease) | (Decrease) | |||||||||||||
Revenues | ||||||||||||||||
Propane | $ | 843,648 | $ | 929,492 | $ | (85,844 | ) | (9.2 | %) | |||||||
Fuel oil and refined fuels | 114,288 | 139,572 | (25,284 | ) | (18.1 | %) | ||||||||||
Natural gas and electricity | 67,419 | 84,721 | (17,302 | ) | (20.4 | %) | ||||||||||
All other | 38,103 | 36,767 | 1,336 | 3.6 | % | |||||||||||
|
|
|
|
|
| |||||||||||
Total revenues | $ | 1,063,458 | $ | 1,190,552 | $ | (127,094 | ) | (10.7 | %) | |||||||
|
|
|
|
|
|
34
Revenues from the distribution of propane and related activities of $885.5$843.6 million for fiscal 2012 decreased $85.9 million, or 9.2%, compared to $929.5 million for the prior year, ended September 25, 2010 increased $21.4 million, or 2.5%, comparedprimarily due to $864.0 million for the year ended September 26, 2009, primarily as a result of higher average selling prices associated with higher product costs, partially offset by lower volumes particularly in our commercialsold and industrial accounts. Averagelower average propane selling prices in fiscal 2010 increased 9.8% compared to the prior year due to higher product costs, thereby having a positive impact on revenues. This increase was partially offset by lower retailprices. Retail propane gallons sold in fiscal 2010 which2012 decreased 26.015.1 million gallons, or 7.6%5.1%, to 317.9283.8 million gallons from 343.9298.9 million gallons in the prior year. The volume decline was more pronounced within our residential customer base as the impact of weather has a greater effect on our residential customers’ propane consumption, which, during the winter, is primarily attributablefor space heating. The impact of record warm temperatures on volumes sold was offset to an extent by the addition of propane volumes sold from Inergy Propane since August 1, 2012, which contributed 27.0 million gallons of propane gallons sold in fiscal 2012. Average propane selling prices for fiscal 2012 decreased 5.0% compared to the prior year due to lower commercial and industrial volumes resulting from adverse economic conditions, an unfavorable weather pattern and, to a lesser extent, continued residential customer conservation. Lower volumes sold in the non-residential customer base accounted for approximately 60% of the decline in propane sales volume. Additionally, includedwholesale product costs. Included within the propane segment are revenues from wholesale and other propane activities of $52.7$74.2 million infor fiscal 2010,2012, which increased $9.3decreased $2.3 million compared to the prior year.
Revenues from the distribution of fuel oil and refined fuels of $135.1$114.3 million for the year ended September 25, 2010fiscal 2012 decreased $24.5$25.3 million, or 15.4%18.1%, from $159.6$139.6 million in the prior year, primarily due to lower volumes sold, partially offset by higher average selling prices.prices associated with higher wholesale product costs. Fuel oil and refined fuels gallons sold in fiscal 20102012 decreased 14.28.7 million gallons, or 24.7%23.5%, to 43.228.5 million gallons from 57.437.2 million gallons in the prior year. Lower volumes in our fuel oil and refined fuels segment were attributable to the aforementioned warmer average temperatures in the northeast region, as well as the impact of ongoing residential customer conservation driven by adverse economic conditions. Average selling prices in our fuel oil and refined fuels segment infor fiscal 20102012 increased 12.2%6.6% compared to the prior year due to higher wholesale product costs, thereby having a positive impact on revenues.
Revenues in our natural gas and electricity segment increased $0.8decreased $17.3 million, or 1.0%20.4%, to $77.6$67.4 million for the year ended September 25, 2010in fiscal 2012 compared to $76.8$84.7 million in the prior year as a result of higher electricity volumes, partially offset by lower natural gas volumes. Revenues in our all other businesses decreased 9.7%and electricity volumes sold, which was primarily attributable to $38.6 million in fiscal 2010 from $42.7 millionthe record warm weather in the prior year, primarily due to reduced installation service activities as a result of the general market decline in residential and commercial construction and other adverse economic conditions.
northeast, discussed above.
35
Percent | ||||||||||||||||
Fiscal | Fiscal | Increase/ | Increase/ | |||||||||||||
(Dollars in thousands) | 2010 | 2009 | (Decrease) | (Decrease) | ||||||||||||
Cost of products sold | ||||||||||||||||
Propane | $ | 436,825 | $ | 367,016 | $ | 69,809 | 19.0 | % | ||||||||
Fuel oil and refined fuels | 92,037 | 104,634 | (12,597 | ) | (12.0 | )% | ||||||||||
Natural gas and electricity | 57,892 | 57,216 | 676 | 1.2 | % | |||||||||||
All other | 11,697 | 11,519 | 178 | 1.5 | % | |||||||||||
Total cost of products sold | $ | 598,451 | $ | 540,385 | $ | 58,066 | 10.7 | % | ||||||||
As a percent of total revenues | 52.6 | % | 47.3 | % |
(Dollars in thousands) | Percent | |||||||||||||||
Fiscal | Fiscal | Increase/ | Increase/ | |||||||||||||
2012 | 2011 | (Decrease) | (Decrease) | |||||||||||||
Cost of products sold | ||||||||||||||||
Propane | $ | 448,120 | $ | 506,481 | $ | (58,361 | ) | (11.5 | %) | |||||||
Fuel oil and refined fuels | 91,239 | 100,908 | (9,669 | ) | (9.6 | %) | ||||||||||
Natural gas and electricity | 46,915 | 61,495 | (14,580 | ) | (23.7 | %) | ||||||||||
All other | 12,785 | 9,835 | 2,950 | 30.0 | % | |||||||||||
|
|
|
|
|
| |||||||||||
Total cost of products sold | $ | 599,059 | $ | 678,719 | $ | (79,660 | ) | (11.7 | %) | |||||||
|
|
|
|
|
| |||||||||||
As a percent of total revenues | 56.3 | % | 57.0 | % |
Average posted prices for propane for fiscal 2012 were 19.7% lower than the prior year, and average fuel oil prices for fiscal 2012 were 7.4% higher than the prior year. Total cost of products sold increased $58.1decreased $79.7 million, or 10.7%11.7%, to $598.5$599.1 million for the year ended September 25, 2010in fiscal 2012, compared to $540.4$678.7 million in the prior year due to higherlower volumes sold and lower propane average product costs, and, to a lesser extent, the unfavorable impact of non-cash mark-to-market adjustments from our risk management activities in fiscal 2010 compared to the prior year, partially offset by lower volumes sold. Average posted prices for propane andhigher fuel oil in fiscal 2010 were 46.3% and 26.1% higher, respectively, compared to the prior year. Cost of products sold in fiscal 2010 included a $5.4 million unrealized (non-cash) loss representing theaverage product costs. The net change in the fair value of derivative instruments during the period, compared to a $1.7 millionresulted in unrealized (non-cash) gaingains reported in the prior yearcost of product sold of $4.6 million and $1.4 million during fiscal 2012 and 2011, respectively, resulting in an increasea decrease of $7.1$3.2 million in cost of products sold in fiscal 20102012 compared to the prior year ($1.34.8 million decrease and $1.6 million increase in cost of products sold reported withinin the propane segment and $8.4 million increase reported within the fuel oil and refined fuels segment)segment, respectively).
Cost of products sold associated with the distribution of propane and related activities of $436.8$448.1 million for the year ended September 25, 2010 increased $69.8fiscal 2012 decreased $58.4 million, or 19.0%11.5%, compared to the prior year. HigherLower average propane product costs and lower propane volumes sold resulted in an increase of $89.2 milliona decrease in cost of products sold of $30.5 million and $23.7 million, respectively, in fiscal 2010 compared to the prior year. This increase was partially offset by lower propane volumes, which resulted in a decrease of $27.5 million in cost of products sold in fiscal 20102012 compared to the prior year. Cost of products sold from wholesale and other propane activities increased $9.4$0.6 million in fiscal 2012 compared to the prior year.
Cost of products sold associated with our fuel oil and refined fuels segment of $92.0$91.2 million for the year ended September 25, 2010fiscal 2012 decreased $12.6$9.7 million, or 12.0%9.6%, compared to the prior year primarily due to lower volumes, offset to an extent by higher product costs and the unfavorable impact of non-cash mark-to-market adjustments from our risk management activities.year. Lower fuel oil and refined fuels volumes sold resulted in a decrease of $26.2 million in cost of products sold, and higher product costs resulted in an increase of $5.2$22.6 million in cost of products sold during fiscal 20102012 compared to the prior year.
Cost of products sold in our natural gas and electricity segment of $57.9$46.9 million for the year ended September 25, 2010 increased $0.6fiscal 2012 decreased $14.6 million, or 1.2%23.7%, compared to the prior year, primarily due to higher electricity volumes, partially offset by lower natural gas volumes. and electricity volumes sold.
Cost of products sold in our all other businesses of $11.7 million was relatively flat compared to the prior year.
36
Fiscal | Fiscal | Percent | ||||||||||||||
(Dollars in thousands) | 2010 | 2009 | (Decrease) | (Decrease) | ||||||||||||
Operating expenses | $ | 289,567 | $ | 304,767 | $ | (15,200 | ) | (5.0 | )% | |||||||
As a percent of total revenues | 25.5 | % | 26.7 | % |
(Dollars in thousands) | ||||||||||||||||
Fiscal | Fiscal | Percent | ||||||||||||||
2012 | 2011 | Increase | Increase | |||||||||||||
Operating expenses | $ | 298,772 | $ | 281,329 | $ | 17,443 | 6.2 | % | ||||||||
As a percent of total revenues | 28.1 | % | 23.6 | % |
Operating expenses of $289.6$298.7 million for the year ended September 25, 2010 decreased $15.2fiscal 2012 increased $17.4 million, or 5.0%6.2%, compared to $304.8$281.3 million in the prior year as a result of lower variable compensation associated with lower earnings,the Inergy Propane Acquisition, offset to an extent by lower payroll and benefit related expenses resulting from a lower headcount and other operating efficiencies, as well as lower bad debt expense and lower insurance costs.
General and Administrative Expenses
Fiscal | Fiscal | Percent | ||||||||||||||
(Dollars in thousands) | 2010 | 2009 | Increase | Increase | ||||||||||||
General and administrative expenses | $ | 61,656 | $ | 57,044 | $ | 4,612 | 8.1 | % | ||||||||
As a percent of total revenues | 5.4 | % | 5.0 | % |
(Dollars in thousands) | ||||||||||||||||
Fiscal | Fiscal | Percent | ||||||||||||||
2012 | 2011 | Increase | Increase | |||||||||||||
General and administrative expenses | $ | 59,020 | $ | 51,648 | $ | 7,372 | 14.3 | % | ||||||||
As a percent of total revenues | 5.5 | % | 4.3 | % |
General and administrative expenses of $61.6$59.0 million for the year ended September 25, 2010fiscal 2012 increased $4.6approximately $7.4 million or 8.1%, compared to $57.0$51.6 million duringin the prior year as savingsyear. General and administrative expenses for fiscal 2012 included a $4.5 million charge associated with a legal settlement (see Item 3 and Note 12 included within the Notes to the Consolidated Financial Statements section elsewhere in this Annual Report for additional discussion), and a $2.1 million non-cash charge from a loss on disposal of an asset used in our natural gas and electricity business. General and administrative expenses for fiscal 2011 included a $2.5 million gain on sale of an asset. Excluding the impact of these items, general and administrative expenses decreased $1.8 million primarily due to lower variable compensation associated with lower earnings, offset to an extent by the addition of Inergy Propane.
Acquisition-related Costs
During fiscal 2012 we recorded acquisition-related costs of $17.9 million related to the Inergy Propane Acquisition. These costs were more than offset by an unfavorable judgment in aprimarily attributable to investment banker, legal, matteraccounting and an increase in accruals for uninsured legal matters, as well as higher advertising costs.
Depreciation and Amortization
Fiscal | Fiscal | Percent | ||||||||||||||
(Dollars in thousands) | 2010 | 2009 | Increase | Increase | ||||||||||||
Depreciation and amortization | $ | 30,834 | $ | 30,343 | $ | 491 | 1.6 | % | ||||||||
As a percent of total revenues | 2.7 | % | 2.7 | % |
(Dollars in thousands) | ||||||||||||||||
Fiscal | Fiscal | Percent | ||||||||||||||
2012 | 2011 | Increase | Increase | |||||||||||||
Depreciation and amortization | $ | 47,034 | $ | 35,628 | $ | 11,406 | 32.0 | % | ||||||||
As a percent of total revenues | 4.4 | % | 3.0 | % |
Depreciation and amortization expense of $30.8$47.0 million for the year ended September 25, 2010in fiscal 2012 increased $0.5$11.4 million, or 1.6%32.0%, compared to $30.3$35.6 million in the prior year, primarily as a result of accelerating depreciation expensetangible and intangible long-lived assets acquired in the third quarter of fiscal 2010 for certain assets retired.
Inergy Propane Acquisition.
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Fiscal | Fiscal | Percent | ||||||||||||||
(Dollars in thousands) | 2010 | 2009 | (Decrease) | (Decrease) | ||||||||||||
Interest expense, net | $ | 27,397 | $ | 38,267 | $ | (10,870 | ) | (28.4 | )% | |||||||
As a percent of total revenues | 2.4 | % | 3.3 | % |
(Dollars in thousands) | ||||||||||||||||
Fiscal | Fiscal | Percent | ||||||||||||||
2012 | 2011 | Increase | Increase | |||||||||||||
Interest expense, net | $ | 38,633 | $ | 27,378 | $ | 11,255 | 41.1 | % | ||||||||
As a percent of total revenues | 3.6 | % | 2.3 | % |
Net interest expense decreased $10.9 million, or 28.4%, to $27.4of $38.6 million for the year ended September 25, 2010,fiscal 2012 increased $11.2 million compared to $38.3$27.4 million in the prior year, primarily due to higher debt levels associated with the reduction of $183.0 million in long-term borrowings duringfinancing for the second half of fiscal 2009, coupled with a lower effective interest rate for borrowings under our revolving credit facility.Inergy Propane Acquisition. See Liquidity and Capital Resources below for additional discussion on the reduction and changesdebt issued in long-term borrowings.
Loss on Debt Extinguishment
In connection with the repurchase,execution of the amendment of our credit agreement on January 5, 2012, we recognized a loss on the extinguishmentnon-cash charge of debt$0.5 million to write-off a portion of $9.5 million in the second quarter of fiscal 2010, consisting of $7.2 million for the repurchase premium and related fees, as well as the write-off of $2.3 million in unamortized debt origination costs and unamortized discount.
Net Income and Adjusted EBITDA
We reported net income of $115.3$0.6 million, or $3.26$0.02 per Common Unit for the year ended September 25, 2010in fiscal 2012 compared to net income of $165.2$115.0 million, or $4.99$3.24 per Common Unit in the prior year. Adjusted EBITDA amounted to $192.4$108.5 million in fiscal 2012, compared to $239.2$179.4 million forin fiscal 2009.
Net income and EBITDA for fiscal 20102012 were negatively impactedaffected by certainseveral significant items, including: (i) $17.9 million in acquisition-related costs associated with the Inergy Propane Acquisition; (ii) a charge of $4.5 million associated with a legal settlement reached during the fourth quarter of fiscal 2012 included within general and administrative expenses; (iii) a loss on debt extinguishment of $9.5$2.2 million; and (iv) a $2.1 million associated with the refinancing of senior notes completed during the second quarter; (ii) a non-cash pension settlement charge of $2.8 million during the fourth quarter; and (iii) a non-cash charge from a loss on disposal of $1.8 million during the third quarter to accelerate depreciation expense on certain assets taken out of service.an asset in our natural gas and electricity business. Net income and EBITDA for fiscal 20092011 included a loss on debt extinguishment of $4.6$2.0 million charge for severance costs associated with the debt tender offer completed during the fourth quarterrealignment of fiscal 2009.
our field operations.
38
Year Ended | ||||||||
September 25, | September 26, | |||||||
(Dollars in thousands) | 2010 | 2009 | ||||||
Net income | $ | 115,316 | $ | 165,238 | ||||
Add: | ||||||||
Provision for income taxes | 1,182 | 2,486 | ||||||
Interest expense, net | 27,397 | 38,267 | ||||||
Depreciation and amortization | 30,834 | 30,343 | ||||||
EBITDA | 174,729 | 236,334 | ||||||
Unrealized (non-cash) losses (gains) on changes in fair value of derivatives | 5,400 | (1,713 | ) | |||||
Loss on debt extinguishment | 9,473 | 4,624 | ||||||
Pension settlement charge | 2,818 | — | ||||||
Adjusted EBITDA | 192,420 | 239,245 | ||||||
Add (subtract): | ||||||||
Provision for income taxes — current | (1,182 | ) | (1,101 | ) | ||||
Interest expense, net | (27,397 | ) | (38,267 | ) | ||||
Unrealized (non-cash) (losses) gains on changes in fair value of derivatives | (5,400 | ) | 1,713 | |||||
Compensation cost recognized under Restricted Unit Plans | 4,005 | 2,396 | ||||||
Loss (gain) on disposal of property, plant and equipment, net | 38 | (650 | ) | |||||
Changes in working capital and other assets and liabilities | (6,687 | ) | 43,215 | |||||
Net cash provided by operating activities | $ | 155,797 | $ | 246,551 | ||||
(Dollars in thousands) | Year Ended | |||||||
September 29, | September 24, | |||||||
2012 | 2011 | |||||||
Net income | $ | 638 | $ | 114,966 | ||||
Add: | ||||||||
Provision for income taxes | 137 | 884 | ||||||
Interest expense, net | 38,633 | 27,378 | ||||||
Depreciation and amortization | 47,034 | 35,628 | ||||||
|
|
|
| |||||
EBITDA | 86,442 | 178,856 | ||||||
Unrealized (non-cash) (gains) losses on changes in fair value of derivatives | (4,649 | ) | (1,431 | ) | ||||
Acquisition-related costs | 17,916 | — | ||||||
Loss on legal settlement | 4,500 | — | ||||||
Loss on debt extinguishment | 2,249 | — | ||||||
Loss on asset disposal | 2,078 | — | ||||||
Severance charges | — | 2,000 | ||||||
|
|
|
| |||||
Adjusted EBITDA | 108,536 | 179,425 | ||||||
Add (subtract): | ||||||||
Provision for income taxes | (137 | ) | (884 | ) | ||||
Interest expense, net | (38,633 | ) | (27,378 | ) | ||||
Unrealized (non-cash) gains (losses) on changes in fair value of derivatives | 4,649 | 1,431 | ||||||
Severance charges | — | (2,000 | ) | |||||
Acquisition-related costs | (17,916 | ) | — | |||||
Loss on legal settlement | (4,500 | ) | — | |||||
Compensation cost recognized under Restricted Unit Plans | 4,059 | 3,922 | ||||||
Gain on disposal of property, plant and equipment, net | (727 | ) | (2,772 | ) | ||||
Changes in working capital and other assets and liabilities | 55,642 | (18,958 | ) | |||||
|
|
|
| |||||
Net cash provided by operating activities | $ | 110,973 | $ | 132,786 | ||||
|
|
|
|
Liquidity and Capital Resources
Analysis of Cash Flows
Operating Activities.Net cash provided by operating activities for fiscal 20112013 amounted to $132.8$214.3 million, a decreasean increase of $23.0$103.3 million compared to the prior year. The decreaseincrease was primarily attributable to a $10.6 million decreasean increase in earnings, after adjusting for non-cash items in both periods, coupled withperiods. In addition, average posted prices for propane during fiscal 2013 decreased 19.2% compared to the prior year, which resulted in a $12.4 million increase in our investment in working capital as a result of the increase in propane and fuel oil product costs. Despite the year-over-year increasesubstantial reduction in working capital requirements we continuedyear-over-year. Also, cash flows from operating activities for fiscal 2013 benefited to fundan extent by the realization of working capital through cash on hand withoutacquired in the need to access the revolving credit facility.
Investing Activities.Net cash used in investing activities of $19.5$14.7 million for fiscal 20112013 consisted of capital expenditures of $22.3$27.8 million (including $10.2$8.3 million for maintenance expenditures and $12.1$19.5 million to support the growth of operations), partially offset by the net proceeds of $7.3 million from the sale of property, plant and equipment, and net proceeds of $5.8 million from Inergy as a result of a purchase price adjustment attributable to the working capital of Inergy Propane. Net cash used in investing activities of $239.8 million for fiscal 2012 consisted of capital expenditures of $17.5 million (including $9.3 million for maintenance expenditures and $8.2 million to support the growth of operations) and business acquisitions of $3.2$223.7 million, partially offset by the net proceeds from the sale of property, plant and equipment of $6.0$1.4 million. Net cash used in investing activities of $30.1 million for fiscal 2010 consisted of capital expenditures of $19.1 million (including $9.7 million for maintenance expenditures and $9.4 million to support the growth of operations), partially offset by the net proceeds from the sale of property, plant and equipment of $3.5 million.
39
Net cash provided by financing activities for fiscal 2012 of $113.5 million reflects $118.3the net proceeds of $259.8 million from the issuance of 7.2 million Common Units in a public offering, net of $25.2 million in debt origination costs, consisting of $10.3 million in debt origination costs associated with the amendments to our credit agreement and $14.9 million in debt origination costs associated with the issuance of new senior notes in connection with the Inergy Propane Acquisition, and $121.1 million in quarterly distributions to Unitholders at a rate of $0.83$0.8525 per Common Unit paid in respect of the fourth quarter of fiscal 2009, $0.835 per Common Unit paid in respect2011 and the first, second and third quarters of fiscal 2012. With the execution of the first quarteramendment of fiscal 2010, $0.84 per Common Unit paid in respectour credit agreement on January 5, 2012, we rolled the $100.0 million then-outstanding under the revolving credit facility of the second quarter of fiscal 2010, and $0.845 per Common Unit paid in respectprevious credit agreement into the Revolving Credit Facility (defined below) of the third quarter of fiscal 2010. In addition, financing activities for fiscal 2010 also reflectsAmended Credit Agreement (defined below). This resulted in the repurchase of $250.0 million aggregate principal amount of our 6.875% senior notes due 2013 for $256.5 million (including repurchase premiums and fees), which was substantially funded by the net proceeds of $247.8 million from the issuance of 7.375% senior notes due 2020, as well as the $5.0 million payment of debt issuance costs associated with the issuancerepayment of the 2020 senior notes.
See Summary of Long-Term Debt Obligations and Revolving Credit Lines below for additional discussion.
Equity Offering
On August 10, 2009,May 17, 2013, we sold 2,200,0002,700,000 Common Units in a public offering (the “Equity Offering”) at a price of $41.50$48.16 per Common Unit realizing proceeds of $86.7$124.7 million, net of underwriting commissions and other offering expenses. On August 24, 2009, we announced thatMay 22, 2013, following the underwriters had given notice of theirunderwriters’ exercise of their over-allotment option, in part, to acquire 230,934we sold an additional 405,000 Common Units at the Equity Offering price of $41.50$48.16 per Common Unit. NetUnit, generating additional proceeds from the over-allotment exercise amounted to $9.2 million.of $18.7 million, net of underwriting commissions. The aggregate net proceeds from the Equity Offeringoffering, including the net proceeds from the underwriters’ exercise of $95.9 milliontheir over-allotment option, were used along with cash on hand, to fund the purchase of $175.0redeem $133.4 million aggregate principal amount of our 6.875%2021 senior notes due 2013.
Summary of Long-Term Debt Obligations and Revolving Credit Lines
As of September 28, 2013, our long-term debt consisted of $496.6 million in aggregate principal amount of 7.5% senior notes due October 1, 2018, $250.0 million in aggregate principal amount of 7.375% senior notes due March 15, 2020, $346.2 million in aggregate principal amount of 7.375% senior notes due August 1, 2021 and $100.0 million under our senior secured Revolving Credit Facility.
Senior Notes
2018 Senior Notes and 2021 Senior Notes
On August 1, 2012, the Partnership and its 100%-owned subsidiary, Suburban Energy Finance Corp., issued $496.6 million in aggregate principal amount of unregistered 7.5% senior notes due October 1, 2018 (the “2018 Senior Notes”) and $503.4 million in aggregate principal amount of unregistered 7.375% senior notes due August 1, 2021 (the “2021 Senior Notes”) in a private placement in connection with the Inergy Propane Acquisition. Based on market rates for similar issues, the 2018 Senior Notes and 2021 Senior Notes were valued at 106.875% and 108.125%, respectively, of the principal amount, on the Acquisition Date as they were issued in exchange for Inergy’s outstanding notes, not for cash. The 2018 Senior Notes require semi-annual interest payments in April and October, and the 2021 Senior Notes require semi-annual interest payments in February and August.
The 2018 Senior Notes are redeemable, at our option, in whole or in part, at any time after October 1, 2014, in each case at the redemption prices described in the table below, together with any accrued and unpaid interest to the date of the redemption.
Year | Percentage | |||
2014 | 103.750 | % | ||
2015 | 101.875 | % | ||
2016 and thereafter | 100.000 | % |
The 2021 Senior Notes are redeemable, at our option, in whole or in part, at any time after August 1, 2016, in each case at the redemption prices described in the table below, together with any accrued and unpaid interest to date of the redemption.
Year | Percentage | |||
2016 | 103.688 | % | ||
2017 | 102.459 | % | ||
2018 | 101.229 | % | ||
2019 and thereafter | 100.000 | % |
On December 19, 2012, we completed an offer to exchange our existing unregistered 7.5% senior notes due 2018 and 7.375% senior notes due 2021 (the “Old Notes”) for an equal principal amount of 7.5% senior notes due 2018 and 7.375% senior notes due 2021 (the “Exchange Notes”), respectively, that have been registered under the Securities Act of 1933, as amended. The terms of the Exchange Notes are identical in all material respects (including principal, interest rate, maturity and redemption rights) to the Old Notes for which they were exchanged, except that the Exchange Notes generally will not be subject to transfer restrictions.
On August 2, 2013, we repurchased, pursuant to optional redemption, $133.4 million of our 2021 Senior Notes using net proceeds from our May 2013 public offering and net proceeds from the underwriters’ exercise of their over-allotment option to purchase additional Common Units. In addition, on August 6, 2013, we repurchased $23.9 million of our 2021 Senior Notes in a private transaction using cash on hand. In connection with these repurchases, which totaled $157.3 million in aggregate principal amount, we recognized a loss on the extinguishment of debt of $2.1 million consisting of $11.7 million for the repurchase premium and related fees, as well as the write-off of $2.1 million and ($11.7) million in unamortized debt origination costs and unamortized premium, respectively.
2020 Senior Notes
On March 23, 2010, wethe Partnership and its 100%-owned subsidiary, Suburban Energy Finance Corp., completed a public offering of $250.0 million in aggregate principal amount of 7.375% senior notes due March 15, 2020 (the “2020 Senior Notes”). The 2020 Senior Notes were issued at 99.136% of the principal amount. The net proceeds from the issuance, along with cash on hand, were used to repurchase the 6.875% senior notes due 2013 (the “2013 Senior Notes”) on March 23, 2010 through a redemption and tender offer. In connection with the repurchase of the 2013 Senior Notes, we recognized a loss on the extinguishment of debt of $9.5 million in the second quarter of fiscal 2010, consisting of $7.2 million for the repurchase premium and related fees, as well as the write-off of $2.3 million in unamortized debt origination costs and unamortized discount.
The 2020 Senior Notes are redeemable, at our option, in whole or in part, at any time after March 15, 2015, in each case at the redemption prices specifieddescribed in the indenture governingtable below, together with any accrued and unpaid interest to the notes. In addition,date of the redemption.
Year | Percentage | |||
2015 | 103.688 | % | ||
2016 | 102.459 | % | ||
2017 | 101.229 | % | ||
2018 and thereafter | 100.000 | % |
Our obligations under the 2018 Senior Notes, 2020 Senior Notes and 2021 Senior Notes (collectively, the “Senior Notes”) are unsecured and rank senior in right of payment to any future subordinated indebtedness and equally in right of payment with any future senior indebtedness. The Senior Notes are structurally subordinated to, which means they rank effectively behind, any debt and other liabilities of the Operating Partnership. The Senior Notes have a change of control provision that would require us to offer to repurchase the notes at 101% of the principal amount repurchased, if thea change of control, as defined in the indenture, occurs and is followed by a rating decline (a decrease in the rating of the notes by either Moody’s Investors Service or Standard and Poor’s Rating Group by one or more gradations) within 90 days of the consummation of the change of control.
40
Credit Agreement
The amendment to the credit agreement on January 5, 2012 amended the previous credit agreement to, among other things, extend the maturity date from June 25, 2013 to January 5, 2017, reduce the borrowing rate and commitment fees, and amend certain affirmative and negative covenants. As of January 5, 2012, our Operating Partnership had borrowings of $100.0 million outstanding under the revolving credit facility of the previous credit agreement, and rolled those borrowings into the Revolving Credit Facility of the Amended Credit Agreement. Also, at such time, our Operating Partnership had letters of credit issued under the revolving credit facility of the previous credit agreement primarily in support of retention levels under its self-insurance programs, all of which have been rolled into the Revolving Credit Facility of the Amended Credit Agreement.
On August 1, 2012, our Operating Partnership executed an amendment to the Amended Credit Agreement to, among other things, provide for (i) a $250.0 million senior secured 364-Day Facility and (ii) an increase in our revolving credit facility under the Amended Credit Agreement from $250.0 million to $400.0 million. On the Acquisition Date, our Operating Partnership drew $225.0 million on the 364-Day Facility, which was used to fund a portion of the Inergy Propane Acquisition, including costs and expenses related to the acquisition. We repaid the $225.0 million of borrowings under the 364-Day Facility on August 14, 2012 with the net proceeds from the public issuance of Common Units on August 14, 2012.
The amendment to the Amended Credit Agreement on August 1, 2012 also amended certain restrictive and affirmative covenants applicable to our Operating Partnership and to us, as well as certain financial covenants, including (a) requiring our consolidated interest coverage ratio, as defined in the amendment, to be not less than 2.0 to 1.0 as of the end of any fiscal quarter; (b) prohibiting the total consolidated leverage ratio, as defined in the amendment, of the Partnership from being greater than 7.0 to 1.0 as of the end of any fiscal quarter. The minimum consolidated interest coverage ratio increases over time, and commencing with the third quarter of fiscal 2014, such minimum ratio will be 2.5 to 1.0. The maximum consolidated leverage ratio decreases over time, as well as upon the occurrence of certain events (such as the issuance of Common Units where the net proceeds from the issuance exceed certain thresholds). Commencing with the second quarter of fiscal 2013, such maximum ratio will be 4.75 to 1.0 (or 5.0 to 1.0 during an acquisition period as defined in the amendment) as a result of the issuance of Common Units in August 2012. As of September 28, 2013 the minimum consolidated interest coverage ratio and maximum consolidated leverage ratio was 2.25 to 1.0 and 4.75 to 1.0, respectively.
We act as a guarantor with respect to the obligations of our Operating Partnership under the Amended Credit Agreement pursuant to the terms and conditions set forth therein. The obligations under the Amended Credit Agreement are secured by liens on substantially all of the personal property of the Partnership, the Operating Partnership and their subsidiaries, as well as mortgages on certain real property.
Borrowings under the Revolving Credit Facility of the Amended Credit Agreement bear interest at prevailing interest rates based upon, at ourthe Operating Partnership’s option, LIBOR plus the applicable margin or the base rate, defined as the higher of the Federal Funds Rate plus1/⁄2 of 1%, the agent bank’s prime rate, or LIBOR plus 1%, plus in each case the applicable margin. The applicable margin is dependent upon ourthe Partnership’s ratio of total debtConsolidated Total Debt to Consolidated EBITDA, on a consolidated basis, as defined in the Revolving Credit Facility. As of September 24, 2011,28, 2013, the interest rate for the Revolving Credit Facility was approximately 3.25%2.8%. The interest rate and the applicable margin will be reset at the end of each calendar quarter.
In connection with the previous revolving credit facility, the Operating Partnership entered into an interest rate swap agreement with a notional amount of $100.0 million, an effective date of March 31, 2010 and a termination date of June 25, 2013. Under the interest rate swap agreement, ourthe Operating Partnership will paypaid a fixed interest rate of 3.12% to the issuing lender on the notional principal amount outstanding, effectively fixing the LIBOR portion of the interest rate at 3.12%. In return, the issuing lender paid to the Operating Partnership a floating rate, namely LIBOR, on the same notional principal amount. The interest rate swap was designated as a cash flow hedge. In connection with the Amended Credit Agreement, our Operating Partnership entered into a forward starting interest rate swap agreement with a notional amount of $100.0 million, and effective date of June 25, 2013 and a termination date of January 5, 2017. Under this forward starting interest rate swap agreement, our Operating Partnership will pay a fixed interest rate of 1.63% to the issuing lender on the notional principal amount outstanding, and the issuing lender will pay our Operating Partnership a floating rate, namely LIBOR, on the same notional principal amount. ThisThe forward starting interest rate swap agreement replacedhas been designated as a cash flow hedge.
As of September 28, 2013, our Operating Partnership had standby letters of credit issued under the previous interest rate swap agreement which terminated on March 31, 2010.
The Amended Credit Agreement and the 2020 Senior Notes both contain various restrictive and affirmative covenants applicable to the Operating Partnership and the Partnership, respectively, including (i) restrictions on the incurrence of additional indebtedness, and (ii) restrictions on certain liens, investments, guarantees, loans, advances, payments, mergers, consolidations, distributions, sales of assets and other transactions. The RevolvingUnder the Amended Credit Facility contains certain financial covenants (a) requiringAgreement and the consolidated interest coverage ratio, as defined, atindentures governing the Partnership level to be not less than 2.5 to 1.0 as of the end of any fiscal quarter; (b) prohibiting the total consolidated leverage ratio, as defined, at the Partnership level from being greater than 4.5 to 1.0 as of the end of any fiscal quarter; and (c) prohibiting the senior secured consolidated leverage ratio, as defined, ofSenior Notes, the Operating Partnership from being greater than 3.0 to 1.0 as ofand the end of any fiscal quarter. Under the 2020 Senior Note indenture, wePartnership are generally permitted to make cash distributions equal to available cash, as defined, as of the end of the immediately preceding quarter, if no event of default exists or would exist upon making such distributions, and with respect to the Partnership’sindentures governing the Senior Notes, our consolidated fixed charge coverage ratio, as defined, is greater than 1.75 to 1. We and our Operating Partnership were in compliance with all covenants and terms of the 2020 Senior Notes and the RevolvingAmended Credit FacilityAgreement as of September 24, 2011.
Debt origination costs representing the costs incurred in connection with the placement of, and the subsequent amendment to, long-term borrowings are capitalized within other assets and amortized on a straight-line basis over the term of the respective debt agreements. During fiscal 2013, we recognized charges of $2.1 million to write-off unamortized debt origination costs associated with the repurchase of our 2021 Senior Notes. During fiscal 2012, we capitalized $14.9 million and $10.3 million for costs incurred in connection with issuance of new senior notes and the amendments to our Amended Credit Agreement, respectively. We recognized charges of $2.2 million to write-off unamortized debt origination costs associated with the amendment to our Amended Credit Agreement on January 5, 2012 and the repayment of borrowings under our 364-Day Facility. Other assets at September 28, 2013 and September 29, 2012 include debt origination costs with a net carrying amount of $21.3 million and $28.1 million, respectively.
The aggregate amounts of long-term debt maturities subsequent to September 28, 2013 are as follows: fiscal 2014 through fiscal 2016: $-0-; fiscal 2017: $100.0 million; fiscal 2018: $496.6 million; and thereafter: $596.2 million.
Partnership Distributions
We are required to make distributions in an amount equal to all of our Available Cash, as defined in the Partnership Agreement, as amended, no more than 45 days after the end of each fiscal quarter to holders of record on the applicable record dates. Available Cash, as defined in the Partnership Agreement, generally means all cash on hand at the end of the respective fiscal quarter less the amount of cash reserves established by the Board of Supervisors in its reasonable discretion for future cash requirements. These reserves are retained for the proper conduct of our business, the payment of debt principal and interest and for distributions during the next four quarters. The Board of Supervisors reviews the level of Available Cash on a quarterly basis based upon information provided by management.
On October 20, 2011,24, 2013, we announced that our Board of Supervisors had declared a quarterly distribution of $0.8525$0.8750 per Common Unit or $3.41 onfor the three months ended September 28, 2013. This quarterly distribution rate equates to an annualized basis, in respectrate of $3.50 per Common Unit, which represents a growth rate of 2.6% when compared to the annualized rate of $3.41 per Common Unit as of the fourth quarterend of fiscal 2011 payableyear 2012. The distribution was paid on November 8, 201112, 2013 to holdersCommon Unitholders of record onas of November 1, 2011.
5, 2013.
41
We have a noncontributory defined benefit pension plan which was originally designed to cover all eligible employees of the Partnership who met certain requirements as to age and length of service. Effective January 1, 1998, we amended the defined benefit pension plan to provide benefits under a cash balance formula as compared to a final average pay formula which was in effect prior to January 1, 1998. Our defined benefit pension plan was frozen to new participants effective January 1, 2000 and, in furtherance of our effort to minimize future increases in our benefit obligations, effective January 1, 2003, all future service credits were eliminated. Therefore, eligible participants will receive interest credits only toward their ultimate defined benefit under the defined benefit pension plan. There were no minimum funding requirements for the defined benefit pension plan during fiscal 2011, 20102013, 2012 or 2009.2011. As of September 24, 201128, 2013 and September 25, 201029, 2012 the plan’s projected benefit obligation exceeded the fair value of plan assets by $26.2$27.9 million and $17.7$32.0 million, respectively. As a result, the funded status ofnet liability recognized in the consolidated financial statements for the defined benefit pension plan declined $8.5decreased by $4.1 million during fiscal 2011,2013, which was primarily attributable to an increasea decrease in the present value of the benefit obligation due to a general decreaseincrease in market interest rates, partially offset by a positive returndecline in the value of plan assets as a result of investment losses during fiscal 2013. As discussed below, plan assets are largely invested in fixed income securities and, as such, an increase in market interest rates will generally result in negative returns on plan assets during fiscal 2011. The funded status of pension and other postretirement benefit plans are recognized as an asset or liability on our balance sheets and the changes in the funded status are recognized in comprehensive income (loss) in the year the changes occur.
Our investment policies and strategies, as set forth in the Investment Management Policy and Guidelines, are monitored by a Benefits Committee comprised of five members of management. The Benefits Committee employs a liability driven investment strategy, which seeks to increase the correlation of the plan’s assets and liabilities to reduce the volatility of the plan’s funded status. The execution of this strategy has resulted in an asset allocation that is largely comprised of fixed income securities. A liability driven investment strategy is intended to reduce investment risk and, over the long-term, generate returns on plan assets that largely fund the annual interest on the accumulated benefit obligation. However, as we experienced in fiscal 2011 and fiscal 2010,2012, significant declines in interest rates relevant to our benefit obligations, or poor performance in the broader capital markets in which our plan assets are invested, could have an adverse impact on the funded status of the defined benefit pension plan. For purposes of measuring the projected benefit obligation as of September 24, 201128, 2013 and September 25, 2010,29, 2012, we used a discount rate of 4.375% and 4.75%3.5%, respectively, reflecting current market rates for debt obligations of a similar duration to our pension obligations.
During fiscal 2010, lump sum settlement payments of $7.9 million exceeded the interest cost component of the net periodic pension cost. As a result, we recorded a non-cash settlement charge of $2.8 million during the fourth quarter of2013, fiscal 2010 in order to accelerate recognition of a portion of cumulative unrecognized losses in the defined benefit pension plan. These unrecognized losses were previously accumulated as a reduction to partners’ capital and were being amortized to expense as part of our net periodic pension cost. During fiscal 20112012 and fiscal 2009,2011, the amount of the pension benefit obligation settled through lump sum payments did not exceed the settlement threshold;threshold (combined service and interest costs of net periodic pension cost); therefore, a settlement charge was not required to be recognized forin either of those fiscal 2011 or fiscal 2009. Additional pension settlement charges may be required in future periods depending on the level of lump sum benefit payments made in future periods.
We also provide postretirement health care and life insurance benefits for certain retired employees. Partnership employees who were hired prior to July 1993 and retired prior to March 1998 are eligible for health care benefits if they reached a specified retirement age while working for the Partnership. Partnership employees hired prior to July 1993 are eligible for postretirement life insurance benefits if they reach a specified retirement age while working for the Partnership. Effective January 1, 2000, we terminated our postretirement health care benefit plan for all eligible employees retiring after March 1, 1998. All active and eligible employees who were to receive health care benefits under the postretirement plan subsequent to March 1, 1998 were provided an increase to their accumulated benefits under the defined benefit pension plan. Our postretirement health care and life insurance benefit plans are unfunded. Effective January 1, 2006, we changed our postretirement health care plan from a self-insured program to one that is fully insured under which we pay a portion of the insurance premium on behalf of the eligible participants.
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Contractual Obligations
The following table summarizes payments due under our known contractual obligations as of September 24, 2011.
Fiscal | ||||||||||||||||||||||||
Fiscal | Fiscal | Fiscal | Fiscal | Fiscal | 2017 and | |||||||||||||||||||
(Dollars in thousands) | 2012 | 2013 | 2014 | 2015 | 2016 | thereafter | ||||||||||||||||||
Long-term debt obligations | $ | — | $ | 100,000 | $ | — | $ | — | $ | — | $ | 250,000 | ||||||||||||
Interest payments | 25,033 | 25,033 | 18,438 | 18,438 | 18,438 | 64,531 | ||||||||||||||||||
Operating lease obligations (a) | 15,836 | 13,346 | 11,540 | 8,480 | 4,993 | 4,709 | ||||||||||||||||||
Self-insurance obligations (b) | 13,188 | 10,706 | 8,212 | 4,900 | 3,110 | 12,724 | ||||||||||||||||||
Other contractual obligations (c) | 7,870 | 4,949 | 2,431 | 1,777 | 2,255 | 18,783 | ||||||||||||||||||
Total | $ | 61,927 | $ | 154,034 | $ | 40,621 | $ | 33,595 | $ | 28,796 | $ | 350,747 | ||||||||||||
Fiscal | ||||||||||||||||||||||||
(Dollars in thousands) | Fiscal | Fiscal | Fiscal | Fiscal | Fiscal | 2019 and | ||||||||||||||||||
2014 | 2015 | 2016 | 2017 | 2018 | thereafter | |||||||||||||||||||
Long-term debt obligations | $ | — | $ | — | $ | — | $ | 100,000 | $ | 496,557 | $ | 596,180 | ||||||||||||
Interest payments | 86,356 | 86,356 | 86,356 | 82,568 | 81,210 | 122,869 | ||||||||||||||||||
Operating lease obligations (a) | 27,238 | 20,488 | 12,770 | 7,894 | 5,208 | 5,947 | ||||||||||||||||||
Self-insurance obligations (b) | 14,552 | 11,910 | 9,021 | 5,300 | 3,284 | 14,085 | ||||||||||||||||||
Other contractual obligations (c) | 5,087 | 5,702 | 5,032 | 2,465 | 2,204 | 17,450 | ||||||||||||||||||
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Total | $ | 133,233 | $ | 124,456 | $ | 113,179 | $ | 198,227 | $ | 588,463 | $ | 756,531 | ||||||||||||
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(a) | Payments exclude costs associated with insurance, taxes and maintenance, which are not material to the operating lease obligations. | |
(b) | The timing of when payments are due for our self-insurance obligations is based on estimates that may differ from when actual payments are made. In addition, the payments do not reflect amounts to be recovered from our insurance providers, which | |
(c) | These amounts are included in our consolidated balance sheet and primarily include payments for postretirement and long-term incentive |
Additionally, we have standby letters of credit in the aggregate amount of $54.9$46.7 million, in support of retention levels under our casualty insurance programs and certain lease obligations, which expire periodically through April 15, 2012.
Operating Leases
We lease certain property, plant and equipment for various periods under noncancelable operating leases, including 63%40% of our vehicle fleet, approximately 34%30% of our customer service centers and portions of our information systems equipment. Rental expense under operating leases was $18.9$33.0 million, $17.6$23.6 million and $17.3$18.9 million for fiscal 2011, 20102013, 2012 and 2009,2011, respectively. Future minimum rental commitments under noncancelable operating lease agreements as of September 24, 201128, 2013 are presented in the table above.
43
Guarantees
Certain of our operating leases, primarily those for transportation equipment with remaining lease periods scheduled to expire periodically through fiscal 2018,2020, contain residual value guarantee provisions. Under those provisions, we guarantee that the fair value of the equipment will equal or exceed the guaranteed amount upon completion of the lease period, or we will pay the lessor the difference between fair value and the guaranteed amount. Although the fair value of equipment at the end of its lease term has historically exceeded the guaranteed amounts, the maximum potential amount of aggregate future payments we could be required to make under these leasing arrangements, assuming the equipment is deemed worthless at the end of the lease term, is approximately $9.7$16.3 million. The fair value of residual value guarantees for outstanding operating leases was de minimis as of September 24, 201128, 2013 and September 25, 2010.
Recently Issued Accounting Pronouncements
In MayDecember 2011, the Financial Accounting Standards Board (“FASB”) issued an accounting standardstandards update to provide guidance on achieving a consistent definition of(“ASU”) regarding disclosures about offsetting assets and common requirements for fair value measurement and related disclosure requirements in US GAAP.liabilities (“ASU 2011-11”). The new guidance requires quantitativean entity to disclose information about unobservable inputs, valuation processesoffsetting and sensitivity analysis associatedrelated arrangements to enable users of financial statements to understand the effect of those arrangements on its financial position. The amendments, further clarified with fair value measurements categorizedASU 2013-01, will enhance disclosures by requiring improved information about financial instruments and derivative instruments that are either offset in accordance with other US GAAP or subject to an enforceable master netting arrangement or similar agreement, irrespective of whether or not they are offset in the balance sheet. The new guidance is effective for annual reporting periods beginning on or after January 1, 2013, and interim periods within Level 3those annual periods, which will be our first quarter of its 2014 fiscal year. We are currently evaluating the impact of the fair value hierarchy, andnew guidance on our future disclosures.
In February 2013, the FASB issued an ASU to establish the effective date for the requirement to present components of reclassifications out of accumulated other comprehensive income either parenthetically on the face of the financial statements or in the notes to the financial statements (“ASU 2013-02”). The guidance is effective prospectively during interim andfor annual periods beginning after December 15, 2011,2012, and interim periods within those annual periods, which will be the secondfirst quarter of our 20122014 fiscal year. Early adoption is not permitted. No material impact is expected on our consolidated financial position, results of operations and cash flows.
Commodity Price Risk
We enter into product supply contracts that are generally one-year agreements subject to annual renewal, and also purchase product on the open market. Our propane supply contracts typically provide for pricing based upon index formulas using the posted prices established at major supply points such as Mont Belvieu, Texas, or Conway, Kansas (plus transportation costs) at the time of delivery. In addition, to supplement our annual purchase requirements, we may utilize forward fixed price purchase contracts to acquire a portion of the propane that we resell to our customers, which allows us to manage our exposure to unfavorable changes in commodity prices and to ensure adequate physical supply. The percentage of contract purchases, and the amount of supply contracted for under forward contracts at fixed prices, will vary from year to year based on market conditions. In certain instances, and when market conditions are favorable, we are able to purchase product under our supply arrangements at a discount to the market.
44
Under our hedging and risk management strategies, we enter into a combination of exchange-traded futures and optionoptions contracts and, in certain instances, over-the-counter optionoptions and swap contracts (collectively, “derivative instruments”) to manage the price risk associated with physical product and with future purchases of the commodities used in our operations, principally propane and fuel oil, as well as to ensure the availability of product during periods of high demand. In addition, the Partnership sells propane and fuel oil to customers at fixed prices, and enters into derivative instruments to hedge a portion of its exposure to fluctuations in commodity prices as a result of selling the fixed price contracts. We do not use derivative instruments for speculative or trading purposes. Futures and swap contracts require that we sell or acquire propane or fuel oil at a fixed price for delivery at fixed future dates. An option contract allows, but does not require, its holder to buy or sell propane or fuel oil at a specified price during a specified time period. However, the writer of an option contract must fulfill the obligation of the option contract, should the holder choose to exercise the option. At expiration, the contracts are settled by the delivery of the product to the respective party or are settled by the payment of a net amount equal to the difference between the then market price and the fixed contract price or option exercise price. To the extent that we utilize derivative instruments to manage exposure to commodity price risk and commodity prices move adversely in relation to the contracts, we could suffer losses on those derivative instruments when settled. Conversely, if prices move favorably, we could realize gains. Under our hedging and risk management strategy, realized gains or losses on derivative instruments will typically offset losses or gains on the physical inventory once the product is sold to customers at market prices.
Futures are traded with brokers of the NYMEX and require daily cash settlements in margin accounts. Forward and option contracts are generally settled at the expiration of the contract term either by physical delivery, orand swap and options contracts are generally settled at expiration through a net settlement mechanism. Market risks associated with futures, options and forward contractsour derivative instruments are monitored daily for compliance with our Hedging and Risk Management Policy which includes volume limits for open positions. Open inventory positions are reviewed and managed daily as to exposures to changing market prices.
Credit Risk
Exchange-traded futures and optionoptions contracts are guaranteed by the NYMEX and, as a result, have minimal credit risk. We are subject to credit risk with over-the-counter forward, swap and propane optionoptions contracts to the extent the counterparties do not perform. We evaluate the financial condition of each counterparty with which we conduct business and establish credit limits to reduce exposure to the risk of non-performance by our counterparties.
Interest Rate Risk
A portion of our borrowings bear interest at prevailing interest rates based upon, at the Operating Partnership’s option, LIBOR, plus an applicable margin or the base rate, defined as the higher of the Federal Funds Rate plus1/⁄2 of 1% or the agent bank’s prime rate, or LIBOR plus 1%, plus the applicable margin. The applicable margin is dependent on the level of the Partnership’s total consolidated leverage ratio (the total ratio of consolidated total debt to consolidated EBITDA). Therefore, we are subject to interest rate risk on the variable component of the interest rate. We manage our interest rate risk by entering into interest rate swap agreements. The interest rate swaps have been designated as a cash flow hedge. Changes in the fair value of the interest rate swaps are recognized in other comprehensive income (“OCI”) until the hedged item is recognized in earnings. At September 24, 2011,28, 2013, the fair value of the interest rate swaps was $4.6a net liability of $2.4 million, representing an unrealized loss andwhich is included within other current liabilities and other liabilities, as applicable, with a corresponding debitunrealized loss reflected in OCI.
accumulated other comprehensive income.
45
All of our derivative instruments are reported on the balance sheet at their fair values. On the date that futures, forward and option contractsderivative instruments are entered into, we make a determination as to whether the derivative instrument qualifies for designation as a hedge. Changes in the fair value of derivative instruments are recorded each period in current period earnings or OCI, depending on whether a derivative instrument is designated as a hedge and, if so, the type of hedge. For derivative instruments designated as cash flow hedges, we formally assess, both at the hedge contract’s inception and on an ongoing basis, whether the hedge contract is highly effective in offsetting changes in cash flows of hedged items. Changes in the fair value of derivative instruments designated as cash flow hedges are reported in OCI to the extent effective and reclassified into earnings during the same period in which the hedged item affects earnings. The mark-to-market gains or losses on ineffective portions of cash flow hedges are immediately recognized in earnings. Changes in the fair value of derivative instruments that are not designated as cash flow hedges, and that do not meet the normal purchase and normal sale exemption, are recorded in earnings as they occur. Cash flows associated with derivative instruments are reported as operating activities within the consolidated statement of cash flows.
Sensitivity Analysis
In an effort to estimate our exposure to unfavorable market price changes in commodities related to our open positions under derivative instruments, we developed a model that incorporates the following data and assumptions:
A. | The fair value of open positions as of September |
B. | The market prices for the underlying commodities used to determine A. above were adjusted adversely by a hypothetical 10% change and compared to the fair value amounts in A. above to project the potential negative impact on earnings that would be recognized for the respective scenario. |
Based on the sensitivity analysis described above, the hypothetical 10% adverse change in market prices for open futures and option contractsderivative instruments as of September 24, 201128, 2013 indicates a reductionan increase in potential future net gainslosses of $1.1$2.2 million as of September 24, 2011.28, 2013. The above hypothetical change does not reflect the worst case scenario. Actual results may be significantly different depending on market conditions and the composition of the open position portfolio.
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Our Consolidated Financial Statements and the Report of Independent Registered Public Accounting Firm thereon listed on the accompanying Index to Financial Statements in Part IV, Item 15 (see page F-1) and the Supplemental Financial Information listed on the accompanying Index to Financial Statement Schedule in Part IV, Item 15 (see page S-1) are included herein.
Selected Quarterly Financial Data
Due to the seasonality of the retail propane, fuel oil and other refined fuel and natural gas businesses, our first and second quarter revenues and earnings are consistently greater than third and fourth quarter results. The following presents our selected quarterly financial data for the last two fiscal years (unaudited; in thousands, except per unit amounts).
First | Second | Third | Fourth | Total | ||||||||||||||||
Quarter | Quarter | Quarter | Quarter | Year | ||||||||||||||||
Fiscal 2011 | ||||||||||||||||||||
Revenues | $ | 328,307 | $ | 464,102 | $ | 216,563 | $ | 181,580 | $ | 1,190,552 | ||||||||||
Cost of products sold | 186,504 | 259,832 | 125,175 | 107,208 | 678,719 | |||||||||||||||
Severance charges | — | 2,000 | — | — | 2,000 | |||||||||||||||
Operating income (loss) | 50,341 | 107,233 | 353 | (14,699 | ) | 143,228 | ||||||||||||||
Net income (loss) | 43,129 | 100,316 | (6,787 | ) | (21,692 | ) | 114,966 | |||||||||||||
Net income (loss) per common unit — basic (b) | 1.22 | 2.82 | (0.19 | ) | (0.61 | ) | 3.24 | |||||||||||||
Net income (loss) per common unit — diluted (b) | 1.21 | 2.81 | (0.19 | ) | (0.61 | ) | 3.22 | |||||||||||||
Cash provided by (used in) | ||||||||||||||||||||
Operating activities | (4,858 | ) | 54,696 | 60,003 | 22,945 | 132,786 | ||||||||||||||
Investing activities | (6,390 | ) | (3,194 | ) | (5,285 | ) | (4,636 | ) | (19,505 | ) | ||||||||||
Financing activities | (30,062 | ) | (30,177 | ) | (30,194 | ) | (30,203 | ) | (120,636 | ) | ||||||||||
EBITDA (c) | $ | 58,521 | $ | 115,687 | $ | 10,023 | $ | (5,375 | ) | $ | 178,856 | |||||||||
Adjusted EBITDA (c) | $ | 60,094 | $ | 113,564 | $ | 10,336 | $ | (4,569 | ) | $ | 179,425 | |||||||||
Retail gallons sold | ||||||||||||||||||||
Propane | 86,286 | 114,034 | 54,629 | 43,953 | 298,902 | |||||||||||||||
Fuel oil and refined fuels | 11,393 | 16,249 | 5,621 | 3,978 | 37,241 | |||||||||||||||
Fiscal 2010 | ||||||||||||||||||||
Revenues | $ | 301,432 | $ | 469,163 | $ | 198,070 | $ | 168,029 | $ | 1,136,694 | ||||||||||
Cost of products sold | 150,366 | 248,459 | 106,627 | 92,999 | 598,451 | |||||||||||||||
Pension settlement charge | — | — | — | 2,818 | 2,818 | |||||||||||||||
Operating income (loss) | 55,757 | 114,797 | 555 | (17,741 | ) | 153,368 | ||||||||||||||
Loss on debt extinguishment (a) | — | 9,473 | — | — | 9,473 | |||||||||||||||
Net income (loss) | 48,375 | 98,388 | (6,616 | ) | (24,831 | ) | 115,316 | |||||||||||||
Net income (loss) per common unit — basic (b) | 1.37 | 2.78 | (0.19 | ) | (0.70 | ) | 3.26 | |||||||||||||
Net income (loss) per common unit — diluted (b) | 1.36 | 2.76 | (0.19 | ) | (0.70 | ) | 3.24 | |||||||||||||
Cash provided by (used in) | ||||||||||||||||||||
Operating activities | (14,726 | ) | 72,057 | 72,393 | 26,073 | 155,797 | ||||||||||||||
Investing activities | (3,663 | ) | (3,487 | ) | (13,614 | ) | (9,347 | ) | (30,111 | ) | ||||||||||
Financing activities | (29,288 | ) | (43,154 | ) | (29,665 | ) | (29,844 | ) | (131,951 | ) | ||||||||||
EBITDA (c) | $ | 62,841 | $ | 112,466 | $ | 9,423 | $ | (10,001 | ) | $ | 174,729 | |||||||||
Adjusted EBITDA (c) | $ | 66,249 | $ | 123,671 | $ | 9,142 | $ | (6,642 | ) | $ | 192,420 | |||||||||
Retail gallons sold | ||||||||||||||||||||
Propane | 89,981 | 124,457 | 56,037 | 47,431 | 317,906 | |||||||||||||||
Fuel oil and refined fuels | 13,056 | 18,381 | 6,631 | 5,128 | 43,196 |
First | Second | Third | Fourth | Total | ||||||||||||||||
Quarter | Quarter | Quarter | Quarter (a) | Year | ||||||||||||||||
Fiscal 2013 | ||||||||||||||||||||
Revenues | $ | 490,703 | $ | 678,426 | $ | 290,805 | $ | 243,672 | $ | 1,703,606 | ||||||||||
Cost of products sold | 245,100 | 346,999 | 148,176 | 121,630 | 861,905 | |||||||||||||||
Operating income (loss) | 82,308 | 153,977 | (20,654 | ) | (38,655 | ) | 176,976 | |||||||||||||
Loss on debt extinguishment (b) | — | — | — | 2,144 | 2,144 | |||||||||||||||
Net income (loss) | 57,620 | 129,484 | (45,187 | ) | (63,119 | ) | 78,798 | |||||||||||||
Net income (loss) per common unit—basic (c) | 1.05 | 2.29 | (0.77 | ) | (1.05 | ) | 1.35 | |||||||||||||
Net income (loss) per common unit—diluted (c) | 1.04 | 2.28 | (0.77 | ) | (1.05 | ) | 1.34 | |||||||||||||
Cash provided by (used in) | ||||||||||||||||||||
Operating activities | 61,537 | 72,426 | 66,505 | 13,838 | 214,306 | |||||||||||||||
Investing activities | 1,847 | (4,999 | ) | (6,532 | ) | (4,979 | ) | (14,663 | ) | |||||||||||
Financing activities | (48,605 | ) | (49,965 | ) | 93,459 | (221,617 | ) | (226,728 | ) | |||||||||||
EBITDA (d) | $ | 112,835 | $ | 185,293 | $ | 10,850 | $ | (3,762 | ) | $ | 305,216 | |||||||||
Adjusted EBITDA (d) | $ | 117,473 | $ | 190,668 | $ | 19,171 | $ | 1,941 | $ | 329,253 | ||||||||||
Retail gallons sold | ||||||||||||||||||||
Propane | 153,933 | 210,314 | 92,109 | 78,265 | 534,621 | |||||||||||||||
Fuel oil and refined fuels | 15,885 | 23,223 | 8,331 | 6,271 | 53,710 | |||||||||||||||
Fiscal 2012 | ||||||||||||||||||||
Revenues | $ | 299,886 | $ | 357,626 | $ | 179,601 | $ | 226,345 | $ | 1,063,458 | ||||||||||
Cost of products sold | 183,574 | 208,401 | 88,776 | 118,308 | 599,059 | |||||||||||||||
Operating income (loss) | 30,290 | 56,125 | (2,744 | ) | (42,014 | ) | 41,657 | |||||||||||||
Loss on debt extinguishment (b) | — | 507 | — | 1,742 | 2,249 | |||||||||||||||
Net income (loss) | 23,232 | 49,573 | (9,323 | ) | (62,844 | ) | 638 | |||||||||||||
Net income (loss) per common unit—basic (c) | 0.65 | 1.39 | (0.26 | ) | (1.32 | ) | 0.02 | |||||||||||||
Net income (loss) per common unit—diluted (c) | 0.65 | 1.38 | (0.26 | ) | (1.32 | ) | 0.02 | |||||||||||||
Cash provided by (used in) | ||||||||||||||||||||
Operating activities | (25,323 | ) | 42,371 | 56,202 | 37,723 | 110,973 | ||||||||||||||
Investing activities | (4,714 | ) | (2,775 | ) | (4,528 | ) | (227,741 | ) | (239,758 | ) | ||||||||||
Financing activities | (30,226 | ) | (32,684 | ) | (32,072 | ) | 208,531 | 113,549 | ||||||||||||
EBITDA (d) | $ | 38,075 | $ | 63,267 | $ | 5,728 | $ | (20,628 | ) | $ | 86,442 | |||||||||
Adjusted EBITDA (d) | $ | 39,123 | $ | 65,852 | $ | 3,460 | $ | 101 | $ | 108,536 | ||||||||||
Retail gallons sold | ||||||||||||||||||||
Propane | 74,279 | 89,941 | 49,014 | 70,607 | 283,841 | |||||||||||||||
Fuel oil and refined fuels | 7,695 | 10,565 | 4,314 | 5,917 | 28,491 |
(a) | The fourth quarter of fiscal 2012 includes 14 weeks of operations compared to 13 weeks in the fourth quarter for fiscal 2013. In addition, on August 1, 2012, we acquired Inergy Propane. The results of operations of Inergy Propane have been included in the consolidated results from the Acquisition Date through September 29, 2012 and all of fiscal 2013. Refer to Note 3—Acquisition of Inergy Propane included within the Notes to the Consolidated Financial Statements section elsewhere in this Annual Report. |
(b) | During the |
47
(c) | Basic net income (loss) per Common Unit is computed by dividing net income (loss) by the weighted average number of outstanding Common Units, and restricted units granted under the |
(d) | EBITDA represents net income before deducting interest expense, income taxes, depreciation and amortization. Adjusted EBITDA represents EBITDA excluding the unrealized net gain or loss from mark-to-market activity for derivative instruments |
Fiscal 2013 Net income (loss) Add: Provision for income taxes Interest expense, net Depreciation and amortization EBITDA Unrealized (non-cash) losses (gains) on changes in fair value of derivatives Integration related costs Multi-employer pension plan withdrawal charge Loss on debt extinguishment Adjusted EBITDA Add (subtract): Provision for income taxes Interest expense, net Unrealized (non-cash) (losses) gains on changes in fair value of derivatives Integration related costs Multi-employer pension plan withdrawal charge Compensation cost recognized under Restricted Unit Plans Gain on disposal of property, plant and equipment, net Changes in working capital and other assets and liabilities Net cash provided by operating activities First Second Third Fourth Total Quarter Quarter Quarter Quarter Year $ 57,620 $ 129,484 $ (45,187 ) $ (63,119 ) $ 78,798 132 150 148 177 607 24,556 24,343 24,385 22,143 95,427 30,527 31,316 31,504 37,037 130,384 112,835 185,293 10,850 (3,762 ) 305,216 3,614 2,646 73 (2,015 ) 4,318 1,024 2,729 2,248 4,574 10,575 — — 6,000 1,000 7,000 — — — 2,144 2,144 117,473 190,668 19,171 1,941 329,253 (132 ) (150 ) (148 ) (177 ) (607 ) (24,556 ) (24,343 ) (24,385 ) (22,143 ) (95,427 ) (3,614 ) (2,646 ) (73 ) 2,015 (4,318 ) (1,024 ) (2,729 ) (2,248 ) (4,574 ) (10,575 ) — — (6,000 ) (1,000 ) (7,000 ) 1,240 1,173 840 635 3,888 (2,267 ) (323 ) (301 ) (652 ) (3,543 ) (25,583 ) (89,224 ) 79,649 37,793 2,635 $ 61,537 $ 72,426 $ 66,505 $ 13,838 $ 214,306
Fiscal 2012 Net income (loss) Add: Provision for (benefit from) income taxes Interest expense, net Depreciation and amortization EBITDA Unrealized (non-cash) losses (gains) on changes in fair value of derivatives Acquisition-related costs Loss on legal settlement Loss on debt extinguishment Loss on asset disposal Adjusted EBITDA Add (subtract): (Provision for) benefit from income taxes Interest expense, net Unrealized (non-cash) (losses) gains on changes in fair value of derivatives Acquisition-related costs Loss on legal settlement Compensation cost recognized under Restricted Unit Plans Gain on disposal of property, plant and equipment, net Changes in working capital and other assets and liabilities Net cash (used in) provided by operating activities First Second Third Fourth Total Quarter Quarter Quarter Quarter Year $ 23,232 $ 49,573 $ (9,323 ) $ (62,844 ) $ 638 220 (380 ) 100 197 137 6,838 6,425 6,479 18,891 38,633 7,785 7,649 8,472 23,128 47,034 38,075 63,267 5,728 (20,628 ) 86,442 1,048 — (8,218 ) 2,521 (4,649 ) — — 5,950 11,966 17,916 — — — 4,500 4,500 — 507 — 1,742 2,249 — 2,078 — — 2,078 39,123 65,852 3,460 101 108,536 (220 ) 380 (100 ) (197 ) (137 ) (6,838 ) (6,425 ) (6,479 ) (18,891 ) (38,633 ) (1,048 ) — 8,218 (2,521 ) 4,649 — — (5,950 ) (11,966 ) (17,916 ) — — — (4,500 ) (4,500 ) 1,203 1,147 911 798 4,059 (32 ) (179 ) (35 ) (481 ) (727 ) (57,511 ) (18,404 ) 56,177 75,380 55,642 $ (25,323 ) $ 42,371 $ 56,202 $ 37,723 $ 110,973
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First | Second | Third | Fourth | Total | ||||||||||||||||
Fiscal 2011 | Quarter | Quarter | Quarter | Quarter | Year | |||||||||||||||
Net income (loss) | $ | 43,129 | $ | 100,316 | $ | (6,787 | ) | $ | (21,692 | ) | $ | 114,966 | ||||||||
Add: | ||||||||||||||||||||
Provision for income taxes | 366 | 98 | 273 | 147 | 884 | |||||||||||||||
Interest expense, net | 6,846 | 6,819 | 6,867 | 6,846 | 27,378 | |||||||||||||||
Depreciation and amortization | 8,180 | 8,454 | 9,670 | 9,324 | 35,628 | |||||||||||||||
EBITDA | 58,521 | 115,687 | 10,023 | (5,375 | ) | 178,856 | ||||||||||||||
Unrealized (non-cash) losses (gains) on changes in fair value of derivatives | 1,573 | (4,123 | ) | 313 | 806 | (1,431 | ) | |||||||||||||
Severance charges | — | 2,000 | — | — | 2,000 | |||||||||||||||
Adjusted EBITDA | 60,094 | 113,564 | 10,336 | (4,569 | ) | 179,425 | ||||||||||||||
Add (subtract): | ||||||||||||||||||||
Provision for income taxes | (366 | ) | (98 | ) | (273 | ) | (147 | ) | (884 | ) | ||||||||||
Interest expense, net | (6,846 | ) | (6,819 | ) | (6,867 | ) | (6,846 | ) | (27,378 | ) | ||||||||||
Unrealized (non-cash) (losses) gains on changes in fair value of derivatives | (1,573 | ) | 4,123 | (313 | ) | (806 | ) | 1,431 | ||||||||||||
Severance charges | — | (2,000 | ) | — | — | (2,000 | ) | |||||||||||||
Compensation cost recognized under Restricted Unit Plans | 1,332 | 1,067 | 737 | 786 | 3,922 | |||||||||||||||
(Gain) loss on disposal of property, plant and equipment, net | (299 | ) | (2,612 | ) | 67 | 72 | (2,772 | ) | ||||||||||||
Changes in working capital and other assets and liabilities | (57,200 | ) | (52,529 | ) | 56,316 | 34,455 | (18,958 | ) | ||||||||||||
Net cash (used in) provided by operating activities | $ | (4,858 | ) | $ | 54,696 | $ | 60,003 | $ | 22,945 | $ | 132,786 | |||||||||
First | Second | Third | Fourth | Total | ||||||||||||||||
Fiscal 2010 | Quarter | Quarter | Quarter | Quarter | Year | |||||||||||||||
Net income (loss) | $ | 48,375 | $ | 98,388 | $ | (6,616 | ) | $ | (24,831 | ) | $ | 115,316 | ||||||||
Add: | ||||||||||||||||||||
Provision for income taxes | 199 | 328 | 363 | 292 | 1,182 | |||||||||||||||
Interest expense, net | 7,183 | 6,608 | 6,808 | 6,798 | 27,397 | |||||||||||||||
Depreciation and amortization | 7,084 | 7,142 | 8,868 | 7,740 | 30,834 | |||||||||||||||
EBITDA | 62,841 | 112,466 | 9,423 | (10,001 | ) | 174,729 | ||||||||||||||
Unrealized (non-cash) losses (gains) on changes in fair value of derivatives | 3,408 | 1,732 | (281 | ) | 541 | 5,400 | ||||||||||||||
Loss on debt extinguishment | — | 9,473 | — | — | 9,473 | |||||||||||||||
Pension settlement charge | — | — | — | 2,818 | 2,818 | |||||||||||||||
Adjusted EBITDA | 66,249 | 123,671 | 9,142 | (6,642 | ) | 192,420 | ||||||||||||||
Add (subtract): | ||||||||||||||||||||
Provision for income taxes | (199 | ) | (328 | ) | (363 | ) | (292 | ) | (1,182 | ) | ||||||||||
Interest expense, net | (7,183 | ) | (6,608 | ) | (6,808 | ) | (6,798 | ) | (27,397 | ) | ||||||||||
Unrealized (non-cash) (losses) gains on changes in fair value of derivatives | (3,408 | ) | (1,732 | ) | 281 | (541 | ) | (5,400 | ) | |||||||||||
Compensation cost recognized under Restricted Unit Plans | 992 | 1,025 | 1,136 | 852 | 4,005 | |||||||||||||||
(Gain) loss on disposal of property, plant and equipment, net | (427 | ) | 293 | 283 | (111 | ) | 38 | |||||||||||||
Changes in working capital and other assets and liabilities | (70,750 | ) | (44,264 | ) | 68,722 | 39,605 | (6,687 | ) | ||||||||||||
Net cash (used in) provided by operating activities | $ | (14,726 | ) | $ | 72,057 | $ | 72,393 | $ | 26,073 | $ | 155,797 | |||||||||
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None.
DISCLOSURE CONTROLS AND PROCEDURES. The Partnership maintains disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934 (the “Exchange Act”)) that are designed to provide reasonable assurance that information required to be disclosed in the Partnership’s filings under the Exchange Act is recorded, processed, summarized and reported within the periods specified in the rules and forms of the SEC and that such information is accumulated and communicated to the Partnership’s management, including its principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.
Before filing this Annual Report, the Partnership completed an evaluation under the supervision and with the participation of the Partnership’s management, including the Partnership’s principal executive officer and principal financial officer, of the effectiveness of the design and operation of the Partnership’s disclosure controls and procedures as of September 24, 2011.28, 2013. Based on this evaluation, the Partnership’s principal executive officer and principal financial officer concluded that the Partnership’s disclosure controls and procedures were effective at the reasonable assurance level as of September 24, 2011.
CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING. There have not been any changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act) during the quarter ended September 24, 2011,28, 2013, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. Management’s Report on Internal Control over Financial Reporting is included below.
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING. Management of the Partnership is responsible for establishing and maintaining adequate internal control over financial reporting. The Partnership’s internal control over financial reporting is designed to provide reasonable assurance as to the reliability of the Partnership’s financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
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.
The Partnership’s management has assessed the effectiveness of the Partnership’s internal control over financial reporting as of September 24, 2011.28, 2013. In making this assessment, the Partnership used the criteria established by the Committee of Sponsoring Organizations of the Treadway Commission (COSO)(“COSO”) in “Internal Control-Integrated Framework.” These criteria are in the areas of control environment, risk assessment, control activities, information and communication, and monitoring. The Partnership’s assessment included documenting, evaluating and testing the design and operating effectiveness of its internal control over financial reporting.
Based on the Partnership’s assessment, as described above, management has concluded that, as of September 24, 2011,28, 2013, the Partnership’s internal control over financial reporting was effective.
Our independent registered public accounting firm, PricewaterhouseCoopers LLP, issued an attestation report dated November 23, 201127, 2013 on the effectiveness of our internal control over financial reporting, which is included herein.
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None.
Partnership Management
Our Partnership Agreement provides that all management powers over our business and affairs are exclusively vested in our Board of Supervisors and, subject to the direction of the Board of Supervisors, our officers. No Unitholder has any management power over our business and affairs or actual or apparent authority to enter into contracts on behalf of or otherwise to bind us. There are currently six Supervisors, who serve on the Board of Supervisors pursuant to the terms of the Partnership Agreement. Under the current Partnership Agreement, allmembers of our Board of Supervisors are elected by the Unitholders for three-year terms. All six of our current Supervisors who were serving in such capacity at the beginning of our 2013 Fiscal Year were elected to their current three-year terms at the Tri-Annual Meeting heldof our Unitholders convened on July 22, 2009.
At its regular meeting on November 13, 2012, our Board of Supervisors, pursuant to authority granted to the Board under the Partnership Agreement, increased the size of the Board from six (6) Supervisors to eight (8) Supervisors. At the same meeting and again pursuant to authority granted to the Board under the Partnership Agreement, the Board elected Messrs. Lawrence C. Caldwell and Matthew J. Chanin to fill the two vacancies on the Board created by the increase in size of the Board, effective immediately. Messrs. Caldwell and Chanin were each elected for a term due to expire at the next Tri-Annual Meeting of our Unitholders, currently scheduled for Spring 2015. At that meeting, Messrs. Caldwell and Chanin were also named to the Audit and Compensation Committees.
Seven Supervisors, who are not officers or employees of the Partnership or its subsidiaries, now serve on the Audit Committee with authority to review, at the request of the Board of Supervisors, specific matters as to which the Board of Supervisors believes there may be a conflict of interest, or which may be required to be disclosed pursuant to Item 404(a) of Regulation S-K adopted by the Securities and Exchange Commission,SEC, in order to determine if the resolution or course of action in respect of such conflict proposed by the Board of Supervisors is fair and reasonable to us. Under the Partnership Agreement, any matter that receives the “Special Approval” of the Audit Committee (i.e., approval by a majority of the members of the Audit Committee) is conclusively deemed to be fair and reasonable to us, is deemed approved by all of our partners and shall not constitute a breach of the Partnership Agreement or any duty stated or implied by law or equity as long as the material facts known to the party having the potential conflict of interest regarding that matter were disclosed to the Audit Committee at the time it gave Special Approval. The Audit Committee also assists the Board of Supervisors in fulfilling its oversight responsibilities relating to (a)(i) integrity of the Partnership’s financial statements and internal control over financial reporting; (b)(ii) the Partnership’s compliance with applicable laws, regulations and its code of conduct; (c)(iii) independence and qualifications of the independent registered public accounting firm; (d)(iv) performance of the internal audit function and the independent registered public accounting firm; and (e)(v) accounting complaints.
The Board of Supervisors has determined that all fiveseven members of the Audit Committee, Harold R. Logan, Jr., John Hoyt Stookey, Dudley C. Mecum, John D. Collins, Lawrence C. Caldwell, Matthew J. Chanin and Jane Swift are independent and (with the exception of Ms. Swift) are audit committee financial experts within the meaning of the NYSE corporate governance listing standards and in accordance with Rule 10A-3 of the Exchange Act, Item 407 of Regulation S-K and the Partnership’s criteria for Supervisor independence (as discussed in Item 13, herein) as of the date of this Annual Report.
Mr. Logan, Chairman of the Board, presides at the regularly scheduled executive sessions of the non-management Supervisors, all of whom are independent, held as part of the meetings of the Audit Committee. Investors and other parties interested in communicating directly with the non-management Supervisors as a group may do so by writing to the Non-Management Members of the Board of Supervisors, c/o Company Secretary, Suburban Propane Partners, L.P., P.O. Box 206, Whippany, New Jersey 07981-0206.
07981-0206
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The following table sets forth certain information with respect to the members of the Board of Supervisors and our executive officers as of November 23, 2011.27, 2013. Officers are appointed by the Board of Supervisors forone-year terms and Supervisors are elected by the Unitholders forthree-year terms.
Name | Age | Position With the Partnership | ||||
Michael J. Dunn, Jr. | 64 | President and Chief Executive Officer; Member of the Board of Supervisors | ||||
Michael A. Stivala | 44 | Chief Financial Officer | ||||
Michael M. Keating | 60 | Senior Vice President | ||||
A. Davin D’Ambrosio | 49 | Vice President and Treasurer | ||||
Paul Abel | 60 | Vice President, General Counsel and Secretary | ||||
Steven C. Boyd | 49 | Vice President | ||||
Douglas T. Brinkworth | 52 | Vice President | ||||
Michael Kuglin | 43 | Vice President and Chief Accounting Officer | ||||
Neil Scanlon | 48 | Vice President – Information Services | ||||
Mark Wienberg | 51 | Vice President – Operational Support and Analysis | ||||
Sandra N. Zwickel | 47 | Vice President – Human Resources | ||||
Harold R. Logan, Jr. | 69 | Member of the Board of Supervisors (Chairman) | ||||
John Hoyt Stookey | 83 | Member of the Board of Supervisors (Chairman of the Compensation Committee) | ||||
Dudley C. Mecum | 78 | Member of the Board of Supervisors | ||||
John D. Collins | 75 | Member of the Board of Supervisors (Chairman of the Audit Committee) | ||||
Jane Swift | Member of the Board of Supervisors | |||||
Lawrence C. Caldwell | 67 | Member of the Board of Supervisors | ||||
Matthew J. Chanin | 59 | Member of the Board of Supervisors |
On November 14, 2013, we announced that, pursuant to a succession plan developed by Mr. Dunn and our Board of Supervisors, Mr. Dunn will relinquish the role of President on March 31, 2014, and will retire as our Chief Executive Officer effective September 27, 2014, the last day of our 2014 fiscal year. Simultaneously, we announced that Mr. Stivala will assume the role of our President on April 1, 2014.
Mr. Dunn has served as our President since May 2005 and as our Chief Executive Officer since September 2009. From June 1998 until May 2005 he was Senior Vice President, becoming Senior Vice President — Corporate Development in November 2002. Mr. Dunn has served as a Supervisor since July 1998. From June 1998 until May 2005 he was our Senior Vice President, becoming Senior Vice President – Corporate Development in November 2002. He was our Vice President —– Procurement and Logistics from March 1997 until June 1998. Before joining the Partnership, Mr. Dunn was Vice President of Commodity Trading for the investment banking firm of Goldman Sachs & Company (“Goldman Sachs”). Mr. Dunn is the sole member of the General Partner.
Mr. Dunn’s qualifications to sit on our Board include his more than 1415 years of experience in the propane industry, including as our President for the past 68 years and Chief Executive Officer for the past 24 years, which day to day leadership roles have provided him with intimate knowledge of our operations.
Mr. Stivala has served as our Chief Financial Officer since November 2009, and, before that, as our Chief Financial Officer and Chief Accounting Officer since October 2007. Prior to that he was our Controller and Chief Accounting Officer since May 2005 and Controller since December 2001. Before joining the Partnership, he held several positions with PricewaterhouseCoopers LLP, an international accounting firm, most recently as Senior Manager in the Assurance practice. Mr. Stivala is a Certified Public Accountant and a member of the American Institute of Certified Public Accountants.
Mr. Keating has served as our Senior Vice President —– Administration since July 2009. From July 1996 to that date he was our Vice President —– Human Resources and Administration. He previously held senior human resource positions at Hanson Industries (the United States management division of Hanson plc, a global diversified industrial conglomerate) and Quantum Chemical Corporation (“Quantum”), a predecessor of the Partnership.
Mr. D’Ambrosio has served as our Treasurer since November 2002 and was additionally made a Vice President in October 2007. He served as our Assistant Treasurer from October 2000 to November 2002 and as Director of Treasury Services from January 1998 to October 2000. Mr. D’Ambrosio joined the Partnership in May 1996 after ten years in the commercial banking industry.
Mr. Abel has served as our General Counsel and Secretary since June 2006 and was additionally made a Vice President in October 2007. From May 2005 until June 2006, Mr. Abel was Assistant General Counsel of Velocita Wireless, L.P., the owner and operator of a nationwide wireless data network. From 1998 until May 2005, Mr. Abel was Vice President, Secretary and General Counsel of AXS-One Inc. (formerly known as Computron Software, Inc.), an international business software company.
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Mr. Brinkworth has served as our Vice President —– Product Supply (formerly Vice President —– Supply) since May 2005. Mr. Brinkworth joined the Partnership in April 1997 after a nine year career with Goldman Sachs and, since joining the Partnership, has served in various positions in the product supply area.
Mr. Kuglin has served as our Vice President and Chief Accounting Officer since November 2011. Prior to that he was our Controller and Chief Accounting Officer since November 2009 and Controller since October 2007. For the eight years prior to joining the Partnership he held several financial and managerial positions with Alcatel-Lucent, a global communications solutions provider. Prior to Alcatel-Lucent, Mr. Kuglin held several positions with the international accounting firm PricewaterhouseCoopers LLP, most recently Manager in the Assurance practice. Mr. Kuglin is a Certified Public Accountant and a member of the American Institute of Certified Public Accountants.
Mr. Scanlon became our Vice President – Information Services in November 2008. Prior to that he served as our Assistant Vice President – Information Services since November 2007, Managing Director – Information Services from November 2002 to November 2007 and Director – Information Services from April 1997 until November 2002. Prior to joining the Partnership, Mr. Scanlon spent several years with JP Morgan & Co., most recently as Vice President – Corporate Systems and earlier held several positions with Andersen Consulting, an international systems consulting firm, most recently as Manager.
Mr. Wienberg has served as our Vice President – Operational Support and Analysis (formerly Vice President – Operational Planning) since October 2007. Prior to that he served as our Managing Director, Financial Planning and Analysis from October 2003 to October 2007 and as Director, Financial Planning and Analysis from July 2001 to October 2003. Prior to joining the Partnership, Mr. Wienberg was Assistant Vice President – Finance of International Home Foods Corp., a consumer products manufacturer.
Ms. Zwickel has served as our Vice President – Human Resources since November 2013. Prior to that, she was our Assistant Vice President – Human Resources since April 2011 and earlier held several roles in the Partnership’s Legal Department (including Assistant General Counsel from October 2009 to April 2011 and Counsel from October 2002 to October 2009), where she was responsible for, among other things, providing legal counsel on employment issues. Ms. Zwickel joined the Partnership in June 1999 after eight years in the private practice of law.
Mr. Logan has served as a Supervisor since March 1996 and was elected as Chairman of the Board of Supervisors in January 2007. Mr. Logan is a Co-Founder and, from 2006 to the present has been serving as a Director, of Basic Materials and Services LLC, an investment company that has invested in companies that provide specialized infrastructure services and materials for the pipeline construction industry and the sand/silica industry. From 2003 to September 2006, Mr. Logan was a Director and Chairman of the Finance Committee of the Board of Directors of TransMontaigne Inc., which provided logistical services (i.e. pipeline, terminaling and marketing) to producers and end-users of refined petroleum products. From 1995 to 2002, Mr. Logan was Executive Vice President/Finance, Treasurer and a Director of TransMontaigne Inc. From 1987 to 1995, Mr. Logan served as Senior Vice President of Finance and a Director of Associated Natural Gas Corporation, an independent gatherer and marketer of natural gas, natural gas liquids and crude oil. Mr. Logan is also a Director of Cimarex Energy Co., Graphic Packaging Holding Company and Hart Energy Publishing LLP, and, until it was sold in 2007, served as a Director of The Houston Exploration Company.
Over the past 40 years, Mr. Logan’s education, investment banking/venture capital experience and business/financial management experience have provided him with a comprehensive understanding of business and finance. Most of Mr. Logan’s business experience has been in the energy industry, both in investment banking and as a senior financial officer and director of publicly-owned energy companies. Mr. Logan’s expertise and experience have been relevant to his responsibilities of providing oversight and advice to the managements of public companies, and is of particular benefit in his role as our Chairman. Since 1996, Mr. Logan has been a director of nine public companies and has served on audit, compensation and governance committees.
53
Mr. Stookey’s qualifications to sit on our Board include his extensive experience as Chief Executive Officer of 4four corporations (including a predecessor of the Partnership) and his many years of service as a director of publicly-owned corporations and non-profit organizations.
Mr. Mecum has served as a Supervisor since June 1996. He has beenwas a Managing Director of Capricorn Holdings, LLC (a sponsor of and investor in leveraged buyouts) since June 1997. Mr. Mecum wasfrom 1997 to 2011 and a partner of G.L. Ohrstrom & Co. (a sponsor of and investor in leveraged buyouts) from 1989 to June 1996. Until 2007, Mr. Mecum was a director of Citigroup, Inc.
Mr. Mecum’s qualifications to sit on our Board include his 20 years in public accounting, rising to the level of Vice Chairman of KPMG LLP, a public accounting firm, his service as Assistant Secretary of the Army for Installations and Logistics and his 15 years of service overseeing or managing various companies. Mr. Mecum has over 20 years of service as a director of various publicly-owned companies.
Mr. Collins has served as a Supervisor since April 2007. He served with KPMG LLP, an international accounting firm, from 1962 until 2000, most recently as senior audit partner of its New York office. He has served as a United States representative on the International Auditing Procedures Committee, a committee of international accountants responsible for establishing international auditing standards. Mr. Collins is a Director of Montpelier Re and, Mrs. Fields Original Cookies, Inc. and, until recently, was a Director of Columbia Atlantic Funds.
Mr. Collins’ qualifications to sit on our Board, and serve as Chairman of its Audit Committee, include his 40 years of experience in public accounting, including 31 years as a partner supervising the audits of public companies. Mr. Collins has served on a number of AICPA and international accounting and auditing standards bodies.
Ms. Swift has served as a Supervisor since April 2007. She is currently the CEO of Middlebury Interactive Languages, LLC, a marketer of world language products. From 2010 through July 2011, Ms. Swift served as Senior Vice President of ConnectEDU Inc., a private education technology company. In 2007, she founded WNP Consulting, LLC, a provider of expert advice and guidance to early stage education companies. From 2003 to 2006 she was a General Partner at Arcadia Partners, a venture capital firm focused on the education industry. She has previously served on the boards of K12, Inc. and Animated Speech Company and currently serves on the boards of Sally Ride Science Inc. and several not-for-profit boards, including the National Alliance for Public Charter Schools and The Republican Majority for Choice and Landmark Volunteers, Inc.Young Writers Project. Prior to joining Arcadia, Ms. Swift served for 15 years in Massachusetts state government, becoming Massachusetts’ first woman governor in 2001.
Ms. Swift’s qualifications to sit on our Board include her strong skills in public policy and government relations and her extensive knowledge of regulatory matters arising from her 15 years in state government.
54
Mr. Chanin has served as a Supervisor since November 2012. He was Senior Managing Director of Prudential Investment Management, a subsidiary of Prudential Financial, Inc., from 1996 until his retirement in January, 2012. He headed the firm’s private fixed income business, chaired an internal committee responsible for strategic investing and was a principal in Prudential Capital Partners, the firm’s mezzanine investment business. He currently serves as a Director of three private companies that are in Prudential Capital Partners funds’ portfolios, and provides consulting services to Prudential and one other client.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Exchange Act requires our Supervisors, executive officers and holders of ten percent or more of our Common Units to file initial reports of ownership and reports of changes in ownership of our Common Units with the SEC. Supervisors, executive officers and ten percent Unitholders are required to furnish the Partnership with copies of all Section 16(a) forms that they file. Based on a review of these filings, we believe that all such filings were timely made during fiscal 2011.
Codes of Ethics and of Business Conduct
We have adopted a Code of Ethics that applies to our principal executive officer, principal financial officer and principal accounting officer, and a Code of Business Conduct that applies to all of our employees, officers and Supervisors. A copy of our Code of Ethics and our Code of Business Conduct is available without charge from our website atwww.suburbanpropane.com or upon written request directed to: Suburban Propane Partners, L.P., Investor Relations, P.O. Box 206, Whippany, New Jersey 07981-0206. Any amendments to, or waivers from, provisions of our Code of Ethics or our Code of Business Conduct that apply to our principal executive officer, principal financial officer and principal accounting officer will be posted on our website.
Corporate Governance Guidelines
We have adopted Corporate Governance Guidelines and Policies in accordance with the NYSE corporate governance listing standards in effect as of the date of this Annual Report. A copy of our Corporate Governance Guidelines is available without charge from our website atwww.suburbanpropane.com or upon written request directed to: Suburban Propane Partners, L.P., Investor Relations, P.O. Box 206, Whippany, New Jersey 07981-0206.
Audit Committee Charter
We have adopted a written Audit Committee Charter in accordance with the NYSE corporate governance listing standards in effect as of the date of this Annual Report. The Audit Committee Charter is reviewed periodically to ensure that it meets all applicable legal and NYSE listing requirements. A copy of our Audit Committee Charter is available without charge from our website atwww.suburbanpropane.com or upon written request directed to: Suburban Propane Partners, L.P., Investor Relations, P.O. Box 206, Whippany, New Jersey 07981-0206.
Compensation Committee Charter
Seven Supervisors, who are not officers or employees of the Partnership or its subsidiaries, serve on the Compensation Committee. The Board of Supervisors has determined that all seven members of the Compensation Committee, Harold R. Logan, Jr., John Hoyt Stookey, Dudley C. Mecum, John D. Collins, Jane Swift, Lawrence C. Caldwell and Matthew J. Chanin are independent. We have adopted a Compensation Committee Charter in accordance with the NYSE corporate governance listing standards in effect as of the date of this Annual Report. A copy of our Compensation Committee Charter is available without charge from our website atwww.suburbanpropane.com or upon written request directed to: Suburban Propane Partners, L.P., Investor Relations, P.O. Box 206, Whippany, New Jersey 07981-0206.
During fiscal 2013, the Compensation Committee independently retained Towers Watson, a compensation consultant, to assist the Compensation Committee in its review and development of a new performance metric under our Long-Term Incentive Plan.
NYSE Annual CEO Certification
The NYSE requires the Chief Executive Officer of each listed company to submit a certification indicating that the company is not in violation of the Corporate Governance listing standards of the NYSE on an annual basis. Mr. Dunn submits his Annual CEO Certification to the NYSE each December. In December 2012, Mr. Dunn submitted his Annual CEO Certification for our 2011 fiscal year to the NYSE without qualification.
55
Compensation Discussion and Analysis
This Compensation Discussion and Analysis explains our executive compensation philosophy, policies and practices with respect to the following executive officers of Suburban, which we refer to as the Partnership (the “named executive officers”): theMr. Dunn, our President and Chief Executive Officer, theOfficer; Mr. Stivala, our Chief Financial OfficerOfficer; and the other three most highly compensated executive officers.
Executive Compensation Philosophy and Components
The objectives of our executive compensation program are as follows:
The alignment of the short-term and long-term interests of our executive officers with the short-term and long-term interests of our Unitholders. |
We accomplish these objectives by providing our executives with compensation packages that combine various components that are specifically linked to either short-term or long-term performance measures. Therefore, our executive compensation packages are designed to achieve our overall goal of sustainable, profitable growth by rewarding our executive officers for behaviors that facilitate our achievement of this goal.
The principal components of the compensation we provide to our named executive officers are as follows:
Cash incentives paid under a performance-based annual bonus plan; | |||
We align the short-term and long-term interests of our executive officers with the short-term and long-term interests of our Unitholders by:
Providing a long-term incentive plan that encourages our executive officers to implement activities and practices conducive to sustainable, profitable growth; and | |||
Establishing Executive Compensation
The Compensation Committee, (the “Committee”)which we hereafter refer to as the “Committee,” is responsible for overseeing our executive compensation program. In accordance with its charter, available on our website atwww.suburbanpropane.com, the Committee ensures that the compensation packages provided to our executive officers are designed in accordance with our compensation philosophy. The Committee reviews and approves the compensation packages of our managing directors, assistant vice presidents, vice presidents, senior vice presidents, and our named executive officers.
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The benchmarking data provided to the Committee for the 2011 fiscal year 2013 was derived from the Mercer Human Resource Consulting, Inc. (“Mercer”) Benchmark Database containing information obtained from surveys of over 2,2692,543 organizations and approximately 201209 positions which may or may not include similarly-sized national propane marketers. The Committee does not base its benchmarking solely on a peer group of other propane marketers. The use of the Mercer database provides a broad base of compensation benchmarking information for companies of a similar size to the Partnership.Suburban. The benchmarking information used by the Committee consisted of organizations included in the Mercer database that report median annual revenues of between $1.4$1.1 billion and $3.8$4.2 billion per year.
In making their decisions regarding executive compensation packages for the coming fiscal year, the members of the Committee review the total cash compensation opportunities that were provided to our executive officers during the just completed fiscal year. Each executive officer’s “total cash compensation opportunity” consists of base salary, an annual cash bonus, and 2003 Long-Term Incentive Plan awards. The Committee then compares each executive officer’s total cash compensation opportunity to the total mean cash compensation opportunity for the parallel position in the Mercer database. By focusing on each executive officer’s total cash compensation opportunity as a whole, instead of on single components of compensation such as base salary, when it met on November 9, 2010,13, 2012, the Committee created fiscal 20112013 compensation packages for our executive officers that emphasized the performance-based components of compensation.
The Committee does not base its benchmarking solely on a peer group of other propane marketers, as the Committee believes that the proximity of Suburban’s headquarters to New York City and the need to realistically compete for skilled executives in an environment shared by numerous other enterprises that seek similarly skilled employees requires a broader review of the market. The Committee chooses not to base its benchmarking on the compensation practices of other propane marketers due to the fact that the other, similarly-sized propane marketers compete for executives in vastly different economic environments.
As previously reported, at their fiscal 2012 Tri-Annual Meeting, our Unitholders overwhelmingly approved the advisory “Say-on-Pay” resolution required by Section 14A of the Exchange Act. As a result, the Committee determined that no major revisions of its practices are required; however, the Committee has, and will continue to, periodically evaluate its compensation practices for possible improvement.
Role of Executive Officers and the Compensation Committee in the Compensation Process
The Committee establishes and enforces our general compensation philosophy in consultation with our President and Chief Executive Officer. The role of our President and Chief Executive Officer in the executive compensation process is to recommend individual pay adjustments for the executive officers, other than himself, to the Committee based on market conditions, our performance, and individual performance. With the assistance of our Senior Vice President of Administration, our President and Chief Executive Officer presents the Committee with information comparing each executive officer’s compensation to the mean compensation figures provided in the Mercer database.
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Among other duties, the Committee has overall responsibility for:
Reporting to the Board of Supervisors any and all decisions regarding compensation changes for our President and Chief Executive Officer, Chief Financial Officer and our other executive officers; | |||
Allocation Among Components
Under our compensation structure, the mix of base salary, cash bonus and long-term compensation provided to each executive officer varies depending on his or her position. The base salary for each executive officer is the only fixed component of compensation. All other cash compensation, including annual cash bonuses and long-term incentive compensation, is variable in nature as it is dependent upon achievement of certain performance measures. The following table summarizes the components as percentages of each named executive officer’s total cash compensation opportunity in fiscal 20112013 (as determined at the Committee’s November 9, 201013, 2012 meeting).
Cash | Long-Term | |||||||||||
Base Salary | Bonus Target | Incentive | ||||||||||
Michael J. Dunn, Jr. | 40 | % | 40 | % | 20 | % | ||||||
Michael A. Stivala | 45 | % | 36 | % | 19 | % | ||||||
Steven C. Boyd | 45 | % | 36 | % | 19 | % | ||||||
Mark Wienberg | 45 | % | 36 | % | 19 | % | ||||||
Douglas T. Brinkworth | 45 | % | 36 | % | 19 | % |
Cash | Long-Term | |||||
Base Salary | Bonus Target | Incentive | ||||
Michael J. Dunn, Jr. | 40% | 40% | 20% | |||
Michael A. Stivala | 45% | 36% | 19% | |||
Steven C. Boyd | 45% | 36% | 19% | |||
Mark Wienberg | 45% | 36% | 19% | |||
Douglas T. Brinkworth | 45% | 36% | 19% |
In allocating compensation among these components, we believe that the compensation of our senior-most levels of management — management—the levels of management having the greatest ability to influence our performance — performance—should be at least 50% performance-based, while lower levels of management should receive a greater portion of their compensation in base salary. Additionally, our short-term and long-term incentive plans are pay-for-performance compensation plans that do not provide for minimum payments and are, thus, truly pay-for-performance compensation plans.
Internal Pay Equity
In determining the different compensation packages for each of our named executive officers, the Committee takes into consideration a number of factors, including the level of responsibility and influence that each named executive officer has over the affairs of the Partnership, tenure with the Partnership,Suburban, individual performance and years of experience in his or her current position. The relative importance assigned to each of these factors by the Committee may differ from executive to executive. The Committee will also consider the existing level of equity ownership of each of our named executive officers when granting awards under our Restricted Unit Plans (see below for a description of these plans). As a result, different weights may be given to different components of compensation among each of our named executive officers. In addition, as discussed in the section above titled “Allocation Among Components,” the compensation packages that we provide to our senior-most levels of management are, at a minimum, 50% performance-based. In order to align the interests of senior management with the interests of our Unitholders, we consider it requisite to accentuate the performance-based elements of the compensation packages that we provide to these individuals.
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Base salaries for the named executive officers and all of our other executive officers, are reviewed and approved annually by the Committee. In order to determine base salary increases, the Committee’s practice is to compare each executive officer’s base salary with the corresponding mean salary provided in the Mercer database. The Committee usually determines base salary adjustments, which may be higher or lower than the comparative data, following an assessment of our overall results as well as each executive officer’s position, performance and scope of responsibility, while at the same time considering each executive officer’s previous total cash compensation opportunities. In accordance with this process and the philosophy described above, and in consideration of the increased responsibilities assumed by our named executive officers as a result of the Inergy Propane Acquisition, at its meeting on November 13, 2012, the Committee did not adjustmade the following adjustments to the base salaries of theour named executive officers duringfor fiscal 2011; instead, the Committee decided to increase each of the bonus target percentages of each of the named executive officers (with the exception of Mr. Dunn’s, whose bonus target percentage was already at 100%). The Committee reasoned that this action would further align the interests of management with the interests of our Unitholders. 2013:
Name | Fiscal 2013 Base Salary | Fiscal 2012 Base Salary | ||||||
Michael J. Dunn, Jr. | $ | 495,000 | $ | 475,000 | ||||
Michael A. Stivala | $ | 300,000 | $ | 275,000 | ||||
Steven C. Boyd | $ | 290,000 | $ | 270,000 | ||||
Mark Wienberg | $ | 280,000 | $ | 250,000 | ||||
Douglas T. Brinkworth | $ | 270,000 | $ | 245,000 |
In the event of a promotion, a significant increase in an executive officer’s responsibilities, or a new hire, it is the Committee’s practice to review that executive officer’s base salary at that time and take such action as the Committee deems warranted.
The total base salary paid to each named executive officer in fiscal 2013, fiscal 2012 and fiscal 2011 is reported in the column titled “Salary ($)”“Salary” in the Summary Compensation Table below.
Annual Cash Bonus Plan
Annual cash bonuses (which fall within the SEC’sSecurities and Exchange Commission’s definition of “Non-Equity Incentive Plan Compensation” for the purposes of the Summary Compensation Table and otherwise) are earned by our executive officers in accordance with the objective performance provisions of our annual cash bonus plan.
The terms of our annual cash bonus plan provide for cash payments of a specified percentage (which, in fiscal 2011,2013, ranged from 80% to 100%) of our named executive officers’ annual base salaries (“target cash bonus”) if, for the fiscal year, actual cash bonus plan EBITDA equals the Partnership’sSuburban’s budgeted EBITDA. For purposes of calculating cash bonus plan EBITDA, the Committee customarily adjusts both budgeted and actual EBITDA (as defined in Item 6 in this annual report on Form 10-K) for various items considered to be non-recurring in nature; including, but not limited to, unrealized (non-cash) gains or losses on changes in the fair value of derivative instruments reported within cost of products sold in our statement of operationsinstruments; acquisition-related costs; integration-related costs; multiemployer pension plan withdrawal charges; pension settlement charges; and gains or losses on the disposal of discontinued operations.debt extinguishment. Under the previous annual cash bonus plan, executive officers had the opportunity to earn between 90% and 110% of their target cash bonuses; however, beginning with fiscal 2011,our executive officers have the opportunity to earn between 60% and 120% of their target cash bonuses, depending upon the Partnership’sSuburban’s EBITDA performance in the fiscal year. Under the existing annual cash bonus plan,year; no bonuses are earned if actual cash bonus plan EBITDA is less than 90% of budgeted cash bonus plan EBITDA, and cash bonuses cannot exceed 120% of the target cash bonus even if actual cash bonus plan EBITDA is more than 120% of budgeted cash bonus plan EBITDA.
Although our annual cash bonus plan is generally administered using the formula described above, the Committee may exercise its broad discretionary powers to decrease or increase the annual cash bonus paid to a particular executive officer, upon the recommendation of our President and Chief Executive Officer, or the executive officers as a group, when the Committee recognizes that an adjustment is warranted. During fiscal 2011,2013, fiscal 20102012 and fiscal 2009,2011, no such discretionary adjustments were made to the annual cash bonuses earned by our executives.
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Hypothetical Fiscal 2011 | ||||||||||
Cash Bonus Plan EBITDA | Target Bonus Percentage that | |||||||||
Hypothetical Fiscal 2011 | Expressed as a | would have been Earned if | ||||||||
Cash Bonus Plan EBITDA | Percentage of | Actual Cash Bonus Plan | ||||||||
Results | Budgeted Cash Bonus Plan | EBITDA Equaled the Figure | ||||||||
(in Millions) | EBITDA | in the First Column | ||||||||
$ | 234.0 | 120 | % | 120 | % | |||||
$ | 214.5 | 110 | % | 110 | % | |||||
$ | 195.0 | (1) | 100 | % | 100 | % | ||||
$ | 185.3 | 95 | % | 90 | % | |||||
$ | 175.5 | 90 | % | 60 | % |
Hypothetical Fiscal 2013 Cash Bonus Plan EBITDA Results (in Millions) | Hypothetical Fiscal 2013 Cash Bonus Plan EBITDA Expressed as a Percentage of Budgeted Cash Bonus Plan EBITDA | Target Bonus Percentage that would have been Earned if Actual Cash Bonus Plan EBITDA Equaled the Figure in the First Column | ||
$438.0 | 120% | 120% | ||
$401.5 | 110% | 110% | ||
$365.0(1) | 100% | 100% | ||
$346.8 | 95% | 90% | ||
$328.5 | 90% | 60% |
(1) | Budgeted cash bonus plan EBITDA for fiscal |
The fiscal 20112013 target cash bonus percentages and target cash bonuses established for each named executive officer and the actual cash bonuses earned by each of them during fiscal 20112013 are summarized as follows:
2011 Target Cash | ||||||||||||
Bonus as a % of | 2011 Target Cash | 2011 Actual Cash | ||||||||||
Name | Base Salary | Bonus | Bonus Earned | |||||||||
Michael J. Dunn, Jr. | 100 | % | $ | 475,000 | $ | 285,000 | ||||||
Michael A. Stivala | 80 | % | $ | 220,000 | $ | 132,000 | ||||||
Steven C. Boyd | 80 | % | $ | 216,000 | $ | 129,600 | ||||||
Mark Wienberg | 80 | % | $ | 200,000 | $ | 120,000 | ||||||
Douglas T. Brinkworth | 80 | % | $ | 196,000 | $ | 117,600 |
Name | 2013 Target Cash Bonus as a % of Base Salary | 2013 Target Cash Bonus | 2013 Actual Cash Bonus Earned at 60% | |||||||
Michael J. Dunn, Jr. | 100% | $ | 495,000 | $ | 297,000 | |||||
Michael A. Stivala | 80% | $ | 240,000 | $ | 144,000 | |||||
Steven C. Boyd | 80% | $ | 232,000 | $ | 139,200 | |||||
Mark Wienberg | 80% | $ | 224,000 | $ | 134,400 | |||||
Douglas T. Brinkworth | 80% | $ | 216,000 | $ | 129,600 |
For purposes of establishing the cash bonus targets for fiscal 2011,2013, the Committee reviewed and approved our fiscal 20112013 budgeted cash bonus plan EBITDA at its November 9, 201013, 2012 meeting. The budgeted cash bonus plan EBITDA is developed annually using a bottom-up process factoring in reasonable growth targets from the prior year’s performance, while at the same time attempting to reach a good balance between a target that is reasonably achievable, yet not assured. As described above, executive officers have the opportunity to earn between 60% and 120% of their target cash bonuses. Over the past three years, our actual cash bonus plan EBITDA was such that each of our executive officers earned 60%, 100%,0% and 110%60% of their respective target cash bonus for fiscal 2011,2013, fiscal 20102012 and fiscal 2009,2011, respectively.
The named executive officers’ target cash bonus percentages and target cash bonuses for fiscal 2014 are the same as those for fiscal 2013. Actual payments for fiscal 2014 under the annual cash bonus plan will depend upon the percentage of the budgeted cash bonus plan EBITDA for fiscal 2014 that is eventually achieved. The budgeted cash bonus plan EBITDA for fiscal 2014 was established using the same bottom-up process described above.
The bonuses earned under the annual cash bonus plan for fiscal 2013 and 2011 by each of our named executive officers are reported in the column titled “Non-Equity Incentive Plan Compensation” in the Summary Compensation Table below.
Long-Term Incentive Plan
While the annual cash bonus plan is a pay-for-performance plan that focuses on our short-term financial goals, the Long-Term Incentive Plans (which we collectively refer to as the “LTIP”) are structured as a LTIP isunit plan that has been designed to motivate our executive officers to focus on our long-term financial goals. Unvested awards are granted at the beginning of each fiscal year as a Committee-approved percentage of each executive officer’s salary. Cash payouts, if any, are earned and paid at the end of a three-year measurement period, depending on performance.
The LTIP measuresis designed to:
LTIP History
At the beginning of fiscal 2003, the Committee adopted the 2003 Long-Term Incentive Plan (the “2003 LTIP”) as a principal component of our executive compensation program. At its meeting on November 9, 2011, the Committee adopted the 2013 Long-Term Incentive Plan (the “2013 LTIP”) as a replacement for the 2003 Long-Term Incentive Plan, which expired on September 30, 2012. The 2013 LTIP became effective on October 1, 2012; its provisions were essentially identical to the provisions of the 2003 LTIP. At its meeting on August 6, 2013, the Committee adopted the 2014 Long-Term Incentive Plan (the “2014 LTIP”) as a replacement for the 2013 LTIP. The provisions of the 2014 LTIP govern all LTIP awards granted subsequent to fiscal 2013.
Calculation of LTIP Units
In accordance with the 2003, 2013, and 2014 LTIP documents, at the beginning of each three-fiscal year measurement period, each executive officer’s number of unvested LTIP unit awards is calculated by dividing a predetermined percentage (52% for awards made prior to fiscal 2014 and 50% for all subsequent awards), established by the Committee, of the executive officer’s target cash bonus by the average of the closing prices of our Common Units for the twenty days preceding the beginning of the first fiscal year in the measurement period.
The following are the numbers of the unvested LTIP units granted to our named executive officers during fiscal 2013 and fiscal 2012 that will be used to calculate cash payments at the end of each award’s respective three-year measurement period (i.e., at the end of fiscal 2015 for the fiscal 2013 award and at the end of fiscal 2014 for the fiscal 2012 award):
Fiscal | Fiscal | |||||||
2013 Award | 2012 Award | |||||||
Michael J. Dunn, Jr. | 6,559 | 5,258 | ||||||
Michael A. Stivala | 3,180 | 2,435 | ||||||
Steven C. Boyd | 3,074 | 2,391 | ||||||
Mark Wienberg | 2,968 | 2,214 | ||||||
Douglas T. Brinkworth | 2,862 | 2,169 |
At its meeting on November 13, 2013, the Committee approved the grant of the following number of unvested LTIP unit awards under the LTIP for the fiscal 2014 award cycle that commenced at the beginning of fiscal 2014 and will conclude at the end of fiscal 2016 that will be used to calculate cash payments at the end of this award’s three-year measurement period (i.e., at the end of fiscal 2016).
Fiscal | ||||
2014 Award | ||||
Michael J. Dunn, Jr. | 5,404 | |||
Michael A. Stivala | 2,620 | |||
Steven C. Boyd | 2,533 | |||
Mark Wienberg | 2,445 | |||
Douglas T. Brinkworth | 2,358 |
Performance Metrics
The primary difference between the 2003/2013 LTIPs and the 2014 LTIP is the performance metric used to determine whether cash payouts have been earned by the participants at the end of an LTIP award cycle’s three-year measurement period.
Awards made prior to fiscal 2014 under the 2003 and 2013 LTIPs measure the market performance of our Common Units on the basis of total return to our Unitholders, (“TRU”)which we refer to as “TRU,” during a three-year measurement period commencing on the first day of the fiscal year in which an unvested award was granted and compares our TRU to the TRU of each of the other members of a predetermined peer group, consisting solely of other master limited partnerships, approved by the Committee.
The predeterminedmembers of the peer groups selected by the Committee for the fiscal 2013, fiscal 2012 and fiscal 2011 awards consist entirely of publicly-traded partnerships. The Committee decided upon these peer groups because all publicly-traded partnerships have similar tax attributes and can, as a result, distribute more cash than similarly-sized corporations generating similar revenues. At its November 13, 2012 meeting, the Committee approved modifications to the peer group may vary from year-to-year, but for all outstanding awards, includes AmeriGas Partners, L.P., Ferrellgas Partners, L.P. and Inergy, L.P. (the other propane master limited partnerships). Unvested awards are granted atin response to significant changes in the beginningcapital structure of each fiscal yearseveral members of the previous peer group, including that of Suburban as a Committee-approved percentageresult of each executive officer’s salary. Cash payouts, if any, are earnedthe Inergy Propane Acquisition. In choosing this new peer group, the Committee particularly considered the market capitalization and paid atrelative similarities in capital structure between the endpeer group members and Suburban.
The following tables list, in alphabetical order, the names and ticker symbols of the peer group used to measure our performance during the three-year measurement period.
Fiscal 2012 and Fiscal 2011 Awards Peer Group
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Peer Group Member Name | Ticker Symbol | ||
AmeriGas Partners, L.P. | |||
Copano Energy, LLC(1) | |||
Dorchester Minerals, L.P. | |||
Enbridge Energy Partners, L.P. | EEP | ||
Energy Transfer Partners, L.P. | ETP | ||
Ferrellgas Partners, L.P. | FGP | ||
Global Partners, L.P. | GLP | ||
Inergy, L.P. (2) | NRGY | ||
MarkWest Energy Partners, L.P. | MWE | ||
Plains All American Pipeline, L.P. | PAA | ||
Sunoco Logistics Partners, L.P. | SXL | ||
Fiscal 2013 Award Peer Group | |||
Peer Group Member Name | Ticker Symbol | ||
Atlas Pipeline Partners, L.P. | APL | ||
AmeriGas Partners, L.P. | APU | ||
BreitBurn Energy Partners, L.P. | BBEP | ||
Copano Energy, LLC (1) | CPNO | ||
Enbridge Energy Partners, L.P. | EEP | ||
Ferrellgas Partners, L.P. | FGP | ||
Genesis Energy, L.P. | GEL | ||
Global Partners L.P. | GLP | ||
Inergy Midstream, L.P. (2) | NRGM | ||
MarkWest Energy Partners, L.P. | MWE | ||
TC Pipelines, L.P. | TCP |
(1) | Copano Energy, LLC was acquired by Kinder Morgan Energy Partners, L.P. on May 1, 2013. For purposes of measuring relative TRU for the fiscal 2011 award, we used Copano’s final closing price, prior to the consummation of the acquisition by Kinder Morgan, in place of an end-of-year twenty-day average. For purposes of measuring relative TRU for the fiscal 2013 and fiscal 2012 awards, as a |
(2) | Inergy Midstream, L.P. merged with Crestwood Midstream Partners LP on October 7, 2013. The combined partnership is named Crestwood Midstream Partners LP and |
The three-year measurement period of the fiscal 2011 award ended simultaneously with the conclusion of fiscal 2013. The TRU for the fiscal 2011 award fell within the lowest quartile; therefore, the participants, including our named executive officers, did not earn cash payouts relative to this award.
Subsequent to the Committee’s meeting on November 13, 2012, the Committee reconsidered the use of TRU as the performance metric for purposes of the LTIP. As a result, the Committee engaged the services of Towers Watson to review the LTIP’s measurement criteria. At the Committee’s July 24, 2013 meeting, Towers Watson presented the Committee with a recommendation to replace TRU with a performance metric that measures our average distribution coverage ratio over a three-year measurement period.
The Committee’s decision to replace the 2013 LTIP with the 2014 LTIP was based on its determination that an incentive structure focused on the level of distributable cash flow over a three-year measurement period, which supports the sustainability of the cash distributions to Unitholders and future growth in distributions, is a more meaningful indicator of the Partnership’s performance than comparative TRU, and also better aligns management’s interests with those of the Unitholders.
As a result of the Committee’s adoption of the 2014 LTIP, the earning of payments under the 2014 LTIP will be determined based on the level our distribution coverage ratio over a three-year measurement period. This ratio will be calculated by dividing our average distributable cash flow generated during an outstanding award’s three-year measurement period by a baseline cash flow set on the initial grant date of the award.
The average distributable cash flow is the average of the distributable cash flow for each of the three years in a particular award’s three-year measurement period. For purposes of this plan’s performance metric, distributable cash flow is equal to adjusted EBITDA for a particular fiscal year less capital expenditures, cash interest expense, and the provision for income taxes for the same fiscal year. For LTIP purposes, “adjusted EBITDA” is identical to cash bonus plan EBITDA. The average distributable cash flow will be adjusted by the sum of the annual differences between the per-Common Unit annualized distribution rate at the beginning of the three-year measurement period and the actual per-Common Unit distributions paid during each executive officer’s unvested award of phantom unitsthe three years in an award’s three-year measurement period. Baseline cash flow is calculated by dividing a predetermined percentage (i.e., 52%), established upon adoptionmultiplying the total number of the LTIP, of the executive officer’s target cash bonus by the average of the closing prices of our Common Units for the twenty days precedingoutstanding at the beginning of the three-year measurement period by the then per Common Unit annualized distribution rate.
Cash Payments
For awards granted under the 2003 and 2013 LTIP plan documents (i.e., the fiscal year. At2013, the fiscal 2012, and the fiscal 2011 awards), at the end of the three-year measurement period, depending on the quartile ranking within which our TRU falls relative to the other members of the peer group, our executive officers, as well as the other participants, all of whom are key employees, will receive a cash payout equal to:
The quantity of the participant’s LTIP units multiplied by the sum of the distributions that would have inured to one of our outstanding Common Units during the three-year measurement period; and The sum of the products of the two preceding calculations multiplied by: zero if our performance falls within the lowest quartile of the peer group; 50% if our performance falls within the second lowest quartile; 100% if our performance falls |
For awards granted under the 2014 plan document (the first of the cash payouts related towhich will be the fiscal 20092014 award, earned by our named executive officerspayable, if at the conclusion of fiscal 2011.
Michael J. Dunn, Jr. | $ | 350,057 | (1) | |
Michael A. Stivala | $ | 160,609 | (1) | |
Steven C. Boyd | $ | 160,609 | (1) | |
Mark Wienberg | $ | 123,962 | (1) | |
Douglas T. Brinkworth | $ | 139,008 | (1) |
Fiscal | Fiscal | |||||||
2011 Award | 2010 Award | |||||||
Michael J. Dunn, Jr. | 4,787 | 5,981 | ||||||
Michael A. Stivala | 2,217 | 2,597 | ||||||
Steven C. Boyd | 2,177 | 2,550 | ||||||
Mark Wienberg | 2,016 | 2,203 | ||||||
Douglas T. Brinkworth | 1,975 | 2,314 |
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Distribution Coverage Ratio | % of Unvested LTIP Units That Will Vest | |||
Less than 1.00 | 00.0 | % | ||
1.00 (Threshold Performance) | 50.0 | % | ||
1.01 | 52.5 | % | ||
1.02 | 55.0 | % | ||
1.03 | 57.5 | % | ||
1.04 | 60.0 | % | ||
1.05 | 62.5 | % | ||
1.06 | 65.0 | % | ||
1.07 | 67.5 | % | ||
1.08 | 70.0 | % | ||
1.09 | 72.5 | % | ||
1.10 | 75.0 | % | ||
1.11 | 77.5 | % | ||
1.12 | 80.0 | % | ||
1.13 | 82.5 | % | ||
1.14 | 85.0 | % | ||
1.15 | 87.5 | % | ||
1.16 | 90.0 | % | ||
1.17 | 92.5 | % | ||
1.18 | 95.0 | % | ||
1.19 | 97.5 | % | ||
1.20 (Target Performance) | 100.0 | % | ||
1.21 | 101.7 | % | ||
1.22 | 103.3 | % | ||
1.23 | 105.0 | % | ||
1.24 | 106.7 | % | ||
1.25 | 108.4 | % | ||
1.26 | 110.0 | % | ||
1.27 | 111.7 | % | ||
1.28 | 113.4 | % | ||
1.29 | 115.0 | % | ||
1.30 | 116.7 | % | ||
1.31 | 118.4 | % | ||
1.32 | 120.0 | % | ||
1.33 | 121.7 | % | ||
1.34 | 123.4 | % | ||
1.35 | 125.1 | % | ||
1.36 | 126.7 | % | ||
1.37 | 128.4 | % | ||
1.38 | 130.1 | % | ||
1.39 | 131.7 | % | ||
1.40 | 133.4 | % | ||
1.41 | 135.1 | % | ||
1.42 | 136.7 | % | ||
1.43 | 138.4 | % | ||
1.44 | 140.1 | % | ||
1.45 | 141.8 | % | ||
1.46 | 143.4 | % | ||
1.47 | 145.1 | % | ||
1.48 | 146.8 | % | ||
1.49 | 148.4 | % | ||
1.50 and Higher (Maximum Performance) | 150.0 | % |
Retirement Provision
A retirement-eligible participant’s outstanding awards under the LTIP will vest as of the retirement-eligible date, but such awardswill remain subject to the same three-year measurement period for purposes of determining the eventual cash payout, if any, at the conclusion of the measurement period.
The grant date values based on the probable outcomes of the awards under the LTIP awards granted during the fiscal year2013, fiscal 2012 and fiscal 2011 are reported in the column titled “Unit Awards ($)”Awards” in the Summary Compensation Table below.
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We adopted the 2000 Restricted Unit Plan effective November 1, 2000. Upon adoption, this plan authorized the issuance of 487,805 Common Units to our executive officers, managers and other employees and to the members of our Board of Supervisors. On October 17, 2006, following approval by our Unitholders, we adopted amendments to this plan which, among other things, increased the number of Common Units authorized for issuance under this plan by 230,000 for a total of 717,805. As this plan terminated by its terms on October 31, 2010, no future awards can be made under this plan; however such termination will not affect the continued validity of any awards granted under the plan prior to its termination.
At our July 22, 2009 Tri-Annual Meeting, our Unitholders approved our adoption of the 2009 Restricted Unit Plan effective August 1, 2009. Upon adoption, this plan authorized the issuance of 1,200,000 Common Units to our executive officers, managers and other employees and to the members of our Board of Supervisors. The provisions of both restricted unit plans are substantially identical. At the conclusion of fiscal 2011,2013, there remained 967,594668,860 restricted units available under the RUP for future awards.
When the Committee authorizes an award of restricted units, the unvested units underlying an award do not provide the grantee with voting rights and do not receive distributions or accrue rights to distributions during the vesting period. Restricted unit awards granted prior to August 6, 2013 normally vest as follows: 25% on each of the third and fourth anniversaries of the grant date and the remaining 50% on the fifth anniversary of the grant date. At its August 6, 2013 meeting, the Committee amended the Partnership’s 2009 Restricted Unit Plan to revise the normative vesting schedule of awards granted thereafter to 33.33% on each of the first three anniversaries of the award grant date. The Committee retained the ability to deviate, at its discretion, from the normal vesting schedule with respect to particular restricted unit awards. The Committee amended the plan to make its vesting schedule comparable to those of similar plans offered by other companies. Unvested awards are subject to forfeiture in certain circumstances as defined in the applicable RUP document. Upon vesting, restricted units are automatically converted into our Common Units, with full voting rights and rights to receive distributions.
The RUP contains a retirement provision that provides for the vesting (six months and one day after the retirement date of qualifying participants) of unvested awards held by a retiring participant who meetmeets all three of the following conditions on his or her retirement date:
The grantee is age 55 or older; and | |||
All RUP awards are approved by the Committee. Because individual circumstances differ, the Committee has not adopted a formulaic approach to making RUP awards. Although the reasons for granting an award can vary, the objective of granting an award to a recipient is to retain the services of the recipient over the five-year vesting period while, at the same time providing the type of motivation that further aligns the long-term interests of the recipient with the long-term interests of our Unitholders. The reasons for which the Committee grants RUP awards include, but are not limited to, the following:
To attract skilled and capable candidates to fill vacant positions; | |||
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The total cash compensation opportunity provided to the executive officer or key employee for whom the award is being considered; | |||
In addition, in establishing the level of restricted units to grant to our executive officers, the Committee considers the existing level of outstanding unvested RUP awards held by our executive officers.
The Committee generally approves awards under the RUP at its first meeting each fiscal year following the availability of the financial results for the prior fiscal year; however, occasionally the Committee grants awards at other times of the year, particularly when the need arises to grant awards because of promotions and new hires.
During fiscal 2013, the Committee adopted a general policy with respectdetermined grants of RUP awards to the effective grant datenamed executive officers would further align the interests of subsequent awardsmanagement with the interests of restricted units underour Unitholders and approved the RUP which states that:
Grant Name | ||||||||||
Date | Quantity | |||||||||
Michael A. Stivala | November 15, 2012 | 8,432 | ||||||||
Steven C. Boyd | November 15, 2012 | 8,432 | ||||||||
Mark Wienberg | ||||||||||
Douglas T. Brinkworth | ||||||||||
In determining the fiscal 20112013 awards for Mr. Stivala, Mr. Boyd, Mr. Wienberg and Mr. Brinkworth, the Committee relied upon information provided by the Mercer database to conclude that these awards were necessary to remediate shortfalls perceived by the Committee in the cash compensation opportunities of these named executive officers, as well as in recognition of their individual achievements.
The aggregate grant date fair values of RUP awards made during the fiscal year2013, fiscal 2012 and fiscal 2011, computed in accordance with accounting principles generally accepted in the United States of America isare reported in the column titled “Unit Awards ($)”Awards” in the Summary Compensation Table below.
For fiscal 2014, at its meeting on November 13, 2013, the Committee granted the following RUP awards to our named executive officers:
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Grant Name | Date | Quantity | ||||||||
Michael A. Stivala | November 15, 2013 | 5,302 | ||||||||
Steven C. Boyd | November 15, 2013 | 5,302 | ||||||||
Mark Wienberg | November 15, 2013 | 5,302 | ||||||||
Douglas T. Brinkworth | November 15, 2013 | 5,302 |
No award was granted to our Chief Executive Officer at this meeting because of the level of remaining unvested RUP awards that were previously granted in connection with the execution of the letter agreement with Mr. Dunn. See section entitled “Letter Agreement of Mr. Dunn” below.
Effective April 22, 2010, the Committee adopted an Equity Holding Policy which establishes guidelines for the level of Partnership equity holdings that members of the Board and our executivesexecutive officers are expected to maintain. The Equity Holding Policy can be accessed through a link on the Partnership’sSuburban’s website atwww.suburbanpropane.com under the “Investors” tab.
Suburban’s equity holding requirements are as follows:
Position | Amount | |||||
Member of the Board of Supervisors | 2 | x Annual Fee | ||||
Chief Executive Officer | 5 | x Base Salary | ||||
President | 5 | x Base Salary | ||||
Chief Operating Officer | 3 | x Base Salary | ||||
Chief Financial Officer | 3 | x Base Salary | ||||
Executive Vice President | 3 | x Base Salary | ||||
Senior Vice President | 2.5 | x Base Salary | ||||
Vice President | 1.5 | x Base Salary | ||||
Assistant Vice President | 1 | x Base Salary | ||||
Managing Director | 1 | x Base Salary |
As of the January 3, 20112, 2013 measurement date, all of our executive officers, including our named executive officers, were in compliance with the Partnership’sSuburban’s Equity Holding Policy.
Incentive Compensation Recoupment Policy
Upon recommendation by the Committee, the Board of Supervisors approvedhas adopted an Incentive Compensation Recoupment Policy which permits the Committee to seek the reimbursement from certain executives of Suburban and the Partnership and Operating Partnership of incentive compensation (i.e., payments/awards pursuant to the annual cash bonus plan, the LTIP and RUP) paid to those executives in connection with any fiscal year for which there is a significant restatement of the published financial statements of the PartnershipSuburban triggered by a material accounting error, which results in less favorable results than those originally reported by the Partnership.Suburban. Such reimbursement can be sought from executives even if they had no responsibility for the restatement. In addition to the foregoing, if the Committee determines that any fraud or intentional misconduct by an executive was a contributing factor to the PartnershipSuburban having to make a significant restatement, then the Committee is authorized to take appropriate action against such executive, including disciplinary action, up to, and including, termination, and requiring reimbursement of all, or any part, of the compensation paid to that executive in excess of that executive’s base salary, including cancellation of any unvested restricted units. The Incentive Compensation Recoupment Policy is available on our website atwww.suburbanpropane.com under the “Investors” tab.
Pension Plan
We sponsor a noncontributory defined benefit pension plan that was originally designed to cover all of our eligible employees who met certain criteria relative to age and length of service. Effective January 1, 1998, we amended the plan in order to provide for a cash balance format rather than the final average pay format that was in effect prior to January 1, 1998. The cash balance format is designed to evenly spread the growth of a participant’s earned retirement benefit throughout his or her career rather than the final average pay format, under which a greater portion of a participant’s benefits were earned toward the latter stages of his or her career. Effective January 1, 2000, we amended the plan to limit participation in this plan to existing participants and no longer admit new participants to the plan. On January 1, 2003, we amended the plan to cease future service and pay-based credits on behalf of the participants and, from that point on, participants’ benefits have increased only due to interest credits.
Each of our named executive officers, with the exception of Mr. Stivala and Mr. Wienberg, participates in the plan. The changes in the actuarial value relative to each named executive officer’s participation in the plan isduring fiscal 2013, fiscal 2012 and fiscal 2011 are reported in the column titled “Change in Pension Value and Nonqualified Deferred Compensation Earnings ($)”Earnings” in the Summary Compensation Table below.
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All employees, including the named executive officers, who satisfy certain service requirements, are entitled to participate in our IRC Section 401(k) Plan, (thewhich we refer to as the “401(k) Plan”),Plan,” in which participants may defer a portion of their eligible cash compensation up to the limits established by law. We offer the 401(k) Plan to attract and retain talented employees by providing them with a tax-advantaged opportunity to save for retirement.
For fiscal 2011,2013, all of our named executive officers participated in the 401(k) Plan. The benefits provided to our named executive officers under the 401(k) Plan are provided on the same basis as to our other exempt employees. Amounts deferred by our named executive officers under the 401(k) Plan during fiscal 2013, fiscal 2012 and fiscal 2011 are included in the column titled “Salary ($)”“Salary” in the Summary Compensation Table below.
In order to be competitive with other employers, if certain performance criteria are met, we will match our employee-participants’ contributions up to the lesser of 6% of their base salary or $245,000,$255,000, at a rate determined based on a performance-based scale. The following chart shows the performance target criteria that must be met for each level of matching contribution:
If We Meet This Percentage of Budgeted EBITDA(1) | The Participating Employee | |||
Will Receive this Matching | ||||
Contribution for the Year | ||||
115% or higher | 100 | % | ||
100% to 114% | 50 | % | ||
90% to 99% | 25 | % | ||
Less than 90% | 0 | % |
(1) | For |
Actual cash bonus plan EBITDA, when applied to the 401(k) Plan EBITDAplan, was $195.0 million. Based on actual fiscal 2011such that we provided participants in the 401(k) Plan EBITDA results, each of our executive officers earnedplan with a matching contribution of 25%. As a result, we will provide participants with a match equal to 25% of their calendar year 20112013 contributions that did not exceed 6% of their total base pay, up to a maximum base payannual compensation limit of $245,000.$255,000. The matching contributions that we will makemade on behalf of our named executive officers for 2013 are reported in the column titled “All Other Compensation ($)”Compensation” in the Summary Compensation Table below.
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As part of his total compensation package, each named executive officer is eligible to participate in all of our other employee benefit plans, such as the medical, dental, group life insurance and disability plans, on the same basis as other exempt employees. These benefit plans are offered to attract and retain talented employees by providing them with competitive benefits.
Other than to Mr. Dunn, in accordance with the terms of his letter agreement (described below in the section titled “Letter Agreement of Mr. Dunn”), there are no post-termination or other special rights provided to any named executive officer to participate in these benefit programs other than the right to participate in such plans for a fixed period of time following termination of employment, on the same basis as is provided to other exempt employees, as required by law.
The costs of all such benefits incurred on behalf of our named executive officers in fiscal 2013, fiscal 2012 and fiscal 2011 are reported in the column titled “All Other Compensation ($)”Compensation” in the Summary Compensation Table below.
Perquisites
Perquisites represent a minor component of our executive officers’ compensation. Each of the named executive officers is eligible for tax preparation services, a company-provided vehicle, and an annual physical. The following table summarizes both the value and the utilization of these perquisites by the named executive officers in fiscal 2011.
Employer- | ||||||||||||
Tax Preparation | Provided | |||||||||||
Name | Services | Vehicle | Physical | |||||||||
Michael J. Dunn, Jr. | $ | 7,700 | $ | 16,302 | $ | 1,300 | ||||||
Michael A. Stivala | $ | -0- | $ | 14,698 | $ | -0- | ||||||
Steven C. Boyd | $ | 7,200 | $ | 7,221 | $ | -0- | ||||||
Mark Wienberg | $ | -0- | $ | 11,970 | $ | 1,300 | ||||||
Douglas T. Brinkworth | $ | 5,100 | $ | 10,851 | $ | 1,300 |
Name | Tax Preparation Services | Employer- Provided Vehicle | Physical | |||||||||
Michael J. Dunn, Jr. | $ | 8,950 | $ | 18,897 | $ | 1,750 | ||||||
Michael A. Stivala | $ | -0- | $ | 19,319 | $ | 1,750 | ||||||
Steven C. Boyd | $ | 2,650 | $ | 7,705 | $ | -0- | ||||||
Mark Wienberg | $ | -0- | $ | 13,570 | $ | 1,500 | ||||||
Douglas T. Brinkworth | $ | 4,050 | $ | 11,521 | $ | 1,750 |
Perquisite-related costs for fiscal 2013, fiscal 2012 and fiscal 2011 are reported in the column titled “All Other Compensation ($)”Compensation” in the Summary Compensation Table below.
Impact of Accounting and Tax Treatments of Executive Compensation
As we are a partnership and not a corporation for federal income tax purposes, we are not subject to the limitations of IRC Section 162(m) with respect to tax deductible executive compensation. Accordingly, none of the compensation paid to our named executive officers is subject to a limitation as to tax deductibility. However, if such tax laws related to executive compensation change in the future, the Committee will consider the implication of such changes to us.
Although it is the Partnership’sSuburban’s practice to comply with the statutory and regulatory provisions of IRC Section 409A, on November 2, 2005, the Board of Supervisors approved an amendment to the Suburban Propane, L.P. Severance Protection Plan for Key Employees, (thewhich we refer to as the “Severance Plan”) to providePlan,” provides that if any payment under the Severance Plan subjects a participant to the 20% federal exciseadditional tax under IRC Section 409A, the payment will be grossed up to permit such participant to retain a net amount on an after-tax basis equal to what he or she would have received had the excise tax not been payable.
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Simultaneous with the commencement of fiscal 2010, Mr. Dunn’s then existing employment agreement was terminated by mutual agreement and replaced with a letter agreement governing retirement and the implementation of a mutually agreed upon succession plan. The letter agreement between Mr. Dunn and us is summarized as follows:
We also agreed that if there was a termination of Mr. Dunn’s employment in connection with a succession plan, it would be deemed a retirement for the purposes of his benefits under the employee benefit plans in which he participates. Mr. Dunn also agreed to provide us with transition consultation services for a period not to exceed two years following his departure. We also agreed that Mr. Dunn willwould not be deemed to have retired or terminated his employment if he simply relinquishesrelinquished the title and responsibilities of President but remainsremained our Chief Executive Officer.
On November 14, 2013, we announced that, pursuant to a succession plan developed by Mr. Dunn and our Board of Supervisors, Mr. Dunn will relinquish the role of President on March 31, 2014, and will retire as our Chief Executive Officer effective September 27, 2014, the last day of our 2014 fiscal year. Accordingly, the retirement provisions of our letter agreement with Mr. Dunn will become effective on September 28, 2014, at which time Mr. Dunn will be age 65.
Also on November 14, 2013, we announced that Mr. Stivala will assume the role of our President on April 1, 2014. Mr. Stivala’s compensation in his new role has not yet been established.
Severance Benefits
We believe that, in most cases, employees should be paid reasonable severance benefits. Therefore, it is the general policy of the Committee to provide executive officers and other key employees who are terminated by us without cause or who choose to terminate their employment with us for good reason with a severance payment equal to, at a minimum, one year’s base salary, unless circumstances dictate otherwise. This policy was adopted because it may be difficult for former executive officers and other key employees to find comparable employment within a short period of time. However, depending upon individual facts and circumstances, particularly the severed employee’s tenure with us, the Committee may make exceptions to this general policy.
A “key employee” is an employee who has attained a director level pay-grade or higher. “Cause” will be deemed to exist where the individual has been convicted of a crime involving moral turpitude, has stolen from us, has violated his or her non-competition or confidentiality obligations, or has been grossly negligent in fulfillment of his or her responsibilities. “Good reason” generally will exist where an executive officer’s position or compensation has been decreased or where the employee has been required to relocate.
Change of Control
Our executive officers and other key employees have built the PartnershipSuburban into the successful enterprise that it is today; therefore, we believe that it is important to protect them in the event of a change of control. Further, it is our belief that the interests of our Unitholders will be best served if the interests of our executive officers are aligned with them, and that providing change of control benefits should eliminate, or at least reduce, the reluctance of our executive officers to pursue potential change of control transactions that may be in the best interests of our Unitholders. Additionally, we believe that the severance benefits provided to our executive officers and to our key employees are consistent with market practice and appropriate because these benefits are an inducement to accepting employment and because the executive officers have agreed to and are subject to non-competition and non-solicitation covenants for a period following termination of employment. Therefore, our executive officers and other key employees are provided with employment protection following a change of control, (thewhich we refer to as the “Severance Protection Plan”). During fiscal 2011,2013, our Severance Protection Plan covered all executive officers, including the named executive officers.
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In addition, upon a change of control, without regard to whether a participant’s employment is terminated, all unvested awards granted under the RUP will vest immediately and become distributable to the participants andparticipants. Also, without regard to whether a participant’s employment is terminated, all outstanding, unvested LTIP awards will vest immediately as if the three-year measurement period for each outstanding award concluded on the date the change of control occurred and our TRU was such that, in relationoccurred. Under the provisions of the LTIP document, an amount equal to the performancecash value of 125% of a participant’s unvested LTIP units plus a sum equal to 125% of a participant’s unvested LTIP units multiplied by an amount equal to the other memberscumulative, per-Common Unit distribution from the beginning of an unvested award’s three-year measurement period through the peer group, it fell withindate on which a change of control occurred would become payable to the top quartile.
For purposes of these benefits, a change of control is deemed to occur, in general, if:
For additional information pertaining to severance payable to our named executive officers following a change of control-related termination, see the tables titled “Potential Payments Upon Termination” below.
Report of the Compensation Committee
The Compensation Committee has reviewed and discussed with management this Compensation Discussion and Analysis. Based on its review and discussions with management, the Committee recommended to the Board of Supervisors that this Compensation Discussion and Analysis be included in this Annual Report on Form 10-K for fiscal 2011.
The Compensation Committee:
John Hoyt Stookey, Chairman
Lawrence C. Caldwell
Matthew J. Chanin
John D. Collins
Harold R. Logan, Jr.
Dudley C. Mecum
Jane Swift
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Summary Compensation Table for Fiscal 2011
The following table sets forth certain information concerning the compensation of each named executive officer during the fiscal years ended September 24, 2011,28, 2013, September 25, 2010,29, 2012, and September 26, 2009:
Change in | ||||||||||||||||||||||||||||||||
Pension Value | ||||||||||||||||||||||||||||||||
and | ||||||||||||||||||||||||||||||||
Nonqualified | ||||||||||||||||||||||||||||||||
Non-Equity | Deferred | |||||||||||||||||||||||||||||||
Unit | Incentive | Compensation | All Other | |||||||||||||||||||||||||||||
Name and Principal | Salary | Bonus | Awards | Plan Compen- | Earnings | Compensation | Total | |||||||||||||||||||||||||
Position | Year | ($)(1) | ($) | ($)(2) | sation ($)(3) | ($)(4) | ($)(5) | ($) | ||||||||||||||||||||||||
(a) | (b) | (c ) | (d) | (e) | (g) | (h) | (i) | (j) | ||||||||||||||||||||||||
Michael J. Dunn, Jr. | 2011 | $ | 475,000 | — | $ | 729,076 | $ | 285,000 | $ | 3,764 | $ | 49,530 | $ | 1,542,370 | ||||||||||||||||||
President and Chief | 2010 | $ | 475,000 | — | $ | 768,484 | $ | 475,000 | $ | 31,661 | $ | 49,330 | $ | 1,799,475 | ||||||||||||||||||
Executive Officer | 2009 | $ | 433,333 | — | $ | 314,197 | $ | 467,500 | $ | 56,050 | $ | 48,065 | $ | 1,319,145 | ||||||||||||||||||
Michael A. Stivala | 2011 | $ | 275,000 | — | $ | 357,103 | $ | 132,000 | — | $ | 35,010 | $ | 799,113 | |||||||||||||||||||
Chief Financial Officer | 2010 | $ | 275,000 | — | $ | 320,699 | $ | 206,250 | — | $ | 37,569 | $ | 839,518 | |||||||||||||||||||
2009 | $ | 262,500 | — | $ | 231,333 | $ | 214,500 | — | $ | 41,728 | $ | 750,061 | ||||||||||||||||||||
Steven C. Boyd | 2011 | $ | 270,000 | — | $ | 354,615 | $ | 129,600 | $ | 15,257 | $ | 37,095 | $ | 806,567 | ||||||||||||||||||
Vice President of | 2010 | $ | 270,000 | — | $ | 317,799 | $ | 202,500 | $ | 21,101 | $ | 34,762 | $ | 846,162 | ||||||||||||||||||
Field Operations | 2009 | $ | 260,000 | — | $ | 190,660 | $ | 214,500 | $ | 53,577 | $ | 39,811 | $ | 758,548 | ||||||||||||||||||
Mark Wienberg | 2011 | $ | 250,000 | — | $ | 344,653 | $ | 120,000 | — | $ | 33,725 | $ | 748,378 | |||||||||||||||||||
Vice President of | 2010 | $ | 250,000 | — | $ | 273,398 | $ | 175,000 | — | $ | 35,755 | $ | 734,153 | |||||||||||||||||||
Operational Support | 2009 | $ | 220,833 | — | $ | 157,386 | $ | 165,550 | — | $ | 40,348 | $ | 584,117 | |||||||||||||||||||
and Analysis | ||||||||||||||||||||||||||||||||
Douglas T. Brinkworth | 2011 | $ | 245,000 | — | $ | 342,155 | $ | 117,600 | $ | 10,245 | $ | 39,156 | $ | 754,156 | ||||||||||||||||||
Vice President of | 2010 | $ | 245,000 | — | $ | 303,237 | $ | 183,750 | $ | 12,959 | $ | 41,767 | $ | 786,713 | ||||||||||||||||||
Product Supply | 2009 | $ | 228,333 | — | $ | 182,883 | $ | 185,625 | $ | 31,679 | $ | 43,440 | $ | 671,960 |
Name and Principal Position | Year | Salary ($)(1) | Bonus ($) | Unit Awards ($)(2) | Non-Equity Incentive Plan Compensation ($)(3) | Change in Pension Value and Nonqualified Deferred Compensation Earnings ($)(4) | All Other Compensation ($)(5) | Total ($) | ||||||||||||||||||||||||
(a) | (b) | (c ) | (d) | (e) | (g) | (h) | (i) | (j) | ||||||||||||||||||||||||
Michael J. Dunn, Jr. President and Chief Executive Officer | 2013 | $ | 495,000 | — | $ | 369,124 | $ | 297,000 | — | $ | 54,619 | $ | 1,215,743 | |||||||||||||||||||
2012 | $ | 475,000 | — | $ | 521,058 | — | $ | 22,308 | $ | 49,280 | $ | 1,067,646 | ||||||||||||||||||||
2011 | $ | 475,000 | — | $ | 729,076 | $ | 285,000 | $ | 3,764 | $ | 49,530 | $ | 1,542,370 | |||||||||||||||||||
Michael A. Stivala Chief Financial Officer | 2013 | $ | 300,000 | — | $ | 376,313 | $ | 144,000 | — | $ | 42,073 | $ | 862,386 | |||||||||||||||||||
2012 | $ | 275,000 | — | $ | 328,487 | — | $ | 36,557 | $ | 640,044 | ||||||||||||||||||||||
2011 | $ | 275,000 | — | $ | 357,103 | $ | 132,000 | — | $ | 35,010 | $ | 799,113 | ||||||||||||||||||||
Steven C. Boyd Vice President of Field Operations | 2013 | $ | 290,000 | — | $ | 370,348 | $ | 139,200 | — | $ | 33,416 | $ | 832,964 | |||||||||||||||||||
2012 | $ | 270,000 | — | $ | 326,310 | — | $ | 41,823 | $ | 32,763 | $ | 670,896 | ||||||||||||||||||||
2011 | $ | 270,000 | — | $ | 354,615 | $ | 129,600 | $ | 15,257 | $ | 37,095 | $ | 806,567 | |||||||||||||||||||
Mark Wienberg Vice President of Operational Support and Analysis | 2013 | $ | 280,000 | — | $ | 364,382 | $ | 134,400 | — | $ | 36,055 | $ | 814,837 | |||||||||||||||||||
2012 | $ | 250,000 | — | $ | 317,553 | — | — | $ | 32,854 | $ | 600,407 | |||||||||||||||||||||
2011 | $ | 250,000 | — | $ | 344,653 | $ | 120,000 | — | $ | 33,725 | $ | 748,378 | ||||||||||||||||||||
Douglas T. Brinkworth Vice President of Product Supply | 2013 | $ | 270,000 | — | $ | 358,418 | $ | 129,600 | — | $ | 40,772 | $ | 798,790 | |||||||||||||||||||
2012 | $ | 245,000 | — | $ | 315,326 | — | $ | 24,327 | $ | 35,786 | $ | 620,439 | ||||||||||||||||||||
2011 | $ | 245,000 | — | $ | 342,155 | $ | 117,600 | $ | 10,245 | $ | 39,156 | $ | 754,156 |
(1) | Includes amounts deferred by named executive officers as contributions to the | |
For more information on the relationship between salaries and other cash compensation (i.e., annual cash bonuses and Long-Term Incentive Plan awards), refer to the subheading titled “Allocation Among Components” in the “Compensation Discussion and Analysis” above.
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(2) | The amounts reported in this column represent the aggregate grant date fair value of RUP awards made during fiscal years |
Plan Name | Mr. Dunn | Mr. Stivala | Mr. Boyd | Mr. Wienberg | Mr. Brinkworth | |||||||||||||||
2011 | ||||||||||||||||||||
RUP | $ | 433,249 | $ | 220,090 | $ | 220,090 | $ | 220,090 | $ | 220,090 | ||||||||||
LTIP | 295,827 | 137,013 | 134,525 | 124,563 | 122,065 | |||||||||||||||
Total | $ | 729,076 | $ | 357,103 | $ | 354,615 | $ | 344.653 | $ | 342,155 | ||||||||||
2010 | ||||||||||||||||||||
RUP | $ | 399,438 | $ | 160,456 | $ | 160,456 | $ | 160,456 | $ | 160,456 | ||||||||||
LTIP | 369,046 | 160,243 | 157,343 | 112,942 | 142,781 | |||||||||||||||
Total | $ | 768,484 | $ | 320,699 | $ | 317,799 | $ | 273,398 | $ | 303,237 | ||||||||||
2009 | ||||||||||||||||||||
RUP | $ | — | $ | 87,177 | $ | 46,504 | $ | 58,115 | $ | 58,115 | ||||||||||
LTIP | 314,197 | 144,156 | 144,156 | 99,271 | 124,768 | |||||||||||||||
Total | $ | 314,197 | $ | 231,333 | $ | 190,660 | $ | 157,386 | $ | 182,883 | ||||||||||
Plan Name | Mr. Dunn | Mr. Stivala | Mr. Boyd | Mr. Wienberg | Mr. Brinkworth | |||||||||||||||
2013 | ||||||||||||||||||||
RUP | NA | $ | 197,351 | $ | 197,351 | $ | 197,351 | $ | 197,351 | |||||||||||
LTIP | 369,124 | 178,962 | 172,997 | 167,031 | 161,067 | |||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Total | $ | 369,124 | $ | 376,313 | $ | 370,348 | $ | 364,382 | $ | 358,418 | ||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
2012 | ||||||||||||||||||||
RUP | $ | 260,900 | $ | 208,007 | $ | 208,007 | $ | 208,007 | $ | 208,007 | ||||||||||
LTIP | 260,158 | 120,480 | 118,303 | 109,546 | 107,319 | |||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Total | $ | 521,058 | $ | 328,487 | $ | 326,310 | $ | 317,553 | $ | 315,326 | ||||||||||
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|
|
|
|
|
|
|
|
| |||||||||||
2011 | ||||||||||||||||||||
RUP | $ | 433,249 | $ | 220,090 | $ | 220,090 | $ | 220,090 | $ | 220,090 | ||||||||||
LTIP | 295,827 | 137,013 | 134,525 | 124,563 | 122,065 | |||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Total | $ | 729,076 | $ | 357,103 | $ | 354,615 | $ | 344,653 | $ | 342,155 | ||||||||||
|
|
|
|
|
|
|
|
|
|
(3) | The amounts reported in this column represent each named executive officer’s annual cash bonus earned in accordance with the performance measures discussed under the subheading “Annual Cash Bonus Plan” in the “Compensation Discussion and Analysis.” | |
(4) | ||
(5) | The amounts reported in this column consist of the following: |
2011 | ||||||||||||||||||||
Type of Compensation | Mr. Dunn | Mr. Stivala | Mr. Boyd | Mr. Wienberg | Mr. Brinkworth | |||||||||||||||
401(k) Match | $ | 3,675 | $ | 3,675 | $ | 3,675 | $ | 3,675 | $ | 3,675 | ||||||||||
Value of Annual Physical Examination | 1,300 | N/A | N/A | 1,300 | 1,300 | |||||||||||||||
Value of Partnership Provided Vehicle | 16,302 | 14,698 | 7,221 | 11,970 | 10,851 | |||||||||||||||
Tax Preparation Services | 7,700 | N/A | 7,200 | N/A | 5,100 | |||||||||||||||
Cash Balance Plan Administrative Fees | 1,500 | N/A | 1,500 | N/A | 1,500 | |||||||||||||||
Insurance Premiums | 19,053 | 16,637 | 17,499 | 16,780 | 16,730 | |||||||||||||||
Totals | $ | 49,530 | $ | 35,010 | $ | 37,095 | $ | 33,725 | $ | 39,156 | ||||||||||
2010 | ||||||||||||||||||||
Type of Compensation | Mr. Dunn | Mr. Stivala | Mr. Boyd | Mr. Wienberg | Mr. Brinkworth | |||||||||||||||
401(k) Match | $ | 7,350 | $ | 7,350 | $ | 7,350 | $ | 7,350 | $ | 7,350 | ||||||||||
Value of Annual Physical Examination | 1,300 | 1,300 | N/A | 1,300 | 1,300 | |||||||||||||||
Value of Partnership Provided Vehicle | 13,868 | 12,903 | 6,251 | 10,993 | 11,966 | |||||||||||||||
Tax Preparation Services | 6,500 | N/A | 3,600 | N/A | 3,600 | |||||||||||||||
Cash Balance Plan Administrative Fees | 1,500 | N/A | 1,500 | N/A | 1,500 | |||||||||||||||
Insurance Premiums | 18,812 | 16,016 | 16,061 | 16,112 | 16,051 | |||||||||||||||
Totals | $ | 49,330 | $ | 37,569 | $ | 34,762 | $ | 35,755 | $ | 41,767 | ||||||||||
2009 | ||||||||||||||||||||
Type of Compensation | Mr. Dunn | Mr. Stivala | Mr. Boyd | Mr. Wienberg | Mr. Brinkworth | |||||||||||||||
401(k) Match | $ | 14,700 | $ | 14,700 | $ | 14,700 | $ | 13,748 | $ | 13,825 | ||||||||||
Value of Annual Physical Examination | N/A | 1,300 | N/A | 1,300 | N/A | |||||||||||||||
Value of Partnership Provided Vehicle | 12,205 | 11,318 | 6,205 | 10,803 | 10,610 | |||||||||||||||
Tax Preparation Services | 3,000 | N/A | 3,000 | N/A | 3,000 | |||||||||||||||
Cash Balance Plan Administrative Fees | 1,500 | N/A | 1,500 | N/A | 1,500 | |||||||||||||||
Insurance Premiums | 16,660 | 14,410 | 14,406 | 14,497 | 14,505 | |||||||||||||||
Totals | $ | 48,065 | $ | 41,728 | $ | 39,811 | $ | 40,348 | $ | 43,440 | ||||||||||
2013 | ||||||||||||||||||||
Type of Compensation | Mr. Dunn | Mr. Stivala | Mr. Boyd | Mr. Wienberg | Mr. Brinkworth | |||||||||||||||
401(k) Match | $ | 3,825 | $ | 3,825 | $ | 3,825 | $ | 3,825 | $ | 3,825 | ||||||||||
Value of Annual Physical Examination | 1,750 | 1,750 | N/A | 1,500 | 1,750 | |||||||||||||||
Value of Partnership Provided Vehicle | 18,897 | 19,319 | 7,705 | 13,570 | 11,521 | |||||||||||||||
Tax Preparation Services | 8,950 | N/A | 2,650 | N/A | 4,050 | |||||||||||||||
Cash Balance Plan Administrative Fees | 1,500 | N/A | 1,500 | N/A | 1,500 | |||||||||||||||
Insurance Premiums | 19,697 | 17,179 | 17,736 | 17,160 | 18,126 | |||||||||||||||
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| |||||||||||
Totals | $ | 54,619 | $ | 42,073 | $ | 33,416 | $ | 36,055 | $ | 40,772 | ||||||||||
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2012 | ||||||||||||||||||||
Type of Compensation | Mr. Dunn | Mr. Stivala | Mr. Boyd | Mr. Wienberg | Mr. Brinkworth | |||||||||||||||
401(k) Match | $ | 3,000 | $ | 3,000 | $ | 3,000 | $ | 3,000 | $ | 2,940 | ||||||||||
Value of Annual Physical Examination | N/A | 1,500 | N/A | 1,500 | N/A | |||||||||||||||
Value of Partnership Provided Vehicle | 17,047 | 15,480 | 7,743 | 11,676 | 10,677 | |||||||||||||||
Tax Preparation Services | 8,400 | N/A | 3,150 | N/A | 4,050 | |||||||||||||||
Cash Balance Plan Administrative Fees | 1,500 | N/A | 1,500 | N/A | 1,500 | |||||||||||||||
Insurance Premiums | 19,333 | 16,577 | 17,370 | 16,678 | 16,619 | |||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Totals | $ | 49,280 | $ | 36,557 | $ | 32,763 | $ | 32,854 | $ | 35,786 | ||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
2011 | ||||||||||||||||||||
Type of Compensation | Mr. Dunn | Mr. Stivala | Mr. Boyd | Mr. Wienberg | Mr. Brinkworth | |||||||||||||||
401(k) Match | $ | 3,675 | $ | 3,675 | $ | 3,675 | $ | 3,675 | $ | 3,675 | ||||||||||
Value of Annual Physical Examination | 1,300 | N/A | N/A | 1,300 | 1,300 | |||||||||||||||
Value of Partnership Provided Vehicle | 16,302 | 14,698 | 7,221 | 11,970 | 10,851 | |||||||||||||||
Tax Preparation Services | 7,700 | N/A | 7,200 | N/A | 5,100 | |||||||||||||||
Cash Balance Plan Administrative Fees | 1,500 | N/A | 1,500 | N/A | 1,500 | |||||||||||||||
Insurance Premiums | 19,053 | 16,637 | 17,499 | 16,780 | 16,730 | |||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Totals | $ | 49,530 | $ | 35,010 | $ | 37,095 | $ | 33,725 | $ | 39,156 | ||||||||||
|
|
|
|
|
|
|
|
|
|
71Note: Column (f) was omitted from the Summary Compensation Table because Suburban does not grant options to its employees.
The following table sets forth certain information concerning grants of awards made to each named executive officer during the fiscal year ended September 24, 2011:
Phantom | Estimated Future | Estimated Future | ||||||||||||||||||||||||||||||||||||||
Units | Payments | Payments | All Other stock | Grant Date | ||||||||||||||||||||||||||||||||||||
Underlying | Under Non-Equity | Under Equity | Awards: | Fair Value of | ||||||||||||||||||||||||||||||||||||
Equity | Incentive | Incentive | Number of | Stock and | ||||||||||||||||||||||||||||||||||||
Incentive | Plan Awards | Plan Awards | Shares of Stock | Option | ||||||||||||||||||||||||||||||||||||
Plan | Grant | Approval | Plan Awards | Target | Maximum | Target | Maximum | or Units | Awards | |||||||||||||||||||||||||||||||
Name | Name | Date | Date | (LTIP)(4) | ($) | ($) | ($) | ($) | (#) | ($)(5) | ||||||||||||||||||||||||||||||
(a) | (b) | (d) | (e) | (g) | (h) | (i) | (l) | |||||||||||||||||||||||||||||||||
Michael J. Dunn, Jr. | RUP | (1) | 1 Dec 10 | 9 Nov 10 | 9,060 | $ | 433,249 | |||||||||||||||||||||||||||||||||
Bonus | (2) | 26 Sep 10 | $ | 475,000 | $ | 570,000 | ||||||||||||||||||||||||||||||||||
LTIP | (3) | 26 Sep 10 | 4,787 | $ | 273,878 | $ | 342,362 | |||||||||||||||||||||||||||||||||
Michael A. Stivala | RUP | (1) | 1 Dec 10 | 9 Nov 10 | 5,436 | $ | 220,090 | |||||||||||||||||||||||||||||||||
Bonus | (2) | 26 Sep 10 | $ | 220,000 | $ | 264,000 | ||||||||||||||||||||||||||||||||||
LTIP | (3) | 26 Sep 10 | 2,217 | $ | 126,842 | $ | 158,538 | |||||||||||||||||||||||||||||||||
Steven C. Boyd | RUP | (1) | 1 Dec 10 | 9 Nov 10 | 5,436 | $ | 220,090 | |||||||||||||||||||||||||||||||||
Bonus | (2) | 26 Sep 10 | $ | 216,000 | $ | 259,200 | ||||||||||||||||||||||||||||||||||
LTIP | (3) | 26 Sep 10 | 2,177 | $ | 124,552 | $ | 155,677 | |||||||||||||||||||||||||||||||||
Mark Wienberg | RUP | (1) | 1 Dec 10 | 9 Nov 10 | 5,436 | $ | 220,090 | |||||||||||||||||||||||||||||||||
Bonus | (2) | 26 Sep 10 | $ | 200,000 | $ | 240,000 | ||||||||||||||||||||||||||||||||||
LTIP | (3) | 26 Sep 10 | 2,016 | $ | 115,342 | $ | 144,177 | |||||||||||||||||||||||||||||||||
Douglas T. Brinkworth | RUP | (1) | 1 Dec 10 | 9 Nov 10 | 5,436 | $ | 220,090 | |||||||||||||||||||||||||||||||||
Bonus | (2) | 26 Sep 10 | $ | 196,000 | $ | 235,200 | ||||||||||||||||||||||||||||||||||
LTIP | (3) | 26 Sep 10 | 1,975 | $ | 112,996 | $ | 141,259 |
Estimated Future Payments Under Non-Equity Incentive Plan Awards | Estimated Future Payments Under Equity Incentive Plan Awards | |||||||||||||||||||||||||||||||||||
Name | Plan Name | Grant Date | Approval Date | LTIP Units Underlying Equity Incentive Plan Awards (LTIP)(4) | Target ($) | Maximum ($) | Target ($) | Maximum ($) | All Other stock Awards: Number of Shares of Stock or Units (#) | Grant Date Fair Value of Stock and Option Awards ($)(5) | ||||||||||||||||||||||||||
(a) | (b) | (d) | (e) | (g) | (h) | (i) | (l) | |||||||||||||||||||||||||||||
Michael J. Dunn, Jr. | RUP (1) | |||||||||||||||||||||||||||||||||||
Bonus (2) | 30 Sep 12 | $ | 495,000 | $ | 594,000 | |||||||||||||||||||||||||||||||
LTIP (3) | 30 Sep 12 | 6,559 | $ | 369,124 | $ | 461,405 | ||||||||||||||||||||||||||||||
Michael A. Stivala | RUP (1) | 15 Nov 12 | 13 Nov 12 | 8,432 | $ | 197,351 | ||||||||||||||||||||||||||||||
Bonus (2) | 30 Sep 12 | $ | 240,000 | $ | 288,000 | |||||||||||||||||||||||||||||||
LTIP (3) | 30 Sep 12 | 3,180 | $ | 178,962 | $ | 223,703 | ||||||||||||||||||||||||||||||
Steven C. Boyd | RUP (1) | 15 Nov 12 | 13 Nov 12 | 8,432 | $ | 197,351 | ||||||||||||||||||||||||||||||
Bonus (2) | 30 Sep 12 | $ | 232,000 | $ | 278,400 | |||||||||||||||||||||||||||||||
LTIP (3) | 30 Sep 12 | 3,074 | $ | 172,997 | $ | 216,246 | ||||||||||||||||||||||||||||||
Mark Wienberg | RUP (1) | 15 Nov 12 | 13 Nov 12 | 8,432 | $ | 197,351 | ||||||||||||||||||||||||||||||
Bonus (2) | 30 Sep 12 | $ | 224,000 | $ | 268,800 | |||||||||||||||||||||||||||||||
LTIP (3) | 30 Sep 12 | 2,968 | $ | 167,031 | $ | 208,789 | ||||||||||||||||||||||||||||||
Douglas T. Brinkworth | RUP (1) | 15 Nov 12 | 13 Nov 12 | 8,432 | $ | 197,351 | ||||||||||||||||||||||||||||||
Bonus (2) | 30 Sep 12 | $ | 216,000 | $ | 259,200 | |||||||||||||||||||||||||||||||
LTIP (3) | 30 Sep 12 | 2,862 | $ | 161,067 | $ | 201,334 |
(1) | The quantities reported on these lines represent awards granted under the | |
(2) | Amounts reported on these lines are the targeted and maximum annual cash bonus compensation potential for each named executive officer under the annual cash bonus plan as described in the “Compensation Discussion and Analysis” under the subheading “Annual Cash Bonus Plan.” Actual amounts earned by the named executive officers for fiscal | |
(3) | The LTIP is a phantom unit plan. Payments, if earned, are based on a combination of (1) the fair market value of our Common Units at the end of a three-year measurement period, which, for purposes of the plan, is the average of the closing prices for the twenty business days preceding the conclusion of the three-year measurement period, and (2) cash equal to the distributions that would have inured to the same quantity of outstanding Common Units during the same three-year measurement period. The fiscal | |
(4) | This column is frequently used when non-equity incentive plan awards are denominated in units; however, in this case, the numbers reported represent the | |
(5) | The dollar amounts reported in this column represent the aggregate fair value of the RUP awards on the grant date, net of estimated future distributions during the vesting period. The fair value shown may not be indicative of the value realized in the future upon vesting due to the variability in the trading price of our Common Units. | |
Note: Columns (j) and (k) were omitted from the Grants of Plan Based Awards Table because Suburban does not award options to its employees.
72
The following table sets forth certain information concerning outstanding equity awards under our Restricted Unit PlansPlan and phantom equityLTIP unit awards under our 2003 Long-Term Incentive PlanLTIP for each named executive officer as of September 24, 2011:
Stock Awards | ||||||||||||||||
Equity Incentive | ||||||||||||||||
Plan Awards: | ||||||||||||||||
Number of | Equity Incentive Plan | |||||||||||||||
Market Value | Unearned | Awards: Market or | ||||||||||||||
Number of Shares | of Shares or | Shares, Units or | Payout Value of | |||||||||||||
or Units of Stock | Units of Stock | Other Rights | Unearned Shares, | |||||||||||||
That Have Not | That Have Not | that Have Not | Units or Other Rights | |||||||||||||
Vested | Vested | Vested | That Have Not Vested | |||||||||||||
Name | (#)(6) | ($)(7) | (#)(8) | ($)(9) | ||||||||||||
(a) | (g) | (h) | (i) | (j) | ||||||||||||
Michael J. Dunn, Jr. (1) | 42,557 | $ | 1,965,069 | 10,768 | $ | 615,698 | ||||||||||
Michael A. Stivala(2) | 19,813 | $ | 914,865 | 4,814 | $ | 275,263 | ||||||||||
Steven C. Boyd(3) | 18,417 | $ | 850,405 | 4,727 | $ | 270,287 | ||||||||||
Mark Wienberg(4) | 16,503 | $ | 762,026 | 4,219 | $ | 241,246 | ||||||||||
Douglas T. Brinkworth(5) | 17,134 | $ | 791,162 | 4,289 | $ | 245,244 |
Stock Awards | ||||||||||||||||
Name | Number of Shares or Units of Stock That Have Not Vested (#)(6) | Market Value of Shares or Units of Stock That Have Not Vested ($)(7) | Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights that Have Not Vested (#)(8) | Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested ($)(9) | ||||||||||||
(a) | (g) | (h) | (i) | (j) | ||||||||||||
Michael J. Dunn, Jr. (1) | 8,000 | $ | 370,960 | 11,817 | $ | 664,557 | ||||||||||
Michael A. Stivala(2) | 26,484 | $ | 1,228,063 | 5,615 | $ | 315,779 | ||||||||||
Steven C. Boyd(3) | 25,360 | $ | 1,175,943 | 5,465 | $ | 307,342 | ||||||||||
Mark Wienberg(4) | 25,682 | $ | 1,190,874 | 5,182 | $ | 291,430 | ||||||||||
Douglas T. Brinkworth(5) | 25,682 | $ | 1,190,874 | 5,031 | $ | 282,937 |
(1) |
Vesting | Dec 3, | Sep 29, | Dec 3, | |||||||||
Date | 2011 | 2012 | 2012 | |||||||||
Quantity of Units | 7,384 | 20,408 | 14,765 |
Vesting Date | Dec 1 2014 | Dec 1 2015 | Dec 1 2016 | |||||||||
Quantity of Units | 2,000 | 2,000 | 4,000 |
(2) | Mr. Stivala’s RUP awards will vest as follows: |
Dec 1, | Dec 3, | Apr 25, | Dec 1, | Dec 3, | Dec 1, | Dec 1, | Dec 1, | |||||||||||||||||||||||||
Vesting Date | 2011 | 2011 | 2012 | 2012 | 2012 | 2013 | 2014 | 2015 | ||||||||||||||||||||||||
Quantity of Units | 1,205 | 568 | 2,748 | 2,482 | 1,136 | 5,044 | 3,912 | 2,718 |
Vesting Date | Dec 1 2013 | Dec 1 2014 | Nov 15 2015 | Dec 1 2015 | Nov 15 2016 | Dec 1 2016 | Nov 15 2017 | |||||||||||||||||||||
Quantity of Units | 5,044 | 5,507 | 2,108 | 4,313 | 2,108 | 3,188 | 4,216 |
(3) | Mr. Boyd’s RUP awards will vest as follows: |
Dec 1, | Dec 3, | Apr 25, | Dec 1, | Dec 3, | Dec 1, | Dec 1, | Dec 1, | |||||||||||||||||||||||||
Vesting Date | 2011 | 2011 | 2012 | 2012 | 2012 | 2013 | 2014 | 2015 | ||||||||||||||||||||||||
Quantity of Units | 643 | 852 | 2,748 | 1,920 | 1,704 | 3,920 | 3,912 | 2,718 |
Vesting Date | Dec 1 2013 | Dec 1 2014 | Nov 15 2015 | Dec 1 2015 | Nov 15 2015 | Dec 1 2016 | Nov 15 2017 | |||||||||||||||||||||
Quantity of Units | 3,920 | 5,507 | 2,108 | 4,313 | 2,108 | 3,188 | 4,216 |
(4) | Mr. Wienberg’s RUP awards will vest as follows: |
Dec 1, | Apr 25, | Dec 1, | Dec 1, | Dec 1, | Dec 1, | |||||||||||||||||||
Vesting Date | 2011 | 2012 | 2012 | 2013 | 2014 | 2015 | ||||||||||||||||||
Quantity of Units | 803 | 2,748 | 2,080 | 4,292 | 3,962 | 2,618 |
Vesting Date | Dec 1, 2013 | Dec 1, 2014 | Nov 15 2015 | Dec 1, 2015 | Nov 15 2016 | Dec 1 2016 | Nov 15 2017 | |||||||||||||||||||||
Quantity of Units | 4,292 | 5,557 | 2,108 | 4,213 | 2,108 | 3,188 | 4,216 |
(5) | Mr. Brinkworth’s RUP awards will vest as follows: |
Dec 1, | Dec 3, | Apr 25, | Dec 1, | Dec 3, | Dec 1, | Dec 1, | Dec 1, | |||||||||||||||||||||||||
Vesting Date | 2011 | 2011 | 2012 | 2012 | 2012 | 2013 | 2014 | 2015 | ||||||||||||||||||||||||
Quantity of Units | 803 | 852 | 823 | 2,080 | 1,704 | 4,242 | 3,912 | 2,718 |
Vesting Date | Dec 1, 2013 | Dec 1, 2014 | Nov 15 2015 | Dec 1, 2015 | Nov 15 2016 | Dec 1 2016 | Nov 15 2017 | |||||||||||||||||||||
Quantity of Units | 4,242 | 5,507 | 2,108 | 4,313 | 2,108 | 3,188 | 4,216 |
(6) | The figures reported in this column represent the total quantity of each of our named executive officer’s unvested RUP awards. | |
(7) | The figures reported in this column represent the figures reported in column (g) multiplied by the average of the highest and the lowest trading prices of our Common Units on September |
73
(8) | The amounts reported in this column represent the quantities of | |
(9) | The amounts reported in this column represent the estimated future target payouts of the fiscal |
Mr. Dunn | Mr. Stivala | Mr. Boyd | Mr. Wienberg | Mr. Brinkworth | ||||||||||||||||
Fiscal 2011 Phantom Units | 4,787 | 2,217 | 2,177 | 2,016 | 1,975 | |||||||||||||||
Value of Fiscal 2011 Phantom Units | $ | 224,893 | $ | 104,155 | $ | 102,275 | $ | 94,712 | $ | 92,786 | ||||||||||
Estimated Distributions over Measurement Period | $ | 48,985 | $ | 22,687 | $ | 22,277 | $ | 20,630 | $ | 20,210 | ||||||||||
Fiscal 2010 Phantom Units | 5,981 | 2,597 | 2,550 | 2,203 | 2,314 | |||||||||||||||
Value of Fiscal 2010 Phantom Units | $ | 280,987 | $ | 122,007 | $ | 119,799 | $ | 103,497 | $ | 108,712 | ||||||||||
Estimated Distributions over Measurement Period | $ | 60,833 | $ | 26,414 | $ | 25,936 | $ | 22,407 | $ | 23,536 |
Mr. Dunn | Mr. Stivala | Mr. Boyd | Mr. Wienberg | Mr. Brinkworth | ||||||||||||||||
Fiscal 2013 LTIP Units | 6,559 | 3,180 | 3,074 | 2,968 | 2,862 | |||||||||||||||
Value of Fiscal 2013 LTIP Units | $ | 300,402 | $ | 145,644 | $ | 140,789 | $ | 135,934 | $ | 131,080 | ||||||||||
Estimated Distributions over Measurement Period | $ | 68,722 | $ | 33,318 | $ | 32,208 | $ | 31,097 | $ | 29,987 | ||||||||||
Fiscal 2012 LTIP Units | 5,258 | 2,435 | 2,391 | 2,214 | 2,169 | |||||||||||||||
Value of Fiscal 2012 LTIP Units | $ | 240,816 | $ | 111,523 | $ | 109,508 | $ | 101,401 | $ | 99,340 | ||||||||||
Estimated Distributions over Measurement Period | $ | 54,617 | $ | 25,294 | $ | 24,837 | $ | 22.998 | $ | 22,530 |
Note: Columns (b), (c), (d), (e) and (f), all of which are for the reporting of option-related compensation, have been omitted from the Outstanding Equity Awards At Fiscal Year End Table because we do not grant options to our employees.
Equity Vested Table for Fiscal 2011
Awards under the Restricted Unit Plans are settled in Common Units upon vesting. Awards under the 2003 Long-Term Incentive Plan,LTIP, a phantom-equityLTIP-equity plan, are settled in cash. The following two tables set forth certain information concerning the vesting of awards under our Restricted Unit Plans and the vesting of the fiscal 20092011 award under our 2003 Long-Term Incentive PlanLTIP for each named executive officer during the fiscal year ended September 24, 2011:
Restricted Unit Plans | Unit Awards | |||||||
Number of | ||||||||
Common Units | ||||||||
Acquired on | Value | |||||||
Vesting | Realized on | |||||||
Name | (#) | Vesting ($)(1) | ||||||
Michael J. Dunn, Jr. | 7,384 | $ | 410,883 | |||||
Michael A. Stivala | 4,280 | $ | 239,616 | |||||
Steven C. Boyd | 5,426 | $ | 299,272 | |||||
Mark Wienberg | 3,712 | $ | 205,004 | |||||
Douglas T. Brinkworth | 4,853 | $ | 268,877 |
Restricted Unit Plans | Unit Awards | |||||||
Number of Common Units | Value Realized | |||||||
Name | Acquired on Vesting (#) | on Vesting ($) (1) | ||||||
Michael J. Dunn, Jr. | 14,765 | $ | 595,842 | |||||
Michael A. Stivala | 3,618 | $ | 146,004 | |||||
Steven C. Boyd | 3,624 | $ | 146,247 | |||||
Mark Wienberg | 2,080 | $ | 83,938 | |||||
Douglas T. Brinkworth | 3,784 | $ | 152,703 |
(1) | The value realized is equal to the average of the high and low trading prices of our Common Units on the vesting date, multiplied by the number of units that vested. |
2003 Long-Term Incentive Plan — Fiscal 2009(2) Award | Cash Awards | |||||||
Number of | ||||||||
Phantom Units | ||||||||
Acquired on | Value | |||||||
Vesting | Realized on | |||||||
Name | (#)(3) | Vesting ($)(4) | ||||||
Michael J. Dunn, Jr. | 6,142 | $ | 350,057 | |||||
Michael A. Stivala | 2,818 | $ | 160,609 | |||||
Steven C. Boyd | 2,818 | $ | 160,609 | |||||
Mark Wienberg | 2,175 | $ | 123,962 | |||||
Douglas T. Brinkworth | 2,439 | $ | 139,008 |
Long-Term Incentive Plan – Fiscal 2011(2) Award | Cash Awards | |||||||
Number of LTIP Units | Value Realized | |||||||
Name | Acquired on Vesting (#) (3) | on Vesting ($) (4) | ||||||
Michael J. Dunn, Jr. | 4,787 | $ | 0 | |||||
Michael A. Stivala | 2,217 | $ | 0 | |||||
Steven C. Boyd | 2,177 | $ | 0 | |||||
Mark Wienberg | 2,016 | $ | 0 | |||||
Douglas T. Brinkworth | 1,975 | $ | 0 |
(2) | The fiscal | |
(3) | In accordance with the formula described in the “Compensation Discussion and Analysis” under the subheading | |
(4) | The value (i.e., cash payment) realized was calculated in accordance with the terms and conditions of the LTIP. For more information, refer to the subheading |
74
The following table sets forth certain information concerning each plan that provides for payments or other benefits at, following, or in connection with retirement for each named executive officer as of the end of the fiscal year ended September 24, 2011:
Number | Present Value | |||||||||||||
of Years | of | Payments | ||||||||||||
Credited | Accumulated | During Last | ||||||||||||
Service | Benefit | Fiscal Year | ||||||||||||
Name | Plan Name | (#) | ($) | ($) | ||||||||||
Michael J. Dunn, Jr. | Cash Balance Plan (1) | 6 | $ | 250,122 | $ | — | ||||||||
LTIP(3) | N/A | $ | 615,698 | $ | — | |||||||||
RUP(4) | N/A | $ | 1,022,730 | $ | — | |||||||||
SERP(5) | 6 | $ | — | $ | 57,611 | |||||||||
Michael A. Stivala(2) | N/A | N/A | $ | — | $ | — | ||||||||
Steven C. Boyd | Cash Balance Plan(1) | 15 | $ | 156,680 | $ | — | ||||||||
Mark Wienberg(2) | N/A | N/A | $ | — | $ | — | ||||||||
Douglas T. Brinkworth | Cash Balance Plan(1) | 6 | $ | 98,920 | $ | — |
Name | Plan Name | Number of Years Credited Service (#) | Present Value of Accumulated Benefit ($) | Payments During Last Fiscal Year ($) | ||||||||
Michael J. Dunn, Jr. | Cash Balance Plan (1) | 6 | $ | 247,290 | $ | — | ||||||
LTIP(3) | N/A | $ | 664,557 | $ | — | |||||||
RUP(4) | N/A | $ | 370,960 | $ | — | |||||||
Michael A. Stivala(2) | N/A | N/A | $ | — | $ | — | ||||||
Steven C. Boyd | Cash Balance Plan (1) | 15 | $ | 169,912 | $ | — | ||||||
Mark Wienberg(2) | N/A | N/A | $ | — | $ | — | ||||||
Douglas T. Brinkworth | Cash Balance Plan (1) | 6 | $ | 108,504 | $ | — |
(1) | For more information on the Cash Balance Plan, refer to the subheading “Pension Plan” in the “Compensation Discussion and Analysis.” | |
(2) | Because Mr. Stivala and Mr. Wienberg commenced employment with | |
(3) | Currently, Mr. Dunn is the only named executive officer who meets the retirement criteria of the LTIP. For such participants, upon retirement, outstanding but unvested awards under the LTIP | |
(4) | Currently, Mr. Dunn is the only named executive officer who meets the retirement criteria of the RUP. | |
75
The following table sets forth certain information containing potential payments to the named executive officers in accordance with the provisions of Mr. Dunn’s letter agreement, the Severance Protection Plan, the RUP and the LTIP for the circumstances listed in the table assuming a September 24, 201128, 2013 termination date:
Involuntary | Involuntary | |||||||||||||||
Termination | Termination | |||||||||||||||
Without Cause | Without Cause | |||||||||||||||
by the | by the | |||||||||||||||
Partnership or | Partnership or | |||||||||||||||
by the | by the | |||||||||||||||
Executive for | Executive for | |||||||||||||||
Good Reason | Good Reason | |||||||||||||||
without a | with a Change | |||||||||||||||
Change of | of Control | |||||||||||||||
Executive Payments and Benefits Upon Termination | Death | Disability | Control Event | Event | ||||||||||||
Michael J. Dunn, Jr. | ||||||||||||||||
Cash Compensation(1) (2) (3) (4) | $ | -0- | $ | -0- | $ | 475,000 | $ | 1,425,000 | ||||||||
Accelerated Vesting of Fiscal 2011 and 2010 LTIP Awards(5) | N/A | N/A | N/A | 703,281 | ||||||||||||
Accelerated Vesting of Outstanding RUP Awards(6) | N/A | 1,546,724 | N/A | 1,965,069 | ||||||||||||
Medical Benefits(3) | N/A | N/A | 13,755 | N/A | ||||||||||||
Total | $ | -0- | $ | 1,546,724 | $ | 488,755 | $ | 4,093,350 | ||||||||
Michael A. Stivala | ||||||||||||||||
Cash Compensation(1) (2) (3) (4) | $ | -0- | $ | -0- | $ | 275,000 | $ | 742,500 | ||||||||
Accelerated Vesting of Fiscal 2011 and 2010 LTIP Awards(5) | N/A | N/A | N/A | 314,091 | ||||||||||||
Accelerated Vesting of Outstanding RUP Awards(6) | N/A | 663,858 | N/A | 914,865 | ||||||||||||
Medical Benefits(3) | N/A | N/A | 13,755 | N/A | ||||||||||||
Total | $ | -0- | $ | 663,858 | $ | 288,755 | $ | 1,971,456 | ||||||||
Steven C. Boyd | ||||||||||||||||
Cash Compensation(1) (2) (3) (4) | $ | -0- | $ | -0- | $ | 270,000 | $ | 729,000 | ||||||||
Accelerated Vesting of Fiscal 2011 and 2010 LTIP Awards(5) | N/A | N/A | N/A | 308,414 | ||||||||||||
Accelerated Vesting of Outstanding RUP Awards(6) | N/A | 599,398 | N/A | 850,405 | ||||||||||||
Medical Benefits(3) | N/A | N/A | 14,272 | N/A | ||||||||||||
Total | $ | -0- | $ | 599,398 | $ | 284,272 | $ | 1,887,819 | ||||||||
Mark Wienberg | ||||||||||||||||
Cash Compensation(1) (2) (3) (4) | $ | -0- | $ | -0- | $ | 250,000 | $ | 675,000 | ||||||||
Accelerated Vesting of Fiscal 2011 and 2010 LTIP Awards(5) | N/A | N/A | N/A | 274,964 | ||||||||||||
Accelerated Vesting of Outstanding RUP Awards(6) | N/A | 511,019 | N/A | 762,026 | ||||||||||||
Medical Benefits(3) | N/A | N/A | 13,755 | N/A | ||||||||||||
Total | $ | -0- | $ | 511,019 | $ | 263,755 | $ | 1,711,990 | ||||||||
Douglas T. Brinkworth | ||||||||||||||||
Cash Compensation(1) (2) (3) (4) | $ | -0- | $ | -0- | $ | 245,000 | $ | 661,500 | ||||||||
Accelerated Vesting of Fiscal 2011 and 2010 LTIP Awards(5) | N/A | N/A | N/A | 279,838 | ||||||||||||
Accelerated Vesting of Outstanding RUP Awards(6) | N/A | 540,155 | N/A | 791,162 | ||||||||||||
Medical Benefits(3) | N/A | N/A | 13,755 | N/A | ||||||||||||
Total | $ | -0- | $ | 540,155 | $ | 258,755 | $ | 1,732,500 |
Executive Payments and Benefits Upon Termination Michael J. Dunn, Jr. Cash Compensation(1) (2) (3) (4) Accelerated Vesting of Fiscal 2013, 2012, and 2011 LTIP Awards(5) Accelerated Vesting of Outstanding RUP Awards(6) Medical Benefits(3) Total Michael A. Stivala Cash Compensation(1) (2) (3) (4) Accelerated Vesting of Fiscal 2013, 2012, and 2011 LTIP Awards(5) Accelerated Vesting of Outstanding RUP Awards(6) Medical Benefits(3) Total Steven C. Boyd Cash Compensation(1) (2) (3) (4) Accelerated Vesting of Fiscal 2013, 2012, and 2011 LTIP Awards(5) Accelerated Vesting of Outstanding RUP Awards(6) Medical Benefits(3) Total Mark Wienberg Cash Compensation(1) (2) (3) (4) Accelerated Vesting of Fiscal 2013, 2012, and 2011 LTIP Awards(5) Accelerated Vesting of Outstanding RUP Awards(6) Medical Benefits(3) Total Douglas T. Brinkworth Cash Compensation(1) (2) (3) (4) Accelerated Vesting of Fiscal 2013, 2012, and 2011 LTIP Awards(5) Accelerated Vesting of Outstanding RUP Awards(6) Medical Benefits(3) Total Death Disability Involuntary
Termination
Without
Cause by
Suburban or
by the
Executive
for Good
Reason
without a
Change of
Control
Event Involuntary
Termination
Without
Cause by
Suburban or
by the
Executive
for Good
Reason with
a Change of
Control
Event $ -0- $ 990,000 $ 990,000 $ 1,485,000 N/A N/A N/A 1,118,988 370,960 370,960 370,960 370,960 N/A 16,414 16,414 N/A $ 370,960 $ 1,377,374 $ 1,377,374 $ 2,974,948 $ -0- $ -0- $ 300,000 $ 810,000 N/A N/A N/A 526,985 1,228,063 837,071 N/A 1,228,063 N/A N/A 17,179 N/A $ 1,228,063 $ 837,071 $ 317,179 $ 2,565,048 $ -0- $ -0- $ 290,000 $ 783,000 N/A N/A N/A 514,473 1,175,943 784,951 N/A 1,175,943 N/A N/A 17,736 N/A $ 1,175,943 $ 784,951 $ 307,736 $ 2,473,416 $ -0- $ -0- $ 280,000 $ 756,000 N/A N/A N/A 483,876 1,190,874 799,883 N/A 1,190,874 N/A N/A 17,159 N/A $ 1,190,874 $ 799,883 $ 297,159 $ 2,430,750 $ -0- $ -0- $ 270,000 $ 729,000 N/A N/A N/A 471,227 1,190,874 799,883 N/A 1,190,874 N/A N/A 18,126 N/A $ 1,190,874 $ 799,883 $ 288,126 $ 2,391,101
(1) | In the event of death, the named executive officer’s estate is entitled to a payment equal to the decedent’s earned but unpaid salary and pro-rata cash bonus. | |
(2) | In the event of disability, the named executive officer is entitled to a payment equal to his earned but unpaid salary and pro-rata cash bonus. Because the terms of our letter agreement with Mr. Dunn became effective on September 29, 2012, for purposes of this table it has been assumed that if Mr. Dunn became disabled on September 28, 2013, the provisions of our letter agreement would govern. For more information on Mr. Dunn’s letter agreement, refer to the subheading “Letter Agreement of Mr. Dunn” in the “Compensation Discussion and Analysis.” | |
(3) | Any severance benefits, unrelated to a change of control event, payable to these officers would be determined by the Committee on a case-by-case basis in accordance with prior treatment of other similarly situated executives and may, as a result, differ from this hypothetical presentation. For purposes of this table, we have assumed that each of these named executive officers would, upon termination of employment without cause or for resignation for good reason, receive accrued salary and benefits through the date of termination plus one times annual salary and continued participation, at active employee rates, in |
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(4) | In the event of a change of control followed by a termination without cause or by a resignation with good reason, each of the named executive officers will receive 78 weeks of base pay plus a sum equal to their annual target cash bonus divided by 52 and multiplied by 78 in accordance with the terms of the Severance Protection Plan. For more information on the Severance Protection Plan, refer to the subheading “Change of Control” in the “Compensation Discussion and Analysis. | |
(5) | In the event of a change of control, all awards under the LTIP | |
In the event of death, the inability to continue employment due to permanent disability, or a termination without cause or a good reason resignation unconnected to a change of control event, awards will vest in accordance with the normal vesting schedule and will be subject to the same requirements as awards held by individuals still employed by Suburban and will be subject to the same risks as awards held by all other participants.
(6) | ||
Under circumstances unrelated to a change of control, if a RUP award recipient’s employment is terminated without cause or he or she resigns for good reason, any RUP awards held by such recipient will be forfeited.
In the event of a change of control, as defined in the RUP document, all unvested RUP awards will vest immediately on the date the change of control is consummated, regardless of the holding period and regardless of whether the recipient’s employment is terminated.
SUPERVISORS’ COMPENSATION
The following table sets forth the compensation of the non-employee members of the Board of Supervisors of the PartnershipSuburban during fiscal 2011.
Fees Earned | ||||||||||||
or Paid in | ||||||||||||
Cash | Unit Awards | Total | ||||||||||
Supervisor | ($)(1) | ($)(2) | ($) | |||||||||
John D. Collins | $ | 75,000 | $ | 0 | $ | 75,000 | ||||||
Harold R. Logan, Jr. | 100,000 | 0 | 100,000 | |||||||||
Dudley C. Mecum | 75,000 | 0 | 75,000 | |||||||||
John Hoyt Stookey | 75,000 | 0 | 75,000 | |||||||||
Jane Swift | 75,000 | 0 | 75,000 |
Supervisor | Fees Earned or Paid in Cash ($)(1) | Unit Awards ($)(2) | Total ($) | |||||||||
Harold R. Logan, Jr. | 115,000 | 140,430 | 255,430 | |||||||||
Lawrence C. Caldwell | 85,000 | 140,791 | 225,791 | |||||||||
Matthew J. Chanin | 85,000 | 140,791 | 225,791 | |||||||||
John D. Collins | 85,000 | 140,430 | 225,430 | |||||||||
Dudley C. Mecum | 85,000 | 140,430 | 225,430 | |||||||||
John Hoyt Stookey | 85,000 | 140,430 | 225,430 | |||||||||
Jane Swift | 85,000 | 140,430 | 225,430 |
(1) | This includes amounts earned for fiscal | |
(2) | ||
Note: The columns for reporting option awards, non-equity incentive plan compensation, changes in pension value and non-qualified deferred compensation plan earnings and all other forms of compensation were omitted from the Supervisor’s Compensation Table because Suburban does not provide these forms of compensation to its non-employee supervisors.
77
Annual Cash Retainer Fees. As the Chairman of the Board of Supervisors, Mr. Logan receivesreceived an annual retainer of $100,000,$115,000 in fiscal 2013, payable in quarterly installments of $25,000$28,750 each. Each of the other non-employee Supervisors receivesreceived an annual cash retainer of $75,000,$85,000 in fiscal 2013, payable in quarterly installments of $18,750$21,250 each.
Meeting Fees.The members of our Board of Supervisors receive no additional remuneration for attendance at regularly scheduled meetings of the Board or its Committees, other than reimbursement of reasonable expenses incurred in connection with such attendance.
Restricted Unit Plans.Each non-employee Supervisor participates in the Restricted Unit Plans. All awards vest in accordance with the provisions of the plan document (see “Compensation Discussion and Analysis” section titled “Restricted Unit Plans” for a description of the vesting schedule). Upon vesting, all awards are settled by issuing Common Units. During fiscal 2004,At its meeting on November 13, 2012, the Committee granted Messrs. Logan, MecumCaldwell and Stookey were grantedChanin unvested restricted unit planRUP awards of 8,500 units each; during fiscal 2007,6,023 each in recognition of them received an additional unvested award of 3,000 units. Uponthe commencement of their terms as supervisors in fiscal 2007, Mr.Supervisors on November 13, 2012. The Committee also granted Messrs. Logan, Collins, Mecum, and Stookey and Ms. Swift additional unvested RUP awards of 6,000 each received an awardin recognition of 5,496 units. During fiscal 2010, each non-employee Supervisor received a granttheir continued service to the Partnership. The effective date of 3,600 units.these grants is November 15, 2012. Messrs. Logan, Mecum and Stookey are the only non-employee Supervisors who have satisfied the retirement provisions of the Partnership’sSuburban’s Restricted Unit Plans.
Additional Supervisor Compensation.Non-employee Supervisors receive no other forms of remuneration from us. The only perquisite provided to the members of the Board of Supervisors is the ability to purchase propane at the same discounted rate that we offer propane to our employees, the value of which was less than $10,000 in fiscal 20112013 for each Supervisor.
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ITEM 12. | SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS |
The following table sets forth certain information as of November 23, 201125, 2013 regarding the beneficial ownership of Common Units by (a) each person or group known to the Partnership, based upon its review of filings under Section 13(d) or (g) under the Securities Act, to own more than 5% of the outstanding Common Units; (b) each member of the Board of Supervisors,Supervisors; (c) each executive officer named in the Summary Compensation Table in Item 11 of this Annual Report,Report; and (d) all members of the Board of Supervisors and executive officers as a group. Based upon filings under Section 13(d) or (g) under the Exchange Act, the Partnership does not know of any person or group who beneficially owns more than 5% of the outstanding Common Units. Except as set forth in the notes to the table, each individual or entity has sole voting and investment power over the Common Units reported.
Amount and Nature of | Percent | |||||||
Name of Beneficial Owner | Beneficial Ownership (1) | of Class | ||||||
Michael J. Dunn, Jr. (a) | 73,715 | * | ||||||
Michael A. Stivala (b) | 11,784 | * | ||||||
Steven C. Boyd (c) | 17,861 | * | ||||||
Mark Wienberg (d) | 4,515 | * | ||||||
Douglas T. Brinkworth (e) | 21,068 | * | ||||||
John Hoyt Stookey (f) | 6,066 | * | ||||||
Harold R. Logan, Jr.(f) | 16,730 | * | ||||||
Dudley C. Mecum (f) | 15,634 | * | ||||||
John D. Collins (g) | 15,198 | * | ||||||
Jane Swift (g) | 1,374 | * | ||||||
All Members of the Board of Supervisors and Executive Officers, as a Group (16 persons) (h) | 244,382 | 1 | % |
Amount and Nature of | Percent | |||||||
Name of Beneficial Owner | Beneficial Ownership (1) | of Class (2) | ||||||
Neuberger Berman Group LLC (a) | 5,836,777 | 9.7 | % | |||||
Michael J. Dunn, Jr. (b) | 108,888 | * | ||||||
Michael A. Stivala (c) | 15,044 | * | ||||||
Steven C. Boyd (d) | 19,873 | * | ||||||
Mark Wienberg (e) | 4,242 | * | ||||||
Douglas T. Brinkworth (f) | 21,310 | * | ||||||
John Hoyt Stookey (g) | 8,466 | * | ||||||
Harold R. Logan, Jr.(g) | 11,840 | * | ||||||
Dudley C. Mecum (g) | 18,034 | * | ||||||
Jane Swift (h) | 900 | * | ||||||
John D. Collins (g) | 16,346 | * | ||||||
Lawrence C. Caldwell (i) | 15,963 | * | ||||||
Matthew J. Chanin (j) | 5,000 | * | ||||||
All Members of the Board of Supervisors and Executive | ||||||||
Officers, as a Group (18 persons) (k) | 310,059 | * |
(1) | With the exception of the 5,836,777 units held by Neuberger Berman Group LLC (of which the Partnership has no knowledge), the 784 units held by the General Partner (see (a) below) and the 10,092 units held by charitable organizations over which Mr. Caldwell has shared investment and voting power (see note (h) below), there is a possibility that any of the above listed units could be pledged as security. Also see note (g) below. |
(2) | Based upon 60,302,682 Common Units outstanding on November 25, 2013. |
* | Less than 1%. | |
(a) | Based upon a Schedule 13G dated June 10, 2013 filed by Neuberger Berman Group LLC and Neuberger Berman LLC, which indicates that as of May 31, 2013 they had the shared power to vote or direct the vote of 5,743,858 Common Units and the shared power to dispose or direct the disposition of 5,836,777 Common Units. The Schedule 13G indicates that Neuberger Berman Group LLC may be deemed to be a beneficial owner of these Common Units for purposes of Rule 13d-3 because certain affiliates have shared power to retain or dispose of Common Units belonging to many unrelated clients. We make no representation as to the accuracy or completeness of the information reported. The address of Neuberger Berman Group LLC is 605 Third Avenue, New York NY 10158. |
(b) | Includes 784 Common Units held by the General Partner, of which Mr. Dunn is the sole member. Excludes |
(c) | Excludes |
(d) | Excludes |
(e) | Excludes |
(f) | Excludes |
(g) | Excludes |
All 900 Common Units have been pledged by Ms. Swift as security for a loan. Excludes |
(j) | Excludes 6,023 unvested restricted units, none of which will vest |
(k) | Inclusive of the unvested restricted units referred to in footnotes (b), (c), (d), (e), (f), (g), (h), (i) and |
79
The following table sets forth certain information, as of September 24, 2011,28, 2013, with respect to the Partnership’s Restricted Unit Plans, under which restricted units of the Partnership, as described in the Notes to the Consolidated Financial Statements included in this Annual Report, are authorized for issuance.
Number of restricted units | ||||||||||||
remaining available for | ||||||||||||
Number of Common | future issuance under the | |||||||||||
Units to be issued upon | Weighted-average grant | Restricted Unit Plans (excluding | ||||||||||
vesting of restricted | date fair value per | securities reflected in | ||||||||||
Plan | units | restricted unit | column (a)) | |||||||||
Category | (a) | (b) | (c) | |||||||||
Equity compensation plans approved by security holders (1) | 485,423 | (2) | $ | 32.71 | 967,594 | |||||||
Equity compensation plans not approved by security holders | — | — | — | |||||||||
Total | 485,423 | $ | 32.71 | 967,594 | ||||||||
Plan Category | Number of Common Units to be issued upon vesting of restricted units (a) | Weighted- average grant date fair value per restricted unit (b) | Number of restricted units remaining available for future issuance under the Restricted Unit Plans (excluding securities reflected in column (a)) (c) | |||||||||
Equity compensation plans approved by security holders (1) | 527,627 | (2) | $ | 29.30 | 668,860 | |||||||
Equity compensation plans not approved by security holders | — | — | — | |||||||||
|
|
|
|
|
| |||||||
Total | 527,627 | $ | 29.30 | 668,860 | ||||||||
|
|
|
|
|
|
(1) | Relates to the Restricted Unit Plans. | |
(2) | Represents number of restricted units that, as of September |
80
Related Person Transactions
None.
Supervisor Independence
The Corporate Governance Guidelines and Principles adopted by the Board of Supervisors provide that a Supervisor is deemed to be lacking a material relationship to the Partnership and is therefore independent of management if the following criteria are satisfied:
1. | Within the past three years, the Supervisor: |
a. | has not been employed by the Partnership and has not received more than $100,000 per year in direct compensation from the Partnership, other than Supervisor and committee fees and pension or other forms of deferred compensation for prior service; | ||
b. | has not provided significant advisory or consultancy services to the Partnership, and has not been affiliated with a company or a firm that has provided such services to the Partnership in return for aggregate payments during any of the last three fiscal years of the Partnership in excess of the greater of 2% of the other company’s consolidated gross revenues or $1 million; | ||
c. | has not been a significant customer or supplier of the Partnership and has not been affiliated with a company or firm that has been a customer or supplier of the Partnership and has either made to the Partnership or received from the Partnership payments during any of the last three fiscal years of the Partnership in excess of the greater of 2% of the other company’s consolidated gross revenues or $1 million; | ||
d. | has not been employed by or affiliated with an internal or external auditor that within the past three years provided services to the Partnership; and | ||
e. | has not been employed by another company where any of the Partnership’s current executives serve on that company’s compensation committee; |
2. | The Supervisor is not a spouse, parent, sibling, child, mother- or father-in-law, son- or daughter-in-law or brother- or sister-in-law of a person having a relationship described in 1. above nor shares a residence with such person; |
3. | The Supervisor is not affiliated with a tax-exempt entity that within the past 12 months received significant contributions from the Partnership (contributions of the greater of 2% of the entity’s consolidated gross revenues or $1 million are considered significant); and |
4. | The Supervisor does not have any other relationships with the Partnership or with members of senior management of the Partnership that the Board determines to be material. |
A copy of our Corporate Governance Guidelines is available without charge from our website atwww.suburbanpropane.com or upon written request directed to: Suburban Propane Partners, L.P., Investor Relations, P.O. Box 206, Whippany, New Jersey 07981-0206.
81
The following table sets forth the aggregate fees for services related to fiscal years 20112013 and 20102012 provided by PricewaterhouseCoopers LLP, our independent registered public accounting firm.
Fiscal | Fiscal | |||||||
2011 | 2010 | |||||||
Audit Fees (a) | $ | 1,956,000 | $ | 2,162,500 | ||||
Tax Fees (b) | 686,425 | 728,223 | ||||||
All Other Fees (c) | 1,800 | 1,605 |
Fiscal | Fiscal | |||||||
2013 | 2012 | |||||||
Audit Fees (a) | $ | 2,378,400 | $ | 3,633,000 | ||||
Audit-Related Fees (b) | — | 450,000 | ||||||
Tax Fees (c) | 1,399,000 | 884,152 | ||||||
All Other Fees (d) | 1,800 | 1,800 | ||||||
|
|
|
| |||||
$ | 3,779,200 | $ | 4,968,952 | |||||
|
|
|
|
(a) | Audit Fees consist of professional services rendered for the integrated audit of our annual consolidated financial statements and our internal control over financial reporting, including reviews of our quarterly financial statements, as well as the issuance of consents in connection with other filings made with the SEC. | |
(b) | Audit-Related Fees consist of acquisition-related due diligence services rendered in connection with the Inergy Propane Acquisition. |
(c) | Tax Fees consist of fees for professional services related to tax reporting, tax compliance and transaction services assistance. |
(d) | All Other Fees represent fees for the purchase of a license to an accounting research software tool. |
The Audit Committee of the Board of Supervisors has adopted a formal policy concerning the approval of audit and non-audit services to be provided by the independent registered public accounting firm, PricewaterhouseCoopers LLP. The policy requires that all services PricewaterhouseCoopers LLP may provide to us, including audit services and permitted audit-related and non-audit services, be pre-approved by the Audit Committee. The Audit Committee pre-approved all audit and non-audit services provided by PricewaterhouseCoopers LLP during fiscal 20112013 and fiscal 2010.
2012.
82
ITEM 15. | EXHIBITS, FINANCIAL STATEMENT SCHEDULES |
(a) | The following documents are filed as part of this Annual Report: |
1. | Financial Statements | ||
See “Index to Financial Statements” set forth on page F-1.
2. | Financial Statement Schedule | ||
See “Index to Financial Statement Schedule” set forth on page S-1.
3. | Exhibits | ||
See “Index to Exhibits” set forth on page E-1.
83
SUBURBAN PROPANE PARTNERS, L.P. | ||||||
Date: November | By: | /s/ MICHAEL J. DUNN, JR. | ||||
Michael J. Dunn, Jr. | ||||||
President, Chief Executive Officer and | ||||||
Supervisor |
Pursuant to the requirements of the Securities Exchange Act of 1934, this Annual Report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated:
Signature | Title | Date | ||||
By: | ||||||
/s/ MICHAEL J. DUNN, JR. | President, Chief Executive | November 27, 2013 | ||||
(Michael J. Dunn, Jr.) | Officer and Supervisor | |||||
By: | ||||||
/s/ HAROLD R. LOGAN, JR. | Chairman and Supervisor | November | ||||
(Harold R. Logan, Jr.) | ||||||
By: | /s/ JOHN HOYT STOOKEY | Supervisor | November | |||
(John Hoyt Stookey) | ||||||
By: | /s/ DUDLEY C. MECUM | Supervisor | November | |||
(Dudley C. Mecum) | ||||||
By: | /s/ JOHN D. COLLINS | Supervisor | November | |||
(John D. Collins) | ||||||
By: | /s/ JANE SWIFT | Supervisor | November | |||
(Jane Swift) | ||||||
By: | /s/ LAWRENCE C. CALDWELL | Supervisor | November 27, 2013 | |||
(Lawrence C. Caldwell) | ||||||
By | /s/ MATTHEW J. CHANIN | Supervisor | November 27, 2013 | |||
(Matthew J. Chanin) | ||||||
By: | /s/ MICHAEL A. STIVALA | Chief Financial Officer | November | |||
(Michael A. Stivala) | ||||||
By | /s/ MICHAEL A. KUGLIN | Vice President and | November 27, 2013 | |||
(Michael A. Kuglin) | Chief Accounting Officer |
84
The exhibits listed on this Exhibit Index are filed as part of this Annual Report. Exhibits required to be filed by Item 601 of Regulation S-K, which are not listed below, are not applicable.
Exhibit | Description | ||||
2.1 | Contribution Agreement dated as of April 25, 2012, as amended as of June 15, 2012, July 6, 2012 and July 19, 2012, among Inergy, L.P., Inergy GP, LLC, Inergy Sales and Service, Inc. and Suburban Propane Partners, L.P. (Incorporated by reference to Exhibit 2.1 to the Partnership’s Current Reports on Form 8-K filed April 26, 2012, June 15, 2012, July 6, 2012 and July 19, 2012, respectively). | ||||
3.1 | Third Amended and Restated Agreement of Limited Partnership of the Partnership dated as of October 19, 2006, as amended as of July 31, 2007. (Incorporated by reference to Exhibit 3.1 to the Partnership’s Current Report on Form 8-K filed August 2, 2007). | ||||
3.2 | Third Amended and Restated Agreement of Limited Partnership of the Operating Partnership dated as of October 19, 2006, as amended as of June 24, 2009. (Incorporated by reference to Exhibit 10.2 to the Partnership’s Current Report on Form 8-K filed June 30, 2009). | ||||
3.3 | Amended and Restated Certificate of Limited Partnership of | ||||
3.4 | Amended and Restated Certificate of Limited Partnership of | ||||
4.1 | Description of Common Units of the Partnership. (Incorporated by reference to Exhibit 4.1 to the Partnership’s Current Report on Form 8-K filed October 19, 2006). | ||||
4.2 | Indenture, dated as of March 23, 2010, related to the 7.375% Senior Notes due 2020, by and among Suburban Propane Partners, L.P., Suburban Energy Finance | ||||
4.3 | First Supplemental Indenture, dated as of March 23, 2010, related to the 7.375% Senior Notes due 2020, by and among Suburban Propane Partners, L.P., Suburban Energy Finance | ||||
4.4 | Indenture, dated as of August 1, 2012, related to the 7.5% Senior Notes due 2018 and the 7.375% Senior Notes due 2021, by and among Suburban Propane Partners, L.P., Suburban Energy Finance Corp. and The Bank of New York Mellon, as Trustee, including the form of 7.5% Senior Notes due 2018 and the form of 7.375% Senior Notes due 2021. (Incorporated by reference to Exhibit 4.1 to the Partnership’s Current Report on Form 8-K filed August 2, 2012). | ||||
4.5 | Support Agreement, dated as of August 1, 2012, among Inergy, L.P., the Partnership and Suburban Energy Finance Corp. (Incorporated by reference to Exhibit 4.3 to the Partnership’s Registration Statement on Form S-4 dated September 19, 2012. |
10.1 | Agreement between Michael J. Dunn, Jr. and the Partnership, effective as of September 27, 2009. (Incorporated by reference to Exhibit 10.1 to the Partnership’s Current Report on Form 8-K filed November 10, 2009). | ||||
10.2 | Suburban Propane Partners, L.P. 2000 Restricted Unit Plan, as amended and restated effective October 17, 2006 and as further amended on July 31, 2007, October 31, 2007, January 24, 2008, January 20, 2009, November 10, 2009 and November | ||||
10.3 | Suburban Propane Partners, L.P. 2009 Restricted Unit Plan, effective August 1, |
E-1
10.4 | Suburban Propane, L.P. Severance Protection Plan, as amended on January 24, 2008, January 20, 2009 and November 10, 2009. (Incorporated by reference to Exhibit 10.8 to the Partnership’s Annual Report on Form 10-K for the fiscal year ended September 26, 2009). | ||||
10.5 | Suburban Propane L.P. 2003 Long Term Incentive Plan, as amended on October 17, 2006 and as further amended on July 31, 2007, October 31, 2007, January 24, 2008 and January 20, 2009. (Incorporated by reference to Exhibit 10.3 to the Partnership’s Quarterly Report on Form 10-Q for the fiscal quarter ended December 27, 2008). | ||||
10.6 | Suburban Propane, L.P. 2013 Long Term Incentive Plan. (Incorporated by reference to Exhibit 99.1 to the Partnership’s Current Report on Form 8-K filed November 10, 2011). | ||||
10.7 | Suburban Propane, L.P. 2014 Long Term Incentive Plan. (Incorporated by reference to Exhibit 99.1 to the Partnership’s Current Report on Form 8-K filed August 7, 2013). | ||||
10.8 | Amended and Restated Retirement Savings and Investment Plan of Suburban Propane effective as of January 1, 1998). (Incorporated by reference to Exhibit 10.24 to the Partnership’s Annual Report on Form 10-K for the fiscal year ended September 29, 2001). | ||||
10.9 | Amendment No. 1 to the Retirement Savings and Investment Plan of Suburban Propane (effective January 1, 2002). (Incorporated by reference to Exhibit 10.25 to the Partnership’s Annual Report on Form 10-K for the fiscal year ended September 28, 2002). | ||||
10.10 | |||||
Amended and Restated Credit Agreement, among the Operating Partnership, the Partnership and Bank of America, N.A., as Administrative Agent and the Lenders party thereto, dated | |||||
10.11 | First Amendment to the Amended and Restated Credit Agreement, | ||||
10.12 | Propane Storage Agreement, dated September 17, 2007, between Suburban Propane, L.P. and Plains LPG Services, L.P. (Incorporated by reference to Exhibit 10.3 to the Partnership’s Current Report on Form 8-K filed September 20, 2007). | ||||
21.1 | Subsidiaries of Suburban Propane Partners, L.P. (Filed herewith). | ||||
23.1 | Consent of PricewaterhouseCoopers LLP. (Filed herewith). |
31.1 | Certification of the President and Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. (Filed herewith). | ||||
31.2 | Certification of the Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. (Filed herewith). | ||||
32.1 | Certification of the President and Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. (Filed herewith). | ||||
32.2 | Certification of the Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. (Filed herewith). | ||||
99.1 | Equity Holding Policy for Supervisors and Executives of Suburban Propane Partners, L.P. (Incorporated by reference to Exhibit 99.1 to the Partnership’s Current Report on Form 8-K dated May 10, 2010). |
E-2
101.INS | XBRL Instance Document | ||||
101.SCH | XBRL Taxonomy Extension Schema Document | ||||
101.CAL | XBRL Taxonomy Extension Calculation Linkbase Document | ||||
101.DEF | XBRL Taxonomy Extension Definition Linkbase Document | ||||
101.LAB | XBRL Taxonomy Extension Label Linkbase Document | ||||
101.PRE | XBRL Taxonomy Extension Presentation Linkbase Document |
E-3
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F-1
To the Board of Supervisors and Unitholders of
Suburban Propane Partners, L.P.
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, of partners’ capital, comprehensive income and of cash flows present fairly, in all material respects, the financial position of Suburban Propane Partners, L.P. and its subsidiaries at September 24, 201128, 2013 and September 25, 2010,29, 2012, and the results of their operations and their cash flows for each of the three fiscal years in the period ended September 24, 201128, 2013, in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the accompanying index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of September 24, 2011,28, 2013, based on criteria established inInternal Control — Control—Integrated Framework (1992)issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Partnership’s management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control over Financial Reporting appearing in Item 9A. Our responsibility is to express opinions on these financial statements, on the financial statement schedule, and on the Partnership’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) 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 (iii) 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.
/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
Florham Park, New Jersey
November 23, 2011
27, 2013
F-2
(in thousands)
September 24, | September 25, | |||||||
2011 | 2010 | |||||||
ASSETS | ||||||||
Current assets: | ||||||||
Cash and cash equivalents | $ | 149,553 | $ | 156,908 | ||||
Accounts receivable, less allowance for doubtful accounts of $6,960 and $5,403, respectively | 66,630 | 60,383 | ||||||
Inventories | 65,907 | 61,047 | ||||||
Other current assets | 15,732 | 18,089 | ||||||
Total current assets | 297,822 | 296,427 | ||||||
Property, plant and equipment, net | 338,125 | 350,420 | ||||||
Goodwill | 277,651 | 277,244 | ||||||
Other assets | 42,861 | 46,823 | ||||||
Total assets | $ | 956,459 | $ | 970,914 | ||||
LIABILITIES AND PARTNERS’ CAPITAL | ||||||||
Current liabilities: | ||||||||
Accounts payable | $ | 37,456 | $ | 39,886 | ||||
Accrued employment and benefit costs | 22,951 | 28,624 | ||||||
Accrued insurance | 9,950 | 10,480 | ||||||
Customer deposits and advances | 57,476 | 63,579 | ||||||
Other current liabilities | 23,681 | 21,945 | ||||||
Total current liabilities | 151,514 | 164,514 | ||||||
Long-term borrowings | 348,169 | 347,953 | ||||||
Accrued insurance | 42,891 | 44,965 | ||||||
Other liabilities | 55,667 | 50,826 | ||||||
Total liabilities | 598,241 | 608,258 | ||||||
Commitments and contingencies | ||||||||
Partners’ capital: | ||||||||
Common Unitholders (35,429 and 35,318 units issued and outstanding at September 24, 2011 and September 25, 2010, respectively) | 418,134 | 419,882 | ||||||
Accumulated other comprehensive loss | (59,916 | ) | (57,226 | ) | ||||
Total partners’ capital | 358,218 | 362,656 | ||||||
Total liabilities and partners’ capital | $ | 956,459 | $ | 970,914 | ||||
September 28, | September 29, | |||||||
2013 | 2012 | |||||||
ASSETS | ||||||||
Current assets: | ||||||||
Cash and cash equivalents | $ | 107,232 | $ | 134,317 | ||||
Accounts receivable, less allowance for doubtful accounts of $6,786 and $4,347, respectively | 94,854 | 88,944 | ||||||
Inventories | 77,623 | 88,176 | ||||||
Other current assets | 13,613 | 26,078 | ||||||
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Total current assets | 293,322 | 337,515 | ||||||
Property, plant and equipment, net | 888,232 | 936,228 | ||||||
Goodwill | 1,087,429 | 1,087,429 | ||||||
Other intangible assets, net | 416,771 | 474,618 | ||||||
Other assets | 42,233 | 48,060 | ||||||
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Total assets | $ | 2,727,987 | $ | 2,883,850 | ||||
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LIABILITIES AND PARTNERS’ CAPITAL | ||||||||
Current liabilities: | ||||||||
Accounts payable | $ | 52,766 | $ | 53,141 | ||||
Accrued employment and benefit costs | 23,559 | 16,514 | ||||||
Accrued insurance | 6,650 | 8,591 | ||||||
Customer deposits and advances | 107,562 | 124,297 | ||||||
Accrued interest | 24,357 | 13,219 | ||||||
Other current liabilities | 19,000 | 37,953 | ||||||
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Total current liabilities | 233,894 | 253,715 | ||||||
Long-term borrowings | 1,245,237 | 1,422,078 | ||||||
Accrued insurance | 51,502 | 45,960 | ||||||
Other liabilities | 68,228 | 71,598 | ||||||
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Total liabilities | 1,598,861 | 1,793,351 | ||||||
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Commitments and contingencies | ||||||||
Partners’ capital: | ||||||||
Common Unitholders 60,231 and 57,013 units issued and outstanding at September 28, 2013 and September 29, 2012, respectively) | 1,176,479 | 1,151,606 | ||||||
Accumulated other comprehensive loss | (47,353 | ) | (61,107 | ) | ||||
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Total partners’ capital | 1,129,126 | 1,090,499 | ||||||
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Total liabilities and partners’ capital | $ | 2,727,987 | $ | 2,883,850 | ||||
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The accompanying notes are an integral part of these consolidated financial statements.
F-3
(in thousands, except per unit amounts)
Year Ended | ||||||||||||
September 24, | September 25, | September 26, | ||||||||||
2011 | 2010 | 2009 | ||||||||||
Revenues | ||||||||||||
Propane | $ | 929,492 | $ | 885,459 | $ | 864,012 | ||||||
Fuel oil and refined fuels | 139,572 | 135,059 | 159,596 | |||||||||
Natural gas and electricity | 84,721 | 77,587 | 76,832 | |||||||||
All other | 36,767 | 38,589 | 42,714 | |||||||||
1,190,552 | 1,136,694 | 1,143,154 | ||||||||||
Costs and expenses | ||||||||||||
Cost of products sold | 678,719 | 598,451 | 540,385 | |||||||||
Operating | 279,329 | 289,567 | 304,767 | |||||||||
General and administrative | 51,648 | 61,656 | 57,044 | |||||||||
Severance charge | 2,000 | — | — | |||||||||
Pension settlement charge | — | 2,818 | — | |||||||||
Depreciation and amortization | 35,628 | 30,834 | 30,343 | |||||||||
1,047,324 | 983,326 | 932,539 | ||||||||||
Operating income | 143,228 | 153,368 | 210,615 | |||||||||
Loss on debt extinguishment | — | (9,473 | ) | (4,624 | ) | |||||||
Interest income | 16 | 61 | 802 | |||||||||
Interest expense | (27,394 | ) | (27,458 | ) | (39,069 | ) | ||||||
Income before provision for income taxes | 115,850 | 116,498 | 167,724 | |||||||||
Provision for income taxes | 884 | 1,182 | 2,486 | |||||||||
Net income | $ | 114,966 | $ | 115,316 | $ | 165,238 | ||||||
Income per Common Unit — basic | $ | 3.24 | $ | 3.26 | $ | 4.99 | ||||||
Weighted average number of Common Units outstanding — basic | 35,525 | 35,374 | 33,134 | |||||||||
Income per Common Unit — diluted | $ | 3.22 | $ | 3.24 | $ | 4.96 | ||||||
Weighted average number of Common Units outstanding — diluted | 35,723 | 35,613 | 33,315 | |||||||||
Year Ended | ||||||||||||
September | September | September | ||||||||||
28, 2013 | 29, 2012 | 24, 2011 | ||||||||||
Revenues | ||||||||||||
Propane | $ | 1,357,102 | $ | 843,648 | $ | 929,492 | ||||||
Fuel oil and refined fuels | 208,957 | 114,288 | 139,572 | |||||||||
Natural gas and electricity | 79,432 | 67,419 | 84,721 | |||||||||
All other | 58,115 | 38,103 | 36,767 | |||||||||
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1,703,606 | 1,063,458 | 1,190,552 | ||||||||||
Costs and expenses | ||||||||||||
Cost of products sold | 861,905 | 599,059 | 678,719 | |||||||||
Operating | 469,496 | 298,772 | 281,329 | |||||||||
General and administrative | 64,845 | 59,020 | 51,648 | |||||||||
Acquisition-related costs | — | 17,916 | — | |||||||||
Depreciation and amortization | 130,384 | 47,034 | 35,628 | |||||||||
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1,526,630 | 1,021,801 | 1,047,324 | ||||||||||
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Operating income | 176,976 | 41,657 | 143,228 | |||||||||
Loss on debt extinguishment | (2,144 | ) | (2,249 | ) | — | |||||||
Interest expense | (95,427 | ) | (38,633 | ) | (27,378 | ) | ||||||
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Income before provision for income taxes | 79,405 | 775 | 115,850 | |||||||||
Provision for income taxes | 607 | 137 | 884 | |||||||||
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Net income | $ | 78,798 | $ | 638 | $ | 114,966 | ||||||
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Income per Common Unit—basic | $ | 1.35 | $ | 0.02 | $ | 3.24 | ||||||
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Weighted average number of Common Units outstanding—basic | 58,378 | 38,848 | 35,525 | |||||||||
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Income per Common Unit—diluted | $ | 1.34 | $ | 0.02 | $ | 3.22 | ||||||
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Weighted average number of Common Units outstanding—diluted | 58,600 | 38,990 | 35,723 | |||||||||
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The accompanying notes are an integral part of these consolidated financial statements.
F-4
(in thousands)
Year Ended | ||||||||||||
September 24, | September 25, | September 26, | ||||||||||
2011 | 2010 | 2009 | ||||||||||
Cash flows from operating activities: | ||||||||||||
Net income | $ | 114,966 | $ | 115,316 | $ | 165,238 | ||||||
Adjustments to reconcile net income to net cash provided by operations: | ||||||||||||
Depreciation and amortization expense | 35,628 | 30,834 | 30,343 | |||||||||
Pension settlement charge | — | 2,818 | — | |||||||||
Loss on debt extinguishment | — | 9,473 | 4,624 | |||||||||
Deferred tax provision | — | — | 1,385 | |||||||||
Other, net | 3,316 | 6,120 | 3,895 | |||||||||
Changes in assets and liabilities: | ||||||||||||
(Increase) decrease in accounts receivable | (6,247 | ) | (7,709 | ) | 42,898 | |||||||
(Increase) decrease in inventories | (4,721 | ) | 9,555 | 9,664 | ||||||||
Increase (decrease) in accounts payable | (2,134 | ) | 3,376 | (22,402 | ) | |||||||
Increase (decrease) in accrued employment and benefit costs | (5,673 | ) | (12,251 | ) | 13,822 | |||||||
Increase (decrease) in accrued insurance | (2,604 | ) | 3,127 | (20,785 | ) | |||||||
Increase (decrease) in customer deposits and advances | (6,103 | ) | (6,328 | ) | (5,437 | ) | ||||||
(Increase) decrease in other current and noncurrent assets | 2,470 | 1,479 | 19,121 | |||||||||
Increase (decrease) in other current and noncurrent liabilities | 3,888 | (13 | ) | 4,185 | ||||||||
Net cash provided by operating activities | 132,786 | 155,797 | 246,551 | |||||||||
Cash flows from investing activities: | ||||||||||||
Capital expenditures | (22,284 | ) | (19,131 | ) | (21,837 | ) | ||||||
Acquisitions of businesses | (3,195 | ) | (14,500 | ) | — | |||||||
Proceeds from sale of property, plant and equipment | 5,974 | 3,520 | 4,985 | |||||||||
Net cash (used in) investing activities | (19,505 | ) | (30,111 | ) | (16,852 | ) | ||||||
Cash flows from financing activities: | ||||||||||||
Repayments of long-term borrowings | — | (256,510 | ) | (177,821 | ) | |||||||
Proceeds from long-term borrowings | — | 247,840 | 100,000 | |||||||||
Issuance costs associated with long-term borrowings | — | (5,018 | ) | (5,543 | ) | |||||||
Repayments of short-term borrowings | — | — | (110,000 | ) | ||||||||
Net proceeds from issuance of Common Units | — | — | 95,880 | |||||||||
Partnership distributions | (120,636 | ) | (118,263 | ) | (106,740 | ) | ||||||
Net cash (used in) financing activities | (120,636 | ) | (131,951 | ) | (204,224 | ) | ||||||
Net (decrease) increase in cash and cash equivalents | (7,355 | ) | (6,265 | ) | 25,475 | |||||||
Cash and cash equivalents at beginning of year | 156,908 | 163,173 | 137,698 | |||||||||
Cash and cash equivalents at end of year | $ | 149,553 | $ | 156,908 | $ | 163,173 | ||||||
Supplemental disclosure of cash flow information: | ||||||||||||
Cash paid for interest | $ | 24,584 | $ | 28,362 | $ | 39,153 | ||||||
Year Ended | ||||||||||||
September | September | September | ||||||||||
28, 2013 | 29, 2012 | 24, 2011 | ||||||||||
Net income | $ | 78,798 | $ | 638 | $ | 114,966 | ||||||
Other comprehensive income: | ||||||||||||
Net unrealized gains (losses) on cash flow hedges | 584 | (3,561 | ) | (1,177 | ) | |||||||
Reclassification of realized losses on cash flow hedges into earnings | 2,465 | 2,680 | 2,881 | |||||||||
Amortization of net actuarial losses and prior service credits into earnings and net change in funded status of benefit plans | 10,705 | (310 | ) | (4,394 | ) | |||||||
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Other comprehensive income (loss) | 13,754 | (1,191 | ) | (2,690 | ) | |||||||
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Total comprehensive income (loss) | $ | 92,552 | $ | (553 | ) | $ | 112,276 | |||||
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The accompanying notes are an integral part of these consolidated financial statements.
F-5
(in thousands)
Accumulated | ||||||||||||||||||||
Other | ||||||||||||||||||||
Number of | Compre- | Total | ||||||||||||||||||
Common | Common | hensive | Partners’ | Comprehensive | ||||||||||||||||
Units | Unitholders | (Loss) Income | Capital | Income (Loss) | ||||||||||||||||
Balance at September 27, 2008 | 32,725 | $ | 262,050 | $ | (44,155 | ) | $ | 217,895 | ||||||||||||
Net income | 165,238 | 165,238 | $ | 165,238 | ||||||||||||||||
Other comprehensive income: | ||||||||||||||||||||
Net unrealized losses on cash flow hedges | (4,079 | ) | (4,079 | ) | (4,079 | ) | ||||||||||||||
Reclassification of realized losses on cash flow hedges into earnings | 3,088 | 3,088 | 3,088 | |||||||||||||||||
Amortization of net actuarial losses and prior service credits into earnings and net change in funded status of benefit plans | (16,142 | ) | (16,142 | ) | (16,142 | ) | ||||||||||||||
Total comprehensive income | $ | 148,105 | ||||||||||||||||||
Partnership distributions | (106,740 | ) | (106,740 | ) | ||||||||||||||||
Common Units issued under Restricted Unit Plans | 72 | |||||||||||||||||||
Sale of Common Units under public offering, net of offering expenses | 2,431 | 95,880 | 95,880 | |||||||||||||||||
Compensation cost recognized under Restricted Unit Plans, net of forfeitures | 2,396 | 2,396 | ||||||||||||||||||
Balance at September 26, 2009 | 35,228 | $ | 418,824 | $ | (61,288 | ) | $ | 357,536 | ||||||||||||
Net income | 115,316 | 115,316 | $ | 115,316 | ||||||||||||||||
Other comprehensive income: | ||||||||||||||||||||
Net unrealized losses on cash flow hedges | (5,706 | ) | (5,706 | ) | (5,706 | ) | ||||||||||||||
Reclassification of realized losses on cash flow hedges into earnings | 3,597 | 3,597 | 3,597 | |||||||||||||||||
Amortization of net actuarial losses and prior service credits into earnings and net change in funded status of benefit plans | 3,353 | 3,353 | 3,353 | |||||||||||||||||
Recognition in earnings of net actuarial loss for pension settlement | 2,818 | 2,818 | 2,818 | |||||||||||||||||
Total comprehensive income | $ | 119,378 | ||||||||||||||||||
Partnership distributions | (118,263 | ) | (118,263 | ) | ||||||||||||||||
Common Units issued under Restricted Unit Plans | 90 | |||||||||||||||||||
Compensation cost recognized under Restricted Unit Plans, net of forfeitures | 4,005 | 4,005 | ||||||||||||||||||
Balance at September 25, 2010 | 35,318 | $ | 419,882 | $ | (57,226 | ) | $ | 362,656 | ||||||||||||
Net income | 114,966 | 114,966 | $ | 114,966 | ||||||||||||||||
Other comprehensive income: | ||||||||||||||||||||
Net unrealized losses on cash flow hedges | (1,177 | ) | (1,177 | ) | (1,177 | ) | ||||||||||||||
Reclassification of realized losses on cash flow hedges into earnings | 2,881 | 2,881 | 2,881 | |||||||||||||||||
Amortization of net actuarial losses and prior service credits into earnings and net change in funded status of benefit plans | (4,394 | ) | (4,394 | ) | (4,394 | ) | ||||||||||||||
Total comprehensive income | $ | 112,276 | ||||||||||||||||||
Partnership distributions | (120,636 | ) | (120,636 | ) | ||||||||||||||||
Common Units issued under Restricted Unit Plans | 111 | |||||||||||||||||||
Compensation cost recognized under Restricted Unit Plans, net of forfeitures | 3,922 | 3,922 | ||||||||||||||||||
Balance at September 24, 2011 | 35,429 | $ | 418,134 | $ | (59,916 | ) | $ | 358,218 | ||||||||||||
Year Ended | ||||||||||||
September | September | September | ||||||||||
28, 2013 | 29, 2012 | 24, 2011 | ||||||||||
Cash flows from operating activities: | ||||||||||||
Net income | $ | 78,798 | $ | 638 | $ | 114,966 | ||||||
Adjustments to reconcile net income to net cash provided by operations: | ||||||||||||
Depreciation and amortization expense | 130,384 | 47,034 | 35,628 | |||||||||
Loss on debt extinguishment | 2,144 | 2,249 | — | |||||||||
Other, net | (2,796 | ) | 6,424 | 3,316 | ||||||||
Changes in assets and liabilities: | ||||||||||||
(Increase) decrease in accounts receivable | (5,910 | ) | 13,762 | (6,247 | ) | |||||||
(Increase) decrease in inventories | 10,553 | 8,189 | (4,721 | ) | ||||||||
Increase (decrease) in accounts payable | (375 | ) | 15,669 | (2,134 | ) | |||||||
Increase (decrease) in accrued employment and benefit costs | 7,045 | (8,586 | ) | (5,673 | ) | |||||||
Increase (decrease) in accrued insurance | 3,601 | (4,451 | ) | (2,604 | ) | |||||||
Increase (decrease) in customer deposits and advances | (16,735 | ) | 18,352 | (6,103 | ) | |||||||
(Increase) decrease in other current and noncurrent assets | 5,436 | (754 | ) | 2,470 | ||||||||
Increase (decrease) in other current and noncurrent liabilities | 2,161 | 12,447 | 3,888 | |||||||||
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Net cash provided by operating activities | 214,306 | 110,973 | 132,786 | |||||||||
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Cash flows from investing activities: | ||||||||||||
Capital expenditures | (27,823 | ) | (17,476 | ) | (22,284 | ) | ||||||
Acquisitions of businesses, net of cash acquired | — | (223,731 | ) | (3,195 | ) | |||||||
Proceeds from sale of property, plant and equipment | 7,310 | 1,449 | 5,974 | |||||||||
Adjustment to purchase price for Inergy Propane | 5,850 | — | — | |||||||||
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Net cash (used in) investing activities | (14,663 | ) | (239,758 | ) | (19,505 | ) | ||||||
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Cash flows from financing activities: | ||||||||||||
Repayments of long-term borrowings | (168,915 | ) | (100,000 | ) | — | |||||||
Proceeds from long-term borrowings | — | 100,000 | — | |||||||||
Proceeds from short-term borrowings | — | 225,000 | — | |||||||||
Repayments of short-term borrowings | — | (225,000 | ) | — | ||||||||
Debt issuance costs | — | (25,199 | ) | — | ||||||||
Net proceeds from issuance of Common Units | 143,444 | 259,842 | — | |||||||||
Partnership distributions | (201,257 | ) | (121,094 | ) | (120,636 | ) | ||||||
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Net cash (used in) provided by financing activities | (226,728 | ) | 113,549 | (120,636 | ) | |||||||
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Net (decrease) in cash and cash equivalents | (27,085 | ) | (15,236 | ) | (7,355 | ) | ||||||
Cash and cash equivalents at beginning of year | 134,317 | 149,553 | 156,908 | |||||||||
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Cash and cash equivalents at end of year | $ | 107,232 | $ | 134,317 | $ | 149,553 | ||||||
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Supplemental disclosure of cash flow information: | ||||||||||||
Cash paid for interest | $ | 86,583 | $ | 38,294 | $ | 24,584 | ||||||
Supplemental disclosure of non-cash investing and financing activities for the Inergy Propane Acquisition (see Note 3): | ||||||||||||
Issuance of long-term debt | $ | — | $ | 1,075,043 | $ | — | ||||||
Issuance of equity | $ | — | $ | 590,027 | $ | — |
The accompanying notes are an integral part of these consolidated financial statements.
F-6
(in thousands)
Number of Common Units | Common Unitholders | Accumulated Other Compre- hensive (Loss) Income | Total Partners’ Capital | |||||||||||||
Balance at September 25, 2010 | 35,318 | $ | 419,882 | $ | (57,226 | ) | $ | 362,656 | ||||||||
Net income | 114,966 | 114,966 | ||||||||||||||
Net unrealized losses on cash flow hedges | (1,177 | ) | (1,177 | ) | ||||||||||||
Reclassification of realized losses on cash flow hedges into earnings | 2,881 | 2,881 | ||||||||||||||
Amortization of net actuarial losses and prior service credits into earnings and net change in funded status of benefit plans | (4,394 | ) | (4,394 | ) | ||||||||||||
Partnership distributions | (120,636 | ) | (120,636 | ) | ||||||||||||
Common Units issued under Restricted Unit Plans | 111 | |||||||||||||||
Compensation cost recognized under Restricted Unit Plans, net of forfeitures | 3,922 | 3,922 | ||||||||||||||
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Balance at September 24, 2011 | 35,429 | $ | 418,134 | $ | (59,916 | ) | $ | 358,218 | ||||||||
Net income | 638 | 638 | ||||||||||||||
Net unrealized losses on cash flow hedges | (3,561 | ) | (3,561 | ) | ||||||||||||
Reclassification of realized losses on cash flow hedges into earnings | 2,680 | 2,680 | ||||||||||||||
Amortization of net actuarial losses and prior service credits into earnings and net change in funded status of benefit plans | (310 | ) | (310 | ) | ||||||||||||
Partnership distributions | (121,094 | ) | (121,094 | ) | ||||||||||||
Issuance of Common Units for business acquisition | 14,200 | 590,027 | 590,027 | |||||||||||||
Sale of Common Units under public offering, net of offering expenses | 7,245 | 259,842 | 259,842 | |||||||||||||
Common Units issued under Restricted Unit Plans | 139 | |||||||||||||||
Compensation cost recognized under Restricted Unit Plans, net of forfeitures | 4,059 | 4,059 | ||||||||||||||
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Balance at September 29, 2012 | 57,013 | $ | 1,151,606 | $ | (61,107 | ) | $ | 1,090,499 | ||||||||
Net income | 78,798 | 78,798 | ||||||||||||||
Net unrealized gains on cash flow hedges | 584 | 584 | ||||||||||||||
Reclassification of realized losses on cash flow hedges into earnings | 2,465 | 2,465 | ||||||||||||||
Amortization of net actuarial losses and prior service credits into earnings and net change in funded status of benefit plans | 10,705 | 10,705 | ||||||||||||||
Partnership distributions | (201,257 | ) | (201,257 | ) | ||||||||||||
Sale of Common Units under public offering, net of offering expenses | 3,105 | 143,444 | 143,444 | |||||||||||||
Common Units issued under Restricted Unit Plans | 113 | |||||||||||||||
Compensation cost recognized under Restricted Unit Plans, net of forfeitures | 3,888 | 3,888 | ||||||||||||||
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Balance at September 28, 2013 | 60,231 | $ | 1,176,479 | $ | (47,353 | ) | $ | 1,129,126 | ||||||||
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The accompanying notes are an integral part of these consolidated financial statements.
SUBURBAN PROPANE PARTNERS, L.P. AND SUBSIDIARIES
(dollars in thousands, except unit and per unit amounts)
1. Partnership Organization and Formation
Suburban Propane Partners, L.P. (the “Partnership”) is a publicly traded Delaware limited partnership principally engaged, through its operating partnership and subsidiaries, in the retail marketing and distribution of propane, fuel oil and refined fuels, as well as the marketing of natural gas and electricity in deregulated markets. In addition, to complement its core marketing and distribution businesses, the Partnership services a wide variety of home comfort equipment, particularly for heating and ventilation. The publicly traded limited partner interests in the Partnership are evidenced by common units traded on the New York Stock Exchange (“Common Units”), with 35,428,85560,230,892 Common Units outstanding at September 24, 2011.28, 2013. The holders of Common Units are entitled to participate in distributions and exercise the rights and privileges available to limited partners under the Third Amended and Restated Agreement of Limited Partnership (the “Partnership Agreement”), adopted on October 19, 2006 following approval by Common Unitholders at the Partnership’s Tri-Annual Meeting and as thereafter amended by the Board of Supervisors on July 31, 2007, pursuant to the authority granted to the Board in the Partnership Agreement.amended. Rights and privileges under the Partnership Agreement include, among other things, the election of all members of the Board of Supervisors and voting on the removal of the general partner.
Suburban Propane, L.P. (the “Operating Partnership”), a Delaware limited partnership, is the Partnership’s operating subsidiary formed to operate the propane business and assets. In addition, Suburban Sales & Service, Inc. (the “Service Company”), a subsidiary of the Operating Partnership, was formed to operate the service work and appliance and parts businesses of the Partnership. The Operating Partnership, together with its direct and indirect subsidiaries, accounts for substantially all of the Partnership’s assets, revenues and earnings. The Partnership, the Operating Partnership and the Service Company commenced operations in March 1996 in connection with the Partnership’s initial public offering.
The general partner of both the Partnership and the Operating Partnership is Suburban Energy Services Group LLC (the “General Partner”), a Delaware limited liability company, the sole member of which is the Partnership’s Chief Executive Officer. Other than as a holder of 784 Common Units that will remain in the General Partner, the General Partner does not have any economic interest in the Partnership or the Operating Partnership.
The Partnership’s fuel oil and refined fuels, natural gas and electricity and services businesses are structured as either limited liability companies that are treated as corporations or corporate entities (collectively referred to as the “Corporate Entities”) and, as such, are subject to corporate level U.S. income tax.
Suburban Energy Finance Corporation,Corp., a direct 100%-owned subsidiary of the Partnership, was formed on November 26, 2003 to serve as co-issuer, jointly and severally with the Partnership, of the Partnership’s senior notes.
On August 1, 2012 (the “Acquisition Date”), the Partnership completed the acquisition of the sole membership interest in Inergy Propane, LLC, including certain wholly-owned subsidiaries of Inergy Propane LLC, and the assets of Inergy Sales and Service, Inc. The acquired interests and assets are collectively referred to as “Inergy Propane.” As of the Acquisition Date, Inergy Propane consisted of the former retail propane assets and operations of Inergy, L.P. (“Inergy”). On the Acquisition Date, Inergy Propane and its remaining wholly-owned subsidiaries acquired became subsidiaries of the Operating Partnership, but were merged into the Operating Partnership on April 30, 2013. The results of operations of Inergy Propane are included in the Partnership’s results of operations beginning on the Acquisition Date. See Note 3.
The Partnership serves approximately 750,000more than 1,200,000 residential, commercial, industrial and agricultural customers from approximately 300750 locations in 3041 states. The Partnership’s operations are concentrated in the east and west coast regions, including Alaska, and have expanded into the mid-west region of the United States including Alaska.as a result of the acquisition of Inergy Propane. No single customer accounted for 10% or more of the Partnership’s revenues during fiscal 2011, 20102013, 2012 or 2009.
2. Summary of Significant Accounting Policies
Principles of Consolidation.The consolidated financial statements include the accounts of the Partnership, the Operating Partnership and all of its direct and indirect subsidiaries. All significant intercompany transactions and account balances have been eliminated. The Partnership consolidates the results of operations, financial condition and cash flows of the Operating Partnership as a result of the Partnership’s 100% limited partner interest in the Operating Partnership.
F-7
Revenue Recognition.Sales of propane, fuel oil and refined fuels are recognized at the time product is delivered to the customer. Revenue from the sale of appliances and equipment is recognized at the time of sale or when installation is complete, as applicable. Revenue from repairs, maintenance and other service activities is recognized upon completion of the service. Revenue from service contracts is recognized ratably over the service period. Revenue from the natural gas and electricity business is recognized based on customer usage as determined by meter readings for amounts delivered, some of which may be unbilled at the end of each accounting period. Revenue from annually billed tank fees is deferred at the time of billings and recognized on a straight-line basis over one year.
Fair Value Measurements.The Partnership measures certain of its assets and liabilities at fair value, which is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants —– in either the principal market or the most advantageous market. The principal market is the market with the greatest level of activity and volume for the asset or liability.
The common framework for measuring fair value utilizes a three-level hierarchy to prioritize the inputs used in the valuation techniques to derive fair values. The basis for fair value measurements for each level within the hierarchy is described below with Level 1 having the highest priority and Level 3 having the lowest.
Level 2: Quoted prices in active markets for similar assets or liabilities; quoted prices for identical or similar instruments in markets that are not active; and model-derived valuations in which all significant inputs are observable in active markets. | ||
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Business Combinations.At the beginning of fiscal 2010, the Partnership adopted revised accounting guidance concerning business combinations. The Partnership accounts for business combinations using the purchaseacquisition method and accordingly, the assets and liabilities of the acquired entities are recorded at their estimated fair values at the acquisition date. Goodwill represents the excess of the purchase price over the fair value of the net assets acquired, including the amount assigned to identifiable intangible assets. The primary drivers that generate goodwill are the value of synergies between the acquired entities and the Partnership, and the acquired assembled workforce, neither of which qualifies as an identifiable intangible asset. Identifiable intangible assets with finite lives are amortized over their useful lives. The results of operations of acquired businesses are included in the Consolidated Financial Statementsconsolidated financial statements from the acquisition date. The Partnership expenses all acquisition-related costs as incurred. Certain provisions of the revised guidance, in particular one related to the accounting for acquired tax benefits, are required to be applied regardless of when the business combination occurred. Therefore, to the extent the Partnership’s Corporate Entities generate taxable profits that enable the utilization of tax benefits acquired in prior business combinations, the corresponding reduction in the valuation allowance will be recorded as a reduction in the provision for income taxes. Previously, such valuation allowance reductions were recorded as a reduction to goodwill.
Use of Estimates.The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (“US GAAP”) 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 revenues and expenses during the reporting period. Estimates have been made by management in the areas of self-insurance and litigation reserves, pension and other postretirement benefit liabilities and costs, valuation of derivative instruments, depreciation and amortization of long-lived assets, asset impairment assessments, tax valuation allowances, and allowances for doubtful accounts.accounts, and purchase price allocation for acquired businesses. Actual results could differ from those estimates, making it reasonably possible that a material change in these estimates could occur in the near term.
F-8
Inventories.Inventories are stated at the lower of cost or market. Cost is determined using a weighted average method for propane, fuel oil and refined fuels and natural gas, and a standard cost basis for appliances, which approximates average cost.
Derivative Instruments and Hedging Activities.
Commodity Price Risk.Given the retail nature of its operations, the Partnership maintains a certain level of priced physical inventory to ensure its field operations have adequate supply commensurate with the time of year. The Partnership’s strategy is to keep its physical inventory priced relatively close to market for its field operations. The Partnership enters into a combination of exchange-traded futures and option contracts and, in certain instances, over-the-counter optionoptions and swap contracts (collectively, “derivative instruments”) to hedge price risk associated with propane and fuel oil physical inventories, as well as future purchases of propane or fuel oil used in its operations and to ensure adequate supply during periods of high demand. In addition, the Partnership sells propane and fuel oil to customers at fixed prices, and enters into derivative instruments to hedge a portion of its exposure to fluctuations in commodity prices as a result of selling the fixed price contracts. Under this risk management strategy, realized gains or losses on derivative instruments will typically offset losses or gains on the physical inventory once the product is sold.sold or delivered as it pertains to fixed price contracts. All of the Partnership’s derivative instruments are reported on the consolidated balance sheet at their fair values. In addition, in the course of normal operations, the Partnership routinely enters into contracts such as forward priced physical contracts for the purchase or sale of propane and fuel oil that qualify for and are designated as normal purchase or normal sale contracts. Such contracts are exempted from the fair value accounting requirements and are accounted for at the time product is purchased or sold under the related contract. The Partnership does not use derivative instruments for speculative trading purposes. Market risks associated with futures, options and forward contractsderivative instruments are monitored daily for compliance with the Partnership’s Hedging and Risk Management Policy which includes volume limits for open positions. Priced on-hand inventory is also reviewed and managed daily as to exposures to changing market prices.
On the date that futures, options and forward contractsderivative instruments are entered into, other than those designated as normal purchases or normal sales, the Partnership makes a determination as to whether the derivative instrument qualifies for designation as a hedge. Changes in the fair value of derivative instruments are recorded each period in current period earnings or other comprehensive income (“OCI”), depending on whether the derivative instrument is designated as a hedge and, if so, the type of hedge. For derivative instruments designated as cash flow hedges, the Partnership formally assesses, both at the hedge contract’s inception and on an ongoing basis, whether the hedge contract is highly effective in offsetting changes in cash flows of hedged items. Changes in the fair value of derivative instruments designated as cash flow hedges are reported in OCI to the extent effective and reclassified into earnings during the same period in which the hedged item affects earnings. The mark-to-market gains or losses on ineffective portions of cash flow hedges are recognized in earnings immediately. Changes in the fair value of derivative instruments that are not designated as cash flow hedges, and that do not meet the normal purchase and normal sale exemption, are recorded within earnings as they occur. Cash flows associated with derivative instruments are reported as operating activities within the consolidated statement of cash flows.
Interest Rate Risk.A portion of the Partnership’s borrowings bear interest at prevailing interest rates based upon, at the Operating Partnership’s option, LIBOR plus an applicable margin or the base rate, defined as the higher of the Federal Funds Rate plus1/⁄2 of 1% or the agent bank’s prime rate, or LIBOR plus 1%, plus the applicable margin. The applicable margin is dependent on the level of the Partnership’s total leverage (the ratio of total debt to income before deducting interest expense, income taxes, depreciation and amortization (“EBITDA”)). Therefore, the Partnership is subject to interest rate risk on the variable component of the interest rate. The Partnership manages part of its variable interest rate risk by entering into interest rate swap agreements. The interest rate swaps have been designated as, and are accounted for as, cash flow hedges. The fair value of the interest rate swaps are determined using an income approach, whereby future settlements under the swaps are converted into a single present value, with fair value being based on the value of current market expectations about those future amounts. Changes in the fair value are recognized in OCI until the hedged item is recognized in earnings. However, due to changes in the underlying interest rate environment, the corresponding value in OCI is subject to change prior to its impact on earnings.
F-9
Valuation of Derivative Instruments. The Partnership measures the fair value of its exchange-traded options and futures contracts using quoted market prices found on the New York Mercantile Exchange (the “NYMEX”) (Level 1 inputs); the fair value of its swap contracts using quoted forward prices, and the fair value of its interest rate swaps using model-derived valuations driven by observable projected movements of the 3-month LIBOR (Level 2 inputs); and the fair value of its over-the-counter options contracts using Level 3 inputs. The Partnership’s over-the-counter options contracts are valued based on an internal option model. The inputs utilized in the model are based on publicly available information, as well as broker quotes. The significant unobservable inputs used in the fair value measurements of the Partnership’s over-the-counter options contracts are interest rate and market volatility.
Property, plant and equipment.Property, plant and equipment are stated at cost. Expenditures for maintenance and routine repairs are expensed as incurred while betterments are capitalized as additions to the related assets and depreciated over the asset’s remaining useful life. The Partnership capitalizes costs incurred in the acquisition and modification of computer software used internally, including consulting fees and costs of employees dedicated solely to a specific project. At the time assets are retired, or otherwise disposed of, the asset and related accumulated depreciation are removed from the accounts, and any resulting gain or loss is recognized within operating expenses. Depreciation is determined under thestraight-line method based upon the estimated useful life of the asset as follows:
Buildings | 40 Years | |||
Building and land improvements | ||||
Transportation equipment | 3-20 Years | |||
Storage facilities | 7-40 Years | |||
Office equipment | 5-10 Years | |||
Tanks and cylinders | ||||
Computer software | 3-7 Years |
The weighted average estimated useful life of the Partnership’s tanks and cylinders is approximately 2728 years.
The Partnership reviews the recoverability of long-lived assets when circumstances occur that indicate that the carrying value of an asset may not be recoverable. Such circumstances include a significant adverse change in the manner in which an asset is being used, current operating losses combined with a history of operating losses experienced by the asset or a current expectation that an asset will be sold or otherwise disposed of before the end of its previously estimated useful life. Evaluation of possible impairment is based on the Partnership’s ability to recover the value of the asset from the future undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the expected undiscounted cash flows are less than the carrying amount of such asset, an impairment loss is recorded as the amount by which the carrying amount of an asset exceeds its fair value. The fair value of an asset will be measured using the best information available, including prices for similar assets or the result of using a discounted cash flow valuation technique.
Goodwill.Goodwill represents the excess of the purchase price over the fair value of net assets acquired. Goodwill is subject to an impairment review at a reporting unit level, on an annual basis in Augustas of the end of fiscal July of each year, or when an event occurs or circumstances change that would indicate potential impairment. The
During the first quarter of fiscal 2013, the Partnership adopted new accounting guidance related to goodwill impairment testing. Under the new guidance, an entity has the option to first assess qualitative factors to determine whether the existence of events or circumstances leads to a determination that it is more likely than not that the fair value of a reporting unit is less than its carrying amount. If, after assessing the totality of events or circumstances, an entity determines it is not more likely than not that the fair value of a reporting unit is less than its carrying amount, then performing the two-step impairment test is unnecessary. However, if an entity concludes otherwise, then it is required to perform the first step of the two-step impairment test.
Under the two-step impairment test, the Partnership assesses the carrying value of goodwill at a reporting unit level based on an estimate of the fair value of the respective reporting unit. Fair value of the reporting unit is estimated using discounted cash flow analyses taking into consideration estimated cash flows in a ten-year projection period and a terminal value calculation at the end of the projection period. If the fair value of the reporting unit exceeds its carrying value, the goodwill associated with the reporting unit is not considered to be impaired. If the carrying value of the reporting unit exceeds its fair value, an impairment loss is recognized to the extent that the carrying amount of the associated goodwill, if any, exceeds the implied fair value of the goodwill.
Other Intangible Assets.Other intangible assets consist of customer lists,relationships, tradenames, non-compete agreements and leasehold interests. Customer listsrelationships and tradenames are amortized under the straight-line method over the estimated period for which the assets are expected to contribute to the future cash flows of the reporting entities to which they relate, ending periodically between fiscal years 20122014 and 2021. Non-compete agreements are amortized under the straight-line method over the periods of the related agreements. Leasehold interests are amortized under the straight-line method over the shorter of the lease term or the useful life of the related assets, through fiscal 2025.
F-10
Customer Deposits and Advances.The Partnership offers different payment programs to its customers including the ability to prepay for usage and to make equal monthly payments on account under a budget payment plan. The Partnership establishes a liability within customer deposits and advances for amounts collected in advance of deliveries.
Income Taxes.As discussed in Note 1, the Partnership structure consists of two limited partnerships, the Partnership and the Operating Partnership, and the Corporate Entities. For federal income tax purposes, as well as for state income tax purposes in the majority of the states in which the Partnership operates, the earnings attributable to the Partnership and the Operating Partnership are included in the tax returns of the individual partners.Common Unitholders. As a result, except for certain states that impose an income tax on partnerships, no income tax expense is reflected in the Partnership’s consolidated financial statements relating to the earnings of the Partnership and the Operating Partnership. The earnings attributable to the Corporate Entities are subject to federal and state income tax. Net earnings for financial statement purposes may differ significantly from taxable income reportable to Common Unitholders as a result of differences between the tax basis and financial reporting basis of assets and liabilities and the taxable income allocation requirements under the Partnership Agreement.
Income taxes for the Corporate Entities are provided based on the asset and liability approach to accounting for income taxes. Under this method, deferred tax assets and liabilities are recognized for the expected future tax consequences of differences between the carrying amounts and the tax basis of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period when the change is enacted. A valuation allowance is recorded to reduce the carrying amounts of deferred tax assets when it is more likely than not that the full amount will not be realized.
Loss Contingencies.In the normal course of business, the Partnership is involved in various claims and legal proceedings. The Partnership records a liability for such matters when it is probable that a loss has been incurred and the amounts can be reasonably estimated. The liability includes probable and estimable legal costs to the point in the legal matter where the Partnership believes a conclusion to the matter will be reached. When only a range of possible loss can be established, the most probable amount in the range is accrued. If no amount within this range is a better estimate than any other amount within the range, the minimum amount in the range is accrued.
Asset Retirement Obligations.Asset retirement obligations apply to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or the normal operation of a long-lived asset. The Partnership has recognized asset retirement obligations for certain costs to remove and properly dispose of underground and aboveground fuel oil storage tanks and contractually mandated removal of leasehold improvements.
The Partnership records a liability at fair value for the estimated cost to settle an asset retirement obligation at the time that liability is incurred, which is generally when the asset is purchased, constructed or leased. The Partnership records the liability, which is referred to as the asset retirement obligation, when it has a legal obligation to incur costs to retire the asset and when a reasonable estimate of the fair value of the liability can be made. If a reasonable estimate cannot be made at the time the liability is incurred, the Partnership records the liability when sufficient information is available to estimate the liability’s fair value.
F-11
Costs and Expenses.The cost of products sold reported in the consolidated statements of operations represents the weighted average unit cost of propane, fuel oil and refined fuels, as well as the cost of natural gas and electricity sold, including transportation costs to deliver product from the Partnership’s supply points to storage or to the Partnership’s customer service centers. Cost of products sold also includes the cost of appliances, equipment and related parts sold or installed by the Partnership’s customer service centers computed on a basis that approximates the average cost of the products. Unrealized (non-cash) gains or losses from changes in the fair value of commodity derivative instruments that are not designated as cash flow hedges are recorded in each reporting period within cost of products sold. Cost of products sold is reported exclusive of any depreciation and amortization as such amounts are reported separately within the consolidated statements of operations.
All other costs of operating the Partnership’s retail propane, fuel oil and refined fuels distribution and appliance sales and service operations, as well as the natural gas and electricity marketing business, are reported within operating expenses in the consolidated statements of operations. These operating expenses include the compensation and benefits of field and direct operating support personnel, costs of operating and maintaining the vehicle fleet, overhead and other costs of the purchasing, training and safety departments and other direct and indirect costs of operating the Partnership’s customer service centers.
All costs of back office support functions, including compensation and benefits for executives and other support functions, as well as other costs and expenses to maintain finance and accounting, treasury, legal, human resources, corporate development and the information systems functions are reported within general and administrative expenses in the consolidated statements of operations.
Net Income Per Unit.Computations of basic income per Common Unit are performed by dividing net income by the weighted average number of outstanding Common Units, and vested (and unissued) restricted units granted under the Partnership’s Restricted Unit Plans, as defined below, to retirement-eligible grantees. Computations of diluted income per Common Unit are performed by dividing net income by the weighted average number of outstanding Common Units and unissued restricted units granted under the Restricted Unit Plans. In computing diluted net income per Common Unit, weighted average units outstanding used to compute basic net income per Common Unit were increased by 198,298, 238,589222,419, 141,570 and 180,789198,298 units for fiscal 2011, 20102013, 2012 and 2009,2011, respectively, to reflect the potential dilutive effect of the unvested restricted units outstanding using the treasury stock method.
Comprehensive Income.The Partnership reports comprehensive (loss) income (the total of net income and all other non-owner changes in partners’ capital) within the consolidated statement of partners’ capital. Comprehensive (loss)comprehensive income. Other comprehensive income includes unrealized gains and losses on derivative instruments accounted for as cash flow hedges and reclassifications of realized losses on cash flow hedges into earnings, amortization of net actuarial losses and prior service credits into earnings and changes in the funded status of pension and other postretirement benefit plans.
F-12
In MayDecember 2011, the Financial Accounting Standards Board (“FASB”) issued an accounting standardstandards update to provide guidance on achieving a consistent definition of(“ASU”) regarding disclosures about offsetting assets and common requirements for fair value measurement and related disclosure requirements in US GAAP.liabilities (“ASU 2011-11”). The new guidance requires quantitativean entity to disclose information about unobservable inputs, valuation processesoffsetting and sensitivity analysis associatedrelated arrangements to enable users of financial statements to understand the effect of those arrangements on its financial position. The guidance intends to enhance disclosures by requiring information about financial instruments and derivative instruments that are either offset in accordance with fair value measurements categorizedother US GAAP or subject to an enforceable master netting arrangement or similar agreement, irrespective of whether or not they are offset in the balance sheet. The new guidance is effective for annual reporting periods beginning on or after January 1, 2013, and interim periods within Level 3those annual periods, which will be the Partnership’s first quarter of its 2014 fiscal year. The Partnership is currently evaluating the impact of the fair value hierarchy, andnew guidance on its future disclosures.
In February 2013, the FASB issued an ASU to establish the effective date for the requirement to present components of reclassifications out of accumulated other comprehensive income either parenthetically on the face of the financial statements or in the notes to the financial statements (“ASU 2013-02”). The guidance is effective prospectively during interim andfor annual periods beginning after December 15, 2011,2012, and interim periods within those annual periods, which will be the secondfirst quarter of the Partnership’s 20122014 fiscal year. Early adoption is not permitted. No material impact is expected on the Partnership’s consolidated financial position, results of operations and cash flows.
3. Acquisition of Inergy Propane
As described in Note 1, the Partnership completed the acquisition of Inergy Propane on August 1, 2012. The acquisition of Inergy Propane (the “Inergy Propane Acquisition”) was consummated pursuant to a definitive agreement dated April 25, 2012 with Inergy, Inergy GP, LLC and Inergy Sales, as amended (the “Contribution Agreement”). Prior to the Acquisition Date, Inergy Propane transferred its interest in certain subsidiaries, as well as all of its rights and interests in the assets and properties of its wholesale propane supply, marketing and distribution business, and its rights and interest in the assets and properties of its West Coast natural gas liquids business, to Inergy. These assets were not included as part of the Inergy Propane business at the time of the transfer of the membership interests in Inergy Propane to the Partnership and were not part of the Inergy Propane Acquisition. The results of operations of Inergy Propane are included in the Partnership’s results of operations beginning on the Acquisition Date.
Pursuant to the Contribution Agreement, the Partnership agreed to issue $600,000 in new Common Units in the aggregate to Inergy and Inergy Sales (the “Equity Consideration”). In accordance with the Contribution Agreement, the number of Common Units issued to Inergy and Inergy Sales in the aggregate was determined by dividing $600,000 by the average of the high and low sales prices of the Partnership’s Common Units for the twenty consecutive trading days ending on the day prior to the execution of the Contribution Agreement, which was determined to be $43.1885, resulting in 13,892,587 Common Units.
Also pursuant to the Contribution Agreement, the Partnership and its wholly-owned subsidiary Suburban Energy Finance Corp. commenced an offer to exchange (the “Exchange Offers”) any and all of the outstanding unsecured 7% senior notes due 2018 and 6.875% senior notes due 2021 issued by Inergy and Inergy Finance Corp., which had an aggregate principal amount outstanding of $1,200,000 (collectively, the “Inergy Notes”), for a combination of $1,000,000 in aggregate principal amount of new unsecured 7.5% senior notes due 2018 and 7.375% senior notes due 2021 (collectively, the “SPH Notes”) issued by the Partnership and Suburban Energy Finance Corp. and up to $200,000 in cash to tendering noteholders (the “Exchange Offer Cash Consideration”). Pursuant to the Contribution Agreement, the Partnership was required to pay Inergy the difference, if any, between $200,000 and the actual Exchange Offer Cash Consideration paid in accordance with the terms of the Exchange Offers (such payment, the “Inergy Cash Consideration”). The Contribution Agreement provided that the Partnership would offer $65,000 in aggregate cash consent payments in connection with the Exchange Offers and that Inergy would pay $36,500 to the Partnership in cash on the Acquisition Date. The Exchange Offers expired and settled on August 1, 2012 (the “Settlement Date”). On the Settlement Date, the Partnership had received tenders and consents from holders representing approximately 98.09% of the total outstanding principal amount of the 2018 Inergy Notes, and tenders and consents from holders representing approximately 99.74% of the total outstanding principal amount of the 2021 Inergy Notes. Based on the results of the Exchange Offers, the Exchange Offer Cash Consideration due to tendering Inergy noteholders was $184,761. The Inergy Cash Consideration was satisfied by the issuance of 307,835 Common Units to Inergy and therefore, when combined with the Equity Consideration, the Partnership issued 14,200,422 Common Units in the aggregate to Inergy and Inergy Sales on August 1, 2012. Inergy distributed 14,058,418 of such Common Units to its unitholders on September 2011,14, 2012.
On April 25, 2012, the FASBPartnership received consents from the requisite lenders under the Amended Credit Agreement (as defined in Note 8) to enable it to incur additional indebtedness, make amendments to the Amended Credit Agreement to adjust certain covenants, and otherwise perform our obligations as contemplated by the Inergy Propane Acquisition. On August 1, 2012, the Operating Partnership executed an amendment to the Amended Credit Agreement to, among other things, provide for (i) a $250,000 senior secured 364-day incremental term loan facility (the “364-Day Facility”) and (ii) an increase in our revolving credit facility under the Amended Credit Agreement from $250,000 to $400,000. On the Acquisition Date, the Operating Partnership drew $225,000 on the 364-Day Facility, which, together with cash received from Inergy (pursuant to the Contribution Agreement) and cash on hand, was used to pay: (i) the consent fees and the Exchange Offer Cash Consideration, (ii) costs and fees related to the Exchange Offers, and (iii) costs and expenses related to the Inergy Propane Acquisition. On August 14, 2012 the Partnership repaid its borrowings of $225,000 under its 364-Day Facility with the proceeds from a public sale of 6,300,000 Common Units that closed on that date.
The fair value of the purchase price for Inergy Propane as determined on the Acquisition Date was $1,890,915, consisting of: (i) $1,075,043 of newly issued a revised accounting standard allowing companiessenior notes (with an aggregate par value of $1,000,000) and $184,761 in cash to first assess qualitative factorstendering Inergy noteholders pursuant to determine whether itthe Exchange Offers; (ii) $65,000 in cash paid to the Inergy noteholders for the consent payments pursuant to the consent solicitations; (iii) $590,027 of new Suburban Common Units (consisting of 14,200,422 Common Units), which were issued to Inergy and Inergy Sales, all but $5,942 (consisting of 142,004 Common Units) of which were subsequently distributed by Inergy to its unitholders; reduced by (iv) $23,916 of cash received from Inergy pursuant to the Contribution Agreement (the cash consideration from Inergy includes the $36,500 discussed above and is more likely than not thatnet of amounts owed to Inergy by the Partnership at the Acquisition Date). The fair value of the newly issued senior notes was determined using Level 2 inputs and the fair value of a reporting unit is less than its carrying amount. If, as a resultthe equity issued to Inergy and Inergy Sales was determined using Level 1 inputs.
During the third quarter of fiscal 2013, the Partnership finalized the third party valuations of the qualitative assessment, it is more likely than not that theAcquisition Date fair value of certain assets acquired in the Inergy Propane Acquisition, principally property, plant and equipment, and intangible assets. The consolidated balance sheets as of September 28, 2013 and September 29, 2012 reflect the final allocation of the purchase price to the assets acquired and liabilities assumed in this business combination.
The table provides the final purchase price allocation:
Assets acquired: | ||||
Cash and cash equivalents | $ | 7,964 | ||
Accounts receivable | 36,076 | |||
Inventories | 30,457 | |||
Other current assets | 2,067 | |||
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Current assets acquired | 76,564 | |||
Property, plant & equipment | 617,854 | |||
Customer relationships (estimated useful life of 9 years) | 445,500 | |||
Non-compete agreements (estimated useful life of 6 years) | 23,059 | |||
Other intangible assets (estimated useful life of 4 years) | 1,983 | |||
Goodwill | 809,778 | |||
Other assets | 2,151 | |||
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Total assets acquired | $ | 1,976,889 | ||
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Liabilities assumed: | ||||
Accounts payable | $ | 16 | ||
Accrued employment and benefit costs | 2,149 | |||
Customer deposits and advances | 48,469 | |||
Other current liabilities | 18,613 | |||
Other noncurrent liabilities | 16,727 | |||
|
| |||
Total liabilities assumed | 85,974 | |||
|
| |||
Total | $ | 1,890,915 | ||
|
|
The final purchase price allocation resulted in the following adjustments to the provisional fair value estimates: property, plant and equipment decreased $33,302, intangible assets (principally customer relationships) increased $39,583, other current assets decreased $765 and other noncurrent liabilities increased $646. The net effect of these adjustments resulted in a reporting unit is less than its carrying amount,$4,870 decrease to goodwill as of the Acquisition Date. As a more detailed two-step goodwill impairment test would be performed to identify a potential goodwill impairment and measure the amount of loss to be recognized, if any. The standard will be effective for annual and interim goodwill impairment tests performed after December 31, 2011, with early adoption permitted. The adoption of this standard is not expected to impact the Partnership’s financial position,result, results of operations or cash flows.
The Partnership has evaluated all subsequent eventsfollowing presents unaudited pro forma combined financial information as if the Inergy Propane Acquisition had occurred on September 26, 2010, the first day of the Partnership’s 2011 fiscal year, as adjusted for the final purchase price allocation. The unaudited pro forma combined financial information was prepared under the assumption that occurredthe net proceeds from the issuance of the 6,300,000 Common Units on August 14, 2012 were used to fund the portion of the Inergy Propane Acquisition that was originally financed through the 364-Day Facility (which was repaid two weeks after the balance sheet date throughAcquisition Date). As a result, the Common Units were assumed to have been issued on September 26, 2010, and, in turn, the pro forma results for the fiscal year ended September 29, 2012 do not include any interest costs associated with the 364-Day Facility.
Year Ended | ||||||||
September 29, | September 24, | |||||||
2012 | 2011 | |||||||
Revenues | $ | 1,842,698 | $ | 2,242,876 | ||||
Net income | $ | 12,824 | $ | 116,287 | ||||
Income per common unit | ||||||||
Basic | $ | 0.23 | $ | 2.08 | ||||
Diluted | $ | 0.23 | $ | 2.07 |
The unaudited pro forma combined financial information is not necessarily indicative of the results that would have occurred had the Inergy Propane Acquisition occurred on the date its financial statements were issued, and concluded there were no events or transactions occurring during this period that required recognition or disclosure in its financial statements.
4. Distributions of Available Cash
The Partnership makes distributions to its partners no later than 45 days after the end of each fiscal quarter of the Partnership in an aggregate amount equal to its Available Cash for such quarter. Available Cash, as defined in the Partnership Agreement, generally means all cash on hand at the end of the respective fiscal quarter less the amount of cash reserves established by the Board of Supervisors in its reasonable discretion for future cash requirements. These reserves are retained for the proper conduct of the Partnership’s business, the payment of debt principal and interest and for distributions during the next four quarters.
The following summarizes the quarterly distributions per Common Unit declared and paid in respect of each of the quarters in the three fiscal years in the period ended September 24, 2011:
Fiscal | Fiscal | Fiscal | ||||||||||
2011 | 2010 | 2009 | ||||||||||
First Quarter | $ | 0.8525 | $ | 0.8350 | $ | 0.8100 | ||||||
Second Quarter | 0.8525 | 0.8400 | 0.8150 | |||||||||
Third Quarter | 0.8525 | 0.8450 | 0.8250 | |||||||||
Fourth Quarter | 0.8525 | 0.8500 | 0.8300 |
Fiscal | Fiscal | Fiscal | ||||||||||
2013 | 2012 | 2011 | ||||||||||
First Quarter | $ | 0.8750 | $ | 0.8525 | $ | 0.8525 | ||||||
Second Quarter | 0.8750 | 0.8525 | 0.8525 | |||||||||
Third Quarter | 0.8750 | 0.8525 | 0.8525 | |||||||||
Fourth Quarter | 0.8750 | 0.8525 | 0.8525 |
F-13
Inventories consist of the following:
As of | ||||||||
September 24, | September 25, | |||||||
2011 | 2010 | |||||||
Propane, fuel oil and refined fuels and natural gas | $ | 64,601 | $ | 59,836 | ||||
Appliances and related parts | 1,306 | 1,211 | ||||||
$ | 65,907 | $ | 61,047 | |||||
As of | ||||||||
September 28, | September 29, | |||||||
2013 | 2012 | |||||||
Propane, fuel oil and refined fuels and natural gas | $ | 75,885 | $ | 83,543 | ||||
Appliances | 1,738 | 4,633 | ||||||
|
|
|
| |||||
$ | 77,623 | $ | 88,176 | |||||
|
|
|
|
The Partnership enters into contracts to buyfor the supply of propane, fuel oil and natural gas for supply purposes.gas. Such contracts generally have a term of one year subject to annual renewal, with purchase quantities specified at the time of order and costs based on market prices at the date of delivery.
Property, plant and equipment consist of the following:
As of | ||||||||
September 24, | September 25, | |||||||
2011 | 2010 | |||||||
Land and improvements | $ | 27,904 | $ | 28,250 | ||||
Buildings and improvements | 82,639 | 80,072 | ||||||
Transportation equipment | 19,067 | 22,959 | ||||||
Storage facilities | 79,525 | 78,176 | ||||||
Equipment, primarily tanks and cylinders | 485,859 | 481,423 | ||||||
Computer systems | 47,718 | 44,705 | ||||||
Construction in progress | 2,704 | 5,290 | ||||||
745,416 | 740,875 | |||||||
Less: accumulated depreciation | 407,291 | 390,455 | ||||||
$ | 338,125 | $ | 350,420 | |||||
As of | ||||||||
September 28, | September 29, | |||||||
2013 | 2012 | |||||||
Land and improvements | $ | 207,516 | $ | 195,803 | ||||
Buildings and improvements | 104,137 | 114,960 | ||||||
Transportation equipment | 71,815 | 70,058 | ||||||
Storage facilities | 113,571 | 115,905 | ||||||
Equipment, primarily tanks and cylinders | 830,282 | 814,342 | ||||||
Computer systems | 49,049 | 48,320 | ||||||
Construction in progress | 4,472 | 4,043 | ||||||
|
|
|
| |||||
1,380,842 | 1,363,431 | |||||||
Less: accumulated depreciation | (492,610 | ) | (427,203 | ) | ||||
|
|
|
| |||||
$ | 888,232 | $ | 936,228 | |||||
|
|
|
|
Depreciation expense for the fiscal 2011, 20102013, 2012 and 20092011 amounted to $72,353, $35,032 and $32,368, $28,411 and $28,123, respectively. During fiscal 2011 and fiscal 2010, the Partnership recorded a $2,883 and $1,800 adjustment, respectively, to accelerate depreciation expense on certain assets taken out of service.
6. Goodwill and Other Intangible Assets
The Partnership’s fiscal 20112013 and fiscal 20102012 annual goodwill impairment review resulted in no adjustments to the carrying amount of goodwill. During fiscal 2009, the Partnership reversed $1,385 of the deferred tax asset valuation allowance, respectively, which was established through purchase accounting, as a reduction to goodwill. This adjustment resulted from the utilization of a portion of the net operating losses established in purchase accounting. As a result of the adoption of revised accounting guidance concerning business combinations at the beginning of fiscal 2010, future reversals of the deferred tax asset valuation allowance will be reflected as a reduction of income tax expense.
F-14
Fuel oil and | Natural gas | |||||||||||||||
Propane | refined fuels | and electricity | Total | |||||||||||||
Balance as of September 25, 2010 | ||||||||||||||||
Goodwill | $ | 264,906 | $ | 10,900 | $ | 7,900 | $ | 283,706 | ||||||||
Accumulated adjustments | — | (6,462 | ) | — | (6,462 | ) | ||||||||||
$ | 264,906 | $ | 4,438 | $ | 7,900 | $ | 277,244 | |||||||||
Balance as of September 24, 2011 | ||||||||||||||||
Goodwill | $ | 265,313 | $ | 10,900 | $ | 7,900 | $ | 284,113 | ||||||||
Accumulated adjustments | — | (6,462 | ) | — | (6,462 | ) | ||||||||||
$ | 265,313 | $ | 4,438 | $ | 7,900 | $ | 277,651 | |||||||||
Goodwill acquired during fiscal 2011 | $ | 407 | $ | — | $ | — | $ | 407 |
Propane | Fuel oil and refined fuels | Natural gas and electricity | Total | |||||||||||||
Balance as of September 29, 2012 | ||||||||||||||||
Goodwill | $ | 1,075,091 | $ | 10,900 | $ | 7,900 | $ | 1,093,891 | ||||||||
Accumulated adjustments | — | (6,462 | ) | — | (6,462 | ) | ||||||||||
|
|
|
|
|
|
|
| |||||||||
$ | 1,075,091 | $ | 4,438 | $ | 7,900 | $ | 1,087,429 | |||||||||
|
|
|
|
|
|
|
| |||||||||
Balance as of September 28, 2013 | ||||||||||||||||
Goodwill | $ | 1,075,091 | $ | 10,900 | $ | 7,900 | $ | 1,093,891 | ||||||||
Accumulated adjustments | — | (6,462 | ) | — | (6,462 | ) | ||||||||||
|
|
|
|
|
|
|
| |||||||||
$ | 1,075,091 | $ | 4,438 | $ | 7,900 | $ | 1,087,429 | |||||||||
|
|
|
|
|
|
|
|
Other intangible assets consist of the following:
As of | ||||||||
September 24, | September 25, | |||||||
2011 | 2010 | |||||||
Customer lists | $ | 26,523 | $ | 25,761 | ||||
Non-compete agreements | 3,756 | 3,156 | ||||||
Tradenames | 1,499 | 1,499 | ||||||
Other | 1,967 | 1,967 | ||||||
33,745 | 32,383 | |||||||
Less: accumulated amortization | ||||||||
Customer lists | (15,036 | ) | (12,671 | ) | ||||
Non-compete agreements | (760 | ) | (107 | ) | ||||
Tradenames | (1,162 | ) | (1,012 | ) | ||||
Other | (709 | ) | (617 | ) | ||||
(17,667 | ) | (14,407 | ) | |||||
$ | 16,078 | $ | 17,976 | |||||
As of | ||||||||
September 28, | September 29, | |||||||
2013 | 2012 | |||||||
Customer relationships | $ | 466,959 | $ | 466,959 | ||||
Non-compete agreements | 26,815 | 26,815 | ||||||
Tradenames | 3,482 | 3,482 | ||||||
Other | 1,967 | 1,967 | ||||||
|
|
|
| |||||
499,223 | 499,223 | |||||||
|
|
|
| |||||
Less: accumulated amortization | ||||||||
Customer relationships | (71,382 | ) | (20,105 | ) | ||||
Non-compete agreements | (8,138 | ) | (2,305 | ) | ||||
Tradenames | (2,040 | ) | (1,394 | ) | ||||
Other | (892 | ) | (801 | ) | ||||
|
|
|
| |||||
(82,452 | ) | (24,605 | ) | |||||
|
|
|
| |||||
$ | 416,771 | $ | 474,618 | |||||
|
|
|
|
Aggregate amortization expense related to other intangible assets for fiscal 2013, 2012 and 2011 2010was $58,031, $12,002 and 2009 was $3,260, $2,423 and $2,220, respectively. Aggregate amortization expense for each of the five succeeding fiscal years related to other intangible assets held as of September 24, 201128, 2013 is as follows: 2012 — $2,834; 2013 — $2,676; 2014 — $2,341; 2015 — $2,1802014—$57,480; 2015—$56,767; 2016—$53,971; 2017—$52,686 and 2016 — $1,690.
7. Income Taxes
For federal income tax purposes, as well as for state income tax purposes in the majority of the states in which the Partnership operates, the earnings attributable to the Partnership as a separate legal entity, and the Operating Partnership are not subject to income tax at the partnership level. With the exception of those states that impose an entity-level income tax on partnerships, the taxable income or loss attributable to the Partnership as a separate legal entity, and to the Operating Partnership, which may vary substantially from the income (loss) before income taxes reported by the Partnership in the consolidated statement of operations, are includable in the federal and state income tax returns of the individual partners.Common Unitholders. The aggregate difference in the basis of the Partnership’s net assets for financial and tax reporting purposes cannot be readily determined as the Partnership does not have access to each partner’sCommon Unitholder’s basis in the Partnership.
F-15
The income tax provision of all the legal entities included in the Partnership’s consolidated statement of operations, which is composed primarily of state income taxes in the few states that impose taxes on partnerships and minimum state income taxes on the Corporate Entities, consists of the following:
Year Ended | ||||||||||||
September 24, | September 25, | September 26, | ||||||||||
2011 | 2010 | 2009 | ||||||||||
Current | ||||||||||||
Federal | $ | 135 | $ | 177 | $ | 173 | ||||||
State and local | 749 | 1,005 | 928 | |||||||||
884 | 1,182 | 1,101 | ||||||||||
Deferred | — | — | 1,385 | |||||||||
$ | 884 | $ | 1,182 | $ | 2,486 | |||||||
Year Ended | ||||||||||||
September 28, | September 29, | September 24, | ||||||||||
2013 | 2012 | 2011 | ||||||||||
Current | ||||||||||||
Federal | $ | 26 | $ | 18 | $ | 135 | ||||||
State and local | 581 | 119 | 749 | |||||||||
|
|
|
|
|
| |||||||
607 | 137 | 884 | ||||||||||
Deferred | — | — | — | |||||||||
|
|
|
|
|
| |||||||
$ | 607 | $ | 137 | $ | 884 | |||||||
|
|
|
|
|
|
The provision for income taxes differs from income taxes computed at the United States federal statutory rate as a result of the following:
Year Ended | ||||||||||||
September 24, | September 25, | September 26, | ||||||||||
2011 | 2010 | 2009 | ||||||||||
Income tax provision at federal statutory tax rate | $ | 40,548 | $ | 40,361 | $ | 58,704 | ||||||
Impact of Partnership income not subject to federal income taxes | (39,952 | ) | (38,808 | ) | (56,294 | ) | ||||||
Permanent differences | 239 | 2,051 | 719 | |||||||||
Change in valuation allowance | (454 | ) | (4,806 | ) | (2,048 | ) | ||||||
State income taxes | 492 | 2,247 | 1,262 | |||||||||
Other | 11 | 137 | 143 | |||||||||
Provision for income taxes — current and deferred | $ | 884 | $ | 1,182 | $ | 2,486 | ||||||
F-16
Year Ended | ||||||||||||
September 28, | September 29, | September 24, | ||||||||||
2013 | 2012 | 2011 | ||||||||||
Income tax provision at federal statutory tax rate | $ | 27,792 | $ | 271 | $ | 40,548 | ||||||
Impact of Partnership income not subject to federal income taxes | (35,187 | ) | (4,564 | ) | (39,952 | ) | ||||||
Permanent differences | 71 | 244 | 239 | |||||||||
Transfer of assets to Corporate Entities | — | 8,181 | — | |||||||||
Change in valuation allowance | 9,771 | (3,567 | ) | (454 | ) | |||||||
State income taxes | (1,135 | ) | 339 | 492 | ||||||||
Other | (705 | ) | (767 | ) | 11 | |||||||
|
|
|
|
|
| |||||||
Provision for income taxes—current and deferred | $ | 607 | $ | 137 | $ | 884 | ||||||
|
|
|
|
|
|
As of | ||||||||
September 24, | September 25, | |||||||
2011 | 2010 | |||||||
Deferred tax assets: | ||||||||
Net operating loss carryforwards | $ | 32,938 | $ | 33,214 | ||||
Allowance for doubtful accounts | 1,323 | 713 | ||||||
Inventory | 658 | 1,423 | ||||||
Intangible assets | 1,201 | 1,362 | ||||||
Deferred revenue | 1,303 | 1,408 | ||||||
Derivative instruments | 71 | 700 | ||||||
AMT credit carryforward | 1,086 | 925 | ||||||
Other accruals | 1,936 | 1,726 | ||||||
Total deferred tax assets | 40,516 | 41,471 | ||||||
Deferred tax liabilities: | ||||||||
Property, plant and equipment | 314 | 815 | ||||||
Total deferred tax liabilities | 314 | 815 | ||||||
Net deferred tax assets | 40,202 | 40,656 | ||||||
Valuation allowance | (40,202 | ) | (40,656 | ) | ||||
Net deferred tax assets | $ | — | $ | — | ||||
As of | ||||||||
September 28, | September 29, | |||||||
2013 | 2012 | |||||||
Deferred tax assets: | ||||||||
Net operating loss carryforwards | $ | 46,356 | $ | 37,255 | ||||
Allowance for doubtful accounts | 878 | 652 | ||||||
Inventory | 525 | 563 | ||||||
Intangible assets | 577 | 927 | ||||||
Deferred revenue | 2,188 | 2,631 | ||||||
Derivative instruments | 109 | 71 | ||||||
AMT credit carryforward | 1,086 | 1,086 | ||||||
Other accruals | 2,062 | 1,926 | ||||||
|
|
|
| |||||
Total deferred tax assets | 53,781 | 45,111 | ||||||
|
|
|
| |||||
Deferred tax liabilities: | ||||||||
Property, plant and equipment | 7,375 | 8,476 | ||||||
|
|
|
| |||||
Total deferred tax liabilities | 7,375 | 8,476 | ||||||
|
|
|
| |||||
Net deferred tax assets | 46,406 | 36,635 | ||||||
Valuation allowance | (46,406 | ) | (36,635 | ) | ||||
|
|
|
| |||||
Net deferred tax assets | $ | — | $ | — | ||||
|
|
|
|
After the Inergy Propane Acquisition, the Partnership contributed all of the Inergy Propane assets and liabilities to the Operating Partnership which, in turn, contributed the fuel oil and refined fuels and service assets and liabilities to the Corporate Entities. At the time of the transfer, the Corporate Entities recognized a deferred tax liability for the difference between the book basis of the assets received and their tax basis. The recognition of that deferred tax liability was offset by the release of a portion of the valuation allowance that previously existed on the net deferred tax assets. Thus, the transfer of these assets had no impact on net income for fiscal 2012.
8. Long-Term Borrowings
Long-term borrowings consist of the following:
As of | ||||||||
September 24, | September 25, | |||||||
2011 | 2010 | |||||||
7.375% senior notes, due March 15, 2020, net of unamortized discount of $1,831 and $2,047, respectively | $ | 248,169 | $ | 247,953 | ||||
Revolving Credit Agreement, due June 25, 2013 | 100,000 | 100,000 | ||||||
$ | 348,169 | $ | 347,953 | |||||
As of | ||||||||
September 28, | September 29, | |||||||
2013 | 2012 | |||||||
7.5% senior notes, due October 1, 2018, including unamortized premium of $28,614 and $33,366, respectively | $ | 525,171 | $ | 529,923 | ||||
7.375% senior notes, due March 15, 2020, net of unamortized discount of $1,400 and $1,615, respectively | 248,600 | 248,385 | ||||||
7.375% senior notes, due August 1, 2021, including unamortized premium of $25,286 and $40,327, respectively | 371,466 | 543,770 | ||||||
Revolving Credit Facility, due January 5, 2017 | 100,000 | 100,000 | ||||||
|
|
|
| |||||
$ | 1,245,237 | $ | 1,422,078 | |||||
|
|
|
|
Senior Notes.
2018 Senior Notes and 2021 Senior Notes
On August 1, 2012, the Partnership and its 100%-owned subsidiary, Suburban Energy Finance Corp., issued $496,557 in aggregate principal amount of unregistered 7.5% senior notes due October 1, 2018 (the “2018 Senior Notes”) and $503,443 in aggregate principal amount of unregistered 7.375% senior notes due August 1, 2021 (the “2021 Senior Notes”) in a private placement in connection with the Inergy Propane Acquisition described in Note 3. Based on market rates for similar issues, the 2018 Senior Notes and 2021 Senior Notes were valued at 106.875% and 108.125%, respectively, of the principal amount, on the Acquisition Date as they were issued in exchange for Inergy’s outstanding notes, not for cash. The 2018 Senior Notes require semi-annual interest payments in April and October, and the 2021 Senior Notes require semi-annual interest payments in February and August.
The 2018 Senior Notes are redeemable, at the Partnership’s option, in whole or in part, at any time after October 1, 2014, in each case at the redemption prices described in the table below, together with any accrued and unpaid interest to the date of the redemption.
Year | Percentage | |||
2014 | 103.750 | % | ||
2015 | 101.875 | % | ||
2016 and thereafter | 100.000 | % |
The 2021 Senior Notes are redeemable, at the Partnership’s option, in whole or in part, at any time after August 1, 2016, in each case at the redemption prices described in the table below, together with any accrued and unpaid interest to date of the redemption.
Year | Percentage | |||
2016 | 103.688 | % | ||
2017 | 102.459 | % | ||
2018 | 101.229 | % | ||
2019 and thereafter | 100.000 | % |
On December 19, 2012, the Partnership completed an offer to exchange its existing unregistered 7.5% senior notes due 2018 and 7.375% senior notes due 2021 (the “Old Notes”) for an equal principal amount of 7.5% senior notes due 2018 and 7.375% senior notes due 2021 (the “Exchange Notes”), respectively, that have been registered under the Securities Act of 1933, as amended. The terms of the Exchange Notes are identical in all material respects (including principal, interest rate, maturity and redemption rights) to the Old Notes for which they were exchanged, except that the Exchange Notes generally will not be subject to transfer restrictions.
On August 2, 2013, the Partnership repurchased, pursuant to an optional redemption, $133,400 of its 2021 Senior Notes using net proceeds from the May 2013 public offering and net proceeds from the underwriters’ exercise of their over-allotment option to purchase additional Common Units. In addition, on August 6, 2013, the Partnership repurchased $23,863 of 2021 Senior Notes in a private transaction using cash on hand. In connection with these repurchases, which totaled $157,263 in aggregate principal amount, the Partnership recognized a loss on the extinguishment of debt of $2,144 consisting of $11,759 for the repurchase premium and related fees, as well as the write-off of $2,064 and ($11,678) in unamortized debt origination costs and unamortized premium, respectively.
2020 Senior Notes
On March 23, 2010, the Partnership and its 100%-owned subsidiary, Suburban Energy Finance Corporation,Corp., completed a public offering of $250,000 in aggregate principal amount of 7.375% senior notes due March 15, 2020 (the “2020 Senior Notes”). The 2020 Senior Notes were issued at 99.136% of the principal amount. amount and require semi-annual interest payments in March and September.
The net proceeds from2020 Senior Notes are redeemable, at the issuance, alongPartnership’s option, in whole or in part, at any time after March 15, 2015, in each case at the redemption prices described in the table below, together with cash on hand, were usedany accrued and unpaid interest to repurchase the 6.875% senior notes due in 2013 (the “2013 Senior Notes”) on March 23, 2010 through a redemption and tender offer. In connection with the repurchasedate of the 2013 Senior Notes, the Partnership recognized a loss on the extinguishment of debt of $9,473 in fiscal 2010, consisting of $7,231 for the repurchase premium and related fees, as well as the write-off of $2,242 in unamortized debt origination costs and unamortized discount.
Year 2015 2016 2017 2018 and thereafter Percentage 103.688 % 102.459 % 101.229 % 100.000 %
The Partnership’s obligations under the 2018 Senior Notes, 2020 Senior Notes and 2021 Senior Notes (collectively, the “Senior Notes”) are unsecured and rank senior in right of payment to any future subordinated indebtedness and equally in right of payment with any future senior indebtedness. The 2020 Senior Notes are structurally subordinated to, which means they rank effectively behind, any debt and other liabilities of the Operating Partnership. The 2020 Senior Notes mature on March 15, 2020 and require semi-annual interest payments in March and September. The Partnership is permitted to redeem some or all of the 2020 Senior Notes any time at redemption prices specified in the indenture governing the 2020 Senior Notes. In addition, the 2020 Senior Notes have a change of control provision that would require the Partnership to offer to repurchase the notes at 101% of the principal amount repurchased, if a change of control, as defined in the indenture, occurs and is followed by a rating decline (a decrease in the rating of the notes by either Moody’s Investors Service or Standard and Poor’s Rating Group by one or more gradations) within 90 days of the consummation of the change of control.
F-17
The amendment to the credit agreement on January 5, 2012 amended the previous credit agreement to, among other things, extend the maturity date from June 25, 2013 to January 5, 2017, reduce the borrowing rate and commitment fees, and amend certain affirmative and negative covenants. As of January 5, 2012, the Operating Partnership borrowedhad borrowings of $100,000 outstanding under the revolving credit facility of the previous credit agreement, and rolled those borrowings into the Revolving Credit Facility and, along with cash on hand, repaidof the $108,000 then outstanding underAmended Credit Agreement. Also, at such time, the Term Loan and terminated the previous credit facility. In addition, theOperating Partnership has standbyhad letters of credit issued under the Revolving Credit Facility inrevolving credit facility of the aggregate amount of $54,856previous credit agreement primarily in support of retention levels under its self-insurance programs, all of which expire periodically through April 15, 2012. Therefore, as of September 24, 2011 the Partnership had available borrowing capacity of $95,144 underhave been rolled into the Revolving Credit Facility.
On August 1, 2012, the Operating Partnership executed an amendment to the Amended Credit Agreement to, among other things, provide for (i) a $250,000 senior secured 364-Day Facility and (ii) an increase in our revolving credit facility under the Amended Credit Agreement from $250,000 to $400,000. On the Acquisition Date, the Operating Partnership drew $225,000 on the 364-Day Facility, which was used to fund a portion of the Inergy Propane Acquisition, including costs and expenses related to the acquisition. The Partnership repaid the $225,000 of borrowings under the 364-Day Facility on August 14, 2012 with the net proceeds from the public issuance of Common Units on August 14, 2012.
The amendment to the Amended Credit Agreement on August 1, 2012 also amended certain restrictive and affirmative covenants applicable to the Operating Partnership and the Partnership, as well as certain financial covenants, including (a) requiring the Partnership’s consolidated interest coverage ratio, as defined in the amendment, to be not less than 2.0 to 1.0 as of the end of any fiscal quarter; (b) prohibiting the total consolidated leverage ratio, as defined in the amendment, of the Partnership from being greater than 7.0 to 1.0 as of the end of any fiscal quarter. The minimum consolidated interest coverage ratio increases over time, and commencing with the third quarter of fiscal 2014, such minimum ratio will be 2.5 to 1.0. The maximum consolidated leverage ratio decreases over time, as well as upon the occurrence of certain events (such as the issuance of Common Units where the net proceeds from the issuance exceed certain thresholds). Commencing with the second quarter of fiscal 2013, such maximum ratio will be 4.75 to 1.0 (or 5.0 to 1.0 during an acquisition period as defined in the amendment) as a result of the issuance of Common Units in August 2012. As of September 28, 2013 the minimum consolidated interest coverage ratio and maximum consolidated leverage ratio was 2.25 to 1.0 and 4.75 to 1.0, respectively.
The Partnership acts as a guarantor with respect to the obligations of the Operating Partnership under the Amended Credit Agreement pursuant to the terms and conditions set forth therein. The obligations under the Amended Credit Agreement are secured by liens on substantially all of the personal property of the Partnership, the Operating Partnership and their subsidiaries, as well as mortgages on certain real property.
Borrowings under the Revolving Credit Facility of the Amended Credit Agreement bear interest at prevailing interest rates based upon, at the Operating Partnership’s option, LIBOR plus the applicable margin or the base rate, defined as the higher of the Federal Funds Rate plus1/⁄2 of 1%, the agent bank’s prime rate, or LIBOR plus 1%, plus in each case the applicable margin. The applicable margin is dependent upon the Partnership’s ratio of total debt to EBITDA on a consolidated basis, as defined in the Revolving Credit Facility. As of September 24, 2011,28, 2013, the interest rate for the Revolving Credit Facility was approximately 3.25%2.8%. The interest rate and the applicable margin will be reset at the end of each calendar quarter.
In connection with respect to the obligations of the Operating Partnership under the Credit Agreement pursuant to the terms and conditions set forth therein. The obligations under the Credit Agreement are secured by liens on substantially all of the personal property of the Partnership, the Operating Partnership and their subsidiaries, as well as mortgages on certain real property.
As of September 28, 2013, the Partnership had standby letters of credit issued under the Revolving Credit Facility in the aggregate amount of $46,742 which expire periodically through April 3, 2014. Therefore, as of September 28, 2013 the Partnership had available borrowing capacity of $253,258 under the Revolving Credit Facility.
The Amended Credit Agreement and the 2020 Senior Notes both contain various restrictive and affirmative covenants applicable to the Operating Partnership and the Partnership, respectively, including (i) restrictions on the incurrence of additional indebtedness, and (ii) restrictions on certain liens, investments, guarantees, loans, advances, payments, mergers, consolidations, distributions, sales of assets and other transactions. The Revolving Credit Facility contains certain financial covenants (a) requiring the Partnership’s consolidated interest coverage ratio, as defined, to be not less than 2.5 to 1.0 as of the end of any fiscal quarter; (b) prohibiting the total consolidated leverage ratio, as defined, of the Partnership from being greater than 4.5 to 1.0 as of the end of any fiscal quarter; and (c) prohibiting the Operating Partnership’s senior secured consolidated leverage ratio, as defined, from being greater than 3.0 to 1.0 as of the end of any fiscal quarter. Under the indentureAmended Credit Agreement and the indentures governing the 2020 Senior Notes, the Operating Partnership isand the Partnership are generally permitted to make cash distributions equal to available cash, as defined, as of the end of the immediately preceding quarter, if no event of default exists or would exist upon making such distributions, and with respect to the indentures governing the Senior Notes, the Partnership’s consolidated fixed charge coverage ratio, as defined, is greater than 1.75 to 1. The Partnership and the Operating Partnership were in compliance with all covenants and terms of the 2020 Senior Notes and the RevolvingAmended Credit FacilityAgreement as of September 24, 2011.
28, 2013.
F-18
The aggregate amounts of long-term debt maturities subsequent to September 24, 201128, 2013 are as follows: 2012:fiscal 2014 through fiscal 2016: $-0-; 2013:fiscal 2017: $100,000; 2014: $-0-; 2015: $-0-;fiscal 2018: $496,557; and thereafter: $250,000.
9. Unit-Based Compensation Arrangements
As described in Note 2, the Partnership recognizes compensation cost over the respective service period for employee services received in exchange for an award of equity, or equity-based compensation, based on the grant date fair value of the award. The Partnership measures liability awards under an equity-based payment arrangement based on remeasurementre-measurement of the award’s fair value at the conclusion of each interim and annual reporting period until the date of settlement, taking into consideration the probability that the performance conditions will be satisfied.
Restricted Unit Plans.In fiscal 2000 and fiscal 2009, the Partnership adopted the Suburban Propane Partners, L.P. 2000 Restricted Unit Plan and 2009 Restricted Unit Plan (collectively, the “Restricted Unit Plans”), respectively, which authorizes the issuance of Common Units to executives, managers and other employees and members of the Board of Supervisors of the Partnership. The total number of Common Units authorized for issuance under the Restricted Unit Plans was 1,906,9711,902,122 as of September 24, 2011.28, 2013. Unless otherwise stipulated by the Compensation Committee of the Partnership’s Board of Supervisors on or before the grant date, Restricted Unitsrestricted units issued under the Restricted Unit Plans vest over time with 25% of the Common Units vesting at the end of each of the third and fourth anniversaries of the grant date and the remaining 50% of the Common Units vesting at the end of the fifth anniversary of the grant date. In accordance with an August 6, 2013 amendment to the Restricted Unit Plans, unless otherwise stipulated by the Compensation Committee of the Partnership’s Board of Supervisors on or before the grant date, all restricted unit awards granted after the date of the amendment will vest 33.33% on each of the first three anniversaries of the award grant date. The Restricted Unit Plans participants are not eligible to receive quarterly distributions on, or vote, their respective restricted units until vested. Restricted units cannot be sold or transferred prior to vesting. The value of the restricted unit is established by the market price of the Common Unit on the date of grant, net of estimated future distributions during the vesting period. Restricted units are subject to forfeiture in certain circumstances as defined in the Restricted Unit Plans. Compensation expense for the unvested awards is recognized ratably over the vesting periods and is net of estimated forfeitures.
F-19
Weighted Average | ||||||||
Grant Date Fair | ||||||||
Units | Value Per Unit | |||||||
Outstanding September 27, 2008 | 446,515 | $ | 30.57 | |||||
Granted | 68,799 | 18.10 | ||||||
Forfeited | (28,382 | ) | (31.92 | ) | ||||
Vested | (71,637 | ) | (27.81 | ) | ||||
Outstanding September 26, 2009 | 415,295 | 28.89 | ||||||
Granted | 160,771 | 32.11 | ||||||
Forfeited | (4,693 | ) | (30.31 | ) | ||||
Vested | (90,106 | ) | (30.37 | ) | ||||
Outstanding September 25, 2010 | 481,267 | 29.67 | ||||||
Granted | 136,241 | 39.54 | ||||||
Forfeited | (21,290 | ) | (33.05 | ) | ||||
Vested | (110,795 | ) | (27.82 | ) | ||||
Outstanding September 24, 2011 | 485,423 | $ | 32.71 | |||||
Weighted Average | ||||||||
Grant Date Fair | ||||||||
Units | Value Per Unit | |||||||
Outstanding September 25, 2010 | 481,267 | $ | 29.67 | |||||
Granted | 136,241 | 39.54 | ||||||
Forfeited | (21,290 | ) | (33.05 | ) | ||||
Issued | (110,795 | ) | (27.82 | ) | ||||
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Outstanding September 24, 2011 | 485,423 | 32.71 | ||||||
Granted | 108,674 | 32.60 | ||||||
Forfeited | (12,225 | ) | (30.78 | ) | ||||
Issued | (139,021 | ) | (33.14 | ) | ||||
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Outstanding September 29, 2012 | 442,851 | 32.68 | ||||||
Granted | 200,933 | 23.42 | ||||||
Forfeited | (3,497 | ) | (32.15 | ) | ||||
Issued | (112,660 | ) | (32.01 | ) | ||||
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Outstanding September 28, 2013 | 527,627 | $ | 29.30 | |||||
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As of September 24, 2011,28, 2013, unrecognized compensation cost related to unvested restricted units awarded under the Restricted Unit Plans amounted to $6,320.$6,141. Compensation cost associated with the unvested awards is expected to be recognized over a weighted-average period of 1.8 years. Compensation expense for the Restricted Unit Plans for fiscal 2013, 2012 and 2011 2010was $3,888, $4,059 and 2009 was $3,922, $4,005 and $2,396, respectively.
Long-Term Incentive Plan.Plans. The Partnership has a non-qualified, unfunded long-term incentive plan for officers and key employees (the “LTIP”) which provides for payment, in the form of cash, for an award of equity-based compensation at the end of a three-year performance period. The level of compensation earned under the LTIP in effect on September 28, 2013 (“Existing LTIP”) is based on the market performance of the Partnership’s Common Units on the basis of total return to Unitholders (“TRU”) compared to the TRU of a predetermined peer group comprised of other publicly traded partnerships (master limited partnerships), as approved by the Compensation Committee of the Partnership’s Board of Supervisors, over the same three-year performance period. Compensation expense, which includes adjustments to previously recognized compensation expense for current period changes in the fair value of unvested awards, for fiscal 2013, 2012 and 2011 2010was $1,439, ($340) and 2009 was $1,504, $3,058 and $3,402, respectively. The cash payouts in fiscal 2011, 20102013, 2012 and 2009,2011, which related to the fiscal 2008, 20072010, 2009 and 20062008 awards, were $-0-, $3,336 and $2,697, $2,741respectively.
On August 6, 2013, the Compensation Committee of the Partnership’s Board of Supervisors adopted the 2014 Long-Term Incentive Plan of the Partnership (“2014 LTIP”) as a replacement for Existing LTIP. The 2014 LTIP became effective October 1, 2013. The major difference between the 2014 LTIP and $2,720, respectively.
10. Employee Benefit Plans
Defined Contribution Plan.The Partnership has an employee Retirement Savings and Investment Plan (the “401(k) Plan”) covering most employees. Employer matching contributions relating to the 401(k) Plan are a percentage of the participating employees’ elective contributions. The percentage of the Partnership’s contributions are based on a sliding scale depending on the Partnership’s achievement of annual performance targets. These contributions totaled $1,201, $2,504$1,915, $1,359 and $5,676$1,201 for fiscal 2013, 2012 and 2011, 2010 and 2009, respectively.
Defined Pension and Retiree Health and Life Benefits Arrangements
Pension Benefits.The Partnership has a noncontributory defined benefit pension plan which was originally designed to cover all eligible employees of the Partnership who met certain requirements as to age and length of service. Effective January 1, 1998, the Partnership amended its defined benefit pension plan to provide benefits under a cash balance formula as compared to a final average pay formula which was in effect prior to January 1, 1998. Effective January 1, 2000, participation in the defined benefit pension plan was limited to eligible existing participants on that date with no new participants eligible to participate in the plan. On September 20, 2002, the Board of Supervisors approved an amendment to the defined benefit pension plan whereby, effective January 1, 2003, future service credits ceased and eligible employees receive interest credits only toward their ultimate retirement benefit.
F-20
Retiree Health and Life Benefits.The Partnership provides postretirement health care and life insurance benefits for certain retired employees. Partnership employees hired prior to July 1993 are eligible for postretirement life insurance benefits if they reach a specified retirement age while working for the Partnership. Partnership employees hired prior to July 1993 and who retired prior to March 1998 are eligible for postretirement health care benefits if they reached a specified retirement age while working for the Partnership. Effective January 1, 2000, the Partnership terminated its postretirement health care benefit plan for all eligible employees retiring after March 1, 1998. All active employees who were eligible to receive health care benefits under the postretirement plan subsequent to March 1, 1998, were provided an increase to their accumulated benefits under the cash balance pension plan. The Partnership’s postretirement health care and life insurance benefit plans are unfunded. Effective January 1, 2006, the Partnership changed its postretirement health care plan from a self-insured program to one that is fully insured under which the Partnership pays a portion of the insurance premium on behalf of the eligible participants.
The Partnership recognizes the funded status of pension and other postretirement benefit plans as an asset or liability on the balance sheet and recognizes changes in the funded status in other comprehensive income (loss) in the year the changes occur. The Partnership uses the date of its consolidated financial statements as the measurement date of plan assets and obligations.
F-21
Retiree Health and Life | ||||||||||||||||
Pension Benefits | Benefits | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Reconciliation of benefit obligations: | ||||||||||||||||
Benefit obligation at beginning of year | $ | 157,626 | $ | 157,187 | $ | 20,932 | $ | 21,127 | ||||||||
Service cost | — | — | 7 | 7 | ||||||||||||
Interest cost | 6,822 | 7,503 | 855 | 1,013 | ||||||||||||
Actuarial loss | 9,165 | 9,059 | 631 | 285 | ||||||||||||
Lump sum benefits paid | (6,365 | ) | (7,889 | ) | — | — | ||||||||||
Ordinary benefits paid | (8,129 | ) | (8,234 | ) | (1,530 | ) | (1,500 | ) | ||||||||
Benefit obligation at end of year | $ | 159,119 | $ | 157,626 | $ | 20,895 | $ | 20,932 | ||||||||
Reconciliation of fair value of plan assets: | ||||||||||||||||
Fair value of plan assets at beginning of year | $ | 139,889 | $ | 140,055 | $ | — | $ | — | ||||||||
Actual return on plan assets | 7,503 | 15,957 | — | — | ||||||||||||
Employer contributions | — | — | 1,530 | 1,500 | ||||||||||||
Lump-sum benefits paid | (6,365 | ) | (7,889 | ) | — | — | ||||||||||
Ordinary benefits paid | (8,129 | ) | (8,234 | ) | (1,530 | ) | (1,500 | ) | ||||||||
Fair value of plan assets at end of year | $ | 132,898 | $ | 139,889 | $ | — | $ | — | ||||||||
Funded status: | ||||||||||||||||
Funded status at end of year | $ | (26,221 | ) | $ | (17,737 | ) | $ | (20,895 | ) | $ | (20,932 | ) | ||||
Amounts recognized in consolidated balance sheets consist of: | ||||||||||||||||
Net amount recognized at end of year | $ | (26,221 | ) | $ | (17,737 | ) | $ | (20,895 | ) | $ | (20,932 | ) | ||||
Less: Current portion | — | — | 1,669 | 1,620 | ||||||||||||
Non-current benefit liability | $ | (26,221 | ) | $ | (17,737 | ) | $ | (19,226 | ) | $ | (19,312 | ) | ||||
Amounts not yet recognized in net periodic benefit cost and included in accumulated other comprehensive income (loss): | ||||||||||||||||
Actuarial net (loss) gain | $ | (59,502 | ) | $ | (56,267 | ) | $ | 1,825 | $ | 2,492 | ||||||
Prior service credits | — | — | 2,358 | 2,848 | ||||||||||||
Net amount recognized in accumulated other comprehensive (loss) income | $ | (59,502 | ) | $ | (56,267 | ) | $ | 4,183 | $ | 5,340 | ||||||
Retiree Health and Life Benefits | ||||||||||||||||
Pension Benefits | ||||||||||||||||
2013 | 2012 | 2013 | 2012 | |||||||||||||
Reconciliation of benefit obligations: | ||||||||||||||||
Benefit obligation at beginning of year | $ | 165,906 | $ | 159,119 | $ | 20,232 | $ | 20,895 | ||||||||
Service cost | — | — | 8 | 7 | ||||||||||||
Interest cost | 5,229 | 6,311 | 586 | 802 | ||||||||||||
Actuarial (gain) loss | (11,446 | ) | 14,089 | (1,784 | ) | (74 | ) | |||||||||
Lump sum benefits paid | (3,155 | ) | (5,498 | ) | — | — | ||||||||||
Ordinary benefits paid | (7,903 | ) | (8,115 | ) | (1,288 | ) | (1,398 | ) | ||||||||
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Benefit obligation at end of year | $ | 148,631 | $ | 165,906 | $ | 17,754 | $ | 20,232 | ||||||||
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Reconciliation of fair value of plan assets: | ||||||||||||||||
Fair value of plan assets at beginning of year | $ | 133,873 | $ | 132,898 | $ | — | $ | — | ||||||||
Actual return on plan assets | (2,039 | ) | 14,588 | — | — | |||||||||||
Employer contributions | — | — | 1,288 | 1,398 | ||||||||||||
Lump sum benefits paid | (3,155 | ) | (5,498 | ) | — | — | ||||||||||
Ordinary benefits paid | (7,903 | ) | (8,115 | ) | (1,288 | ) | (1,398 | ) | ||||||||
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Fair value of plan assets at end of year | $ | 120,776 | $ | 133,873 | $ | — | $ | — | ||||||||
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Funded status: | ||||||||||||||||
Funded status at end of year | $ | (27,855 | ) | $ | (32,033 | ) | $ | (17,754 | ) | $ | (20,232 | ) | ||||
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Amounts recognized in consolidated balance sheets consist of: | ||||||||||||||||
Net amount recognized at end of year | $ | (27,855 | ) | $ | (32,033 | ) | $ | (17,754 | ) | $ | (20,232 | ) | ||||
Less: Current portion | — | — | 1,427 | 1,427 | ||||||||||||
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Non-current benefit liability | $ | (27,855 | ) | $ | (32,033 | ) | $ | (16,327 | ) | $ | (18,805 | ) | ||||
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Amounts not yet recognized in net periodic benefit cost and included in accumulated other comprehensive income (loss): | ||||||||||||||||
Actuarial net (loss) gain | $ | (49,986 | ) | $ | (59,397 | ) | $ | 3,683 | $ | 1,899 | ||||||
Prior service credits | — | — | 1,379 | 1,869 | ||||||||||||
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Net amount recognized in accumulated other comprehensive (loss) income | $ | (49,986 | ) | $ | (59,397 | ) | $ | 5,062 | $ | 3,768 | ||||||
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Amounts recognized in other comprehensive income consisted ofincluded net actuarial (gains) losses arising during the period of $7,957($4,126) and $1,181$5,166 for pension benefits for fiscal 20112013 and 2010, respectively. Amounts recognized in other comprehensive income consisted of2012, respectively, and net actuarial losses(gains) arising during the period of $631($1,784) and $285($74) for other postretirement benefits for fiscal 20112013 and 2010,2012, respectively. The losses (gains)amounts in accumulated other comprehensive loss as of September 24, 201128, 2013 that are expected to be recognized as components of net periodic benefit costs during fiscal 20122014 are $5,271expenses of $4,492 and $(465)credits of $(671) for pension and other postretirement benefits, respectively.
Plan Assets.The Partnership’s investment policies and strategies, as set forth in the Investment Management Policy and Guidelines, are monitored by a Benefits Committee comprised of five members of management. The Partnership employs a liability driven investment strategy, which seeks to increase the correlation of the plan’s assets and liabilities to reduce the volatility of the plan’s funded status. This strategy has resulted in an asset allocation that is largely comprised of investments in funds of fixed income securities. The target asset mix is as follows: (i) fixed income securities portion of the portfolio should range between 75%80% and 95%90%; and (ii) equity securities portion of the portfolio should range between 5%10% and 25%20%.
F-22
2011 | 2010 | |||||||
Fixed income securities | 88 | % | 86 | % | ||||
Equity securities | 12 | % | 14 | % | ||||
100 | % | 100 | % | |||||
September | September | |||||||
28, 2013 | 29, 2012 | |||||||
Fixed income securities | 85 | % | 85 | % | ||||
Equity securities | 15 | % | 15 | % | ||||
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100 | % | 100 | % | |||||
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In accordance with current accounting guidance, the Partnership’s valuations include the use of the Partnership’s pension plan assetsfunds’ reported net asset values for commingled fund investments and private investment funds. Commingled funds are measuredvalued at the net asset value for their underlying securities. The Partnership further corroborates the above valuations with observable market data using Levellevel 2 inputs.inputs within the fair value framework. The assets of the defined benefit pension plan have no significant concentration of risk and there are no restrictions on these investments.
The following table describes the measurement of the Partnership’s pension plan assets by asset category:
As of September 24, | As of September 25, | |||||||
2011 | 2010 | |||||||
Short term investments (1) | $ | 1,439 | $ | 1,259 | ||||
Equity securities: (1) (2) | ||||||||
Domestic | 10,823 | 13,042 | ||||||
International | 5,342 | 6,563 | ||||||
Fixed income securities (1) (3) | 115,294 | 119,025 | ||||||
$ | 132,898 | $ | 139,889 | |||||
September 28, | September 29, | |||||||
2013 | 2012 | |||||||
Short term investments (1) | $ | 1,516 | $ | 1,309 | ||||
Equity securities: (1) (2) | ||||||||
Domestic | 11,780 | 13,187 | ||||||
International | 5,959 | 6,727 | ||||||
Fixed income securities (1) (3) | 101,521 | 112,650 | ||||||
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$ | 120,776 | $ | 133,873 | |||||
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(1) | Includes funds which are not publicly traded and are valued at the net asset value of the units provided by the fund issuer. | |
(2) | Includes funds which invest primarily in a diversified portfolio of publicly traded | |
(3) | Includes funds which invest primarily in publicly traded and non-publicly traded, investment grade corporate bonds, U.S. government bonds and asset-backed securities. |
Projected Contributions and Benefit Payments.There are no projected minimum funding requirements under the Partnership’s defined benefit pension plan for fiscal 2012.2014. Estimated future benefit payments for both pension and retiree health and life benefits are as follows:
Retiree | ||||||||
Pension | Health and Life | |||||||
Fiscal Year | Benefits | Benefits | ||||||
2012 | $ | 27,452 | $ | 1,669 | ||||
2013 | 13,804 | 1,603 | ||||||
2014 | 13,303 | 1,540 | ||||||
2015 | 12,494 | 1,466 | ||||||
2016 | 12,079 | 1,382 | ||||||
2017 through 2021 | 51,118 | 5,553 |
Fiscal Year 2014 2015 2016 2017 2018 2019 through 2023 Retiree Health and Pension Life Benefits Benefits 30,745 1,337 12,968 1,270 12,474 1,194 11,033 1,111 10,923 1,036 46,319 3,935
Estimated future pension benefit payments assumes that age 65 or older active and non-active eligible participants in the pension plan that had not received a benefit payment prior to fiscal 20122014 will elect to receive a benefit payment in fiscal 2012.2014. In addition, for all periods presented, estimated future pension benefit payments assumes that participants will elect a lump sum payment in the fiscal year that the participant becomes eligible to receive benefits.
F-23
Pension Benefits | Retiree Health and Life Benefits | |||||||||||||||||||||||
2011 | 2010 | 2009 | 2011 | 2010 | 2009 | |||||||||||||||||||
Service cost | $ | — | $ | — | $ | — | $ | 7 | $ | 7 | $ | 4 | ||||||||||||
Interest cost | 6,822 | 7,503 | 9,487 | 855 | 1,013 | 1,381 | ||||||||||||||||||
Expected return on plan assets | (6,295 | ) | (8,080 | ) | (9,205 | ) | — | — | — | |||||||||||||||
Amortization of prior service credit | — | — | — | (490 | ) | (490 | ) | (490 | ) | |||||||||||||||
Settlement charge | — | 2,818 | — | — | — | — | ||||||||||||||||||
Recognized net actuarial loss | 4,721 | 5,374 | 4,050 | (35 | ) | (65 | ) | (312 | ) | |||||||||||||||
Net periodic benefit costs | $ | 5,248 | $ | 7,615 | $ | 4,332 | $ | 337 | $ | 465 | $ | 583 | ||||||||||||
Pension Benefits | Retiree Health and Life Benefits | |||||||||||||||||||||||
2013 | 2012 | 2011 | 2013 | 2012 | 2011 | |||||||||||||||||||
Service cost | $ | — | $ | — | $ | — | $ | 8 | $ | 7 | $ | 7 | ||||||||||||
Interest cost | 5,229 | 6,311 | 6,822 | 586 | 802 | 855 | ||||||||||||||||||
Expected return on plan assets | (5,281 | ) | (5,665 | ) | (6,295 | ) | — | — | — | |||||||||||||||
Amortization of prior service credit | — | — | — | (490 | ) | (490 | ) | (490 | ) | |||||||||||||||
Recognized net actuarial loss | 5,285 | 5,271 | 4,721 | — | — | (35 | ) | |||||||||||||||||
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Net periodic benefit costs | $ | 5,233 | $ | 5,917 | $ | 5,248 | $ | 104 | $ | 319 | $ | 337 | ||||||||||||
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Actuarial Assumptions.The assumptions used in the measurement of the Partnership’s benefit obligations as of September 24, 201128, 2013 and September 25, 201029, 2012 are shown in the following table:
Retiree Health and | ||||||||||||||||
Pension Benefits | Life Benefits | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Weighted-average discount rate | 4.375 | % | 4.750 | % | 4.000 | % | 4.250 | % | ||||||||
Average rate of compensation increase | n/a | n/a | n/a | n/a |
Pension Benefits | Retiree Health and Life Benefits | |||||||||||||||
2013 | 2012 | 2013 | 2012 | |||||||||||||
Weighted-average discount rate | 4.375 | % | 3.500 | % | 3.750 | % | 3.000 | % | ||||||||
Average rate of compensation increase | n/a | n/a | n/a | n/a | ||||||||||||
Health care cost trend | n/a | n/a | 7.330 | % | 7.530 | % |
The assumptions used in the measurement of net periodic pension benefit and postretirement benefit costs for fiscal 2011, 20102013, 2012 and 20092011 are shown in the following table:
Pension Benefits | Retiree Health and Life Benefits | |||||||||||||||||||||||
2011 | 2010 | 2009 | 2011 | 2010 | 2009 | |||||||||||||||||||
Weighted-average discount rate | 4.750 | % | 5.125 | % | 7.625 | % | 4.250 | % | 5.000 | % | 7.625 | % | ||||||||||||
Average rate of compensation increase | n/a | n/a | n/a | n/a | n/a | n/a | ||||||||||||||||||
Weighted-average expected long-term rate of return on plan assets | 5.000 | % | 6.250 | % | 7.390 | % | n/a | n/a | n/a | |||||||||||||||
Health care cost trend | n/a | n/a | n/a | 7.950 | % | 8.150 | % | 9.000 | % |
Pension Benefits | Retiree Health and Life Benefits | |||||||||||||||||||||||
2013 | 2012 | 2011 | 2013 | 2012 | 2011 | |||||||||||||||||||
Weighted-average discount rate | 3.500 | % | 4.375 | % | 4.750 | % | 3.000 | % | 4.000 | % | 4.250 | % | ||||||||||||
Average rate of compensation increase | n/a | n/a | n/a | n/a | n/a | n/a | ||||||||||||||||||
Weighted-average expected long-term rate of return on plan assets | 4.500 | % | 4.800 | % | 5.000 | % | n/a | n/a | n/a | |||||||||||||||
Health care cost trend | n/a | n/a | n/a | 7.530 | % | 7.740 | % | 7.950 | % |
The discount rate assumption takes into consideration current market expectations related to long-term interest rates and the projected duration of the Partnership’s pension obligations based on a benchmark index with similar characteristics as the expected cash flow requirements of the Partnership’s defined benefit pension plan over the long-term. The expected long-term rate of return on plan assets assumption reflects estimated future performance in the Partnership’s pension asset portfolio considering the investment mix of the pension asset portfolio and historical asset performance. The expected return on plan assets is determined based on the expected long-term rate of return on plan assets and the market-related value of plan assets. The market-related value of pension plan assets is the fair value of the assets. Unrecognized actuarial gains and losses in excess of 10% of the greater of the projected benefit obligation and the market-related value of plan assets are amortized over the expected average remaining service period of active employees expected to receive benefits under the plan.
F-24
10.Multiemployer Pension Plans. As a result of the Inergy Propane Acquisition, the Partnership contributes to multiemployer pension plans (“MEPPs”) in accordance with various collective bargaining agreements covering union employees. As one of the many participating employers in these MEPPs, the Partnership is responsible with the other participating employers for any plan underfunding. During fiscal 2013, the Partnership established an accrual of $7,000 for its estimated obligation to certain MEPPs due to the Partnership’s voluntary partial withdrawal from one such MEPP and full withdrawal from four MEPPs. Due to the uncertainty regarding future factors that could trigger withdrawal liability, including the integration of Inergy Propane, the Partnership is unable to determine the amount and timing of any future withdrawal liability, if any.
The Partnership’s contributions to a particular MEPP are established by the applicable collective bargaining agreements (“CBAs”); however, the required contributions may increase based on the funded status of an MEPP and legal requirements of the Pension Protection Act of 2006 (the “PPA”), which requires substantially underfunded MEPPs to implement a funding improvement plan (“FIP”) or a rehabilitation plan (“RP”) to improve their funded status. Factors that could impact funded status of an MEPP include, without limitation, investment performance, changes in the participant demographics, decline in the number of contributing employers, changes in actuarial assumptions and the utilization of extended amortization provisions.
While no multiemployer pension plan that the Partnership contributed to is individually significant to the Partnership, the table below discloses the three largest MEPPs to which the Partnership contributes. The financial health of a MEPP is indicated by the zone status, as defined by the PPA, which represents the funded status of the plan as certified by the plan’s actuary. Plans in the red zone are less than 65% funded, the yellow zone are between 65% and 80% funded, and green zone are at least 80% funded. Total contributions made by the Partnership to multiemployer pension plans for the fiscal year ended September 28, 2013 are shown below and reflect contributions made from the Inergy Propane Acquisition Date.
PPA Zone Status Pension Fund 2013 2012 Status Contributions of CBA New England Teamsters & Trucking Local 282 Pension Trust Fund Teamsters Industrial Employees Pension Fund Other (d) EIN/ Contributions Pension greater than 5% Plan FIP/RP Contributions of Total Plan Expiration date Number 2013 2012
Industry Pension Fund 04-6372430 Red (a) Red (a) Implemented $ 562 $ 30 No March 2014 - April 2016 11-6245313 Green (b) Green (b) n/a 284 66 No September 2014 22-6099363 Red (c) Red (c) Implemented 179 15 No June 2017 137 48 No n/a $ 1,162 $ 159
(a) | Based on most recent available valuation information for plan years ended September 2012. |
(b) | Based on most recent available valuation information for plan years ended February 2013. |
(c) | Based on most recent available valuation information for plan years ending December 2013. |
(d) | Includes the MEPPs from which the Partnership withdrew in fiscal 2013. |
Additionally, the Partnership contributes to certain multi-employer plans that provide health and welfare benefits and defined annuity plans. Contributions to those plans were $2,040 and $309 for fiscal 2013 and fiscal 2012, respectively.
11. Financial Instruments and Risk Management
Cash and Cash Equivalents.The fair value of cash and cash equivalents is not materially different from their carrying amount because of the short-term maturity of these instruments.
Derivative Instruments and Hedging Activities. The Partnership measures the fair value of its exchange-traded commodity-related options and futures contracts using Level 1 inputs, the fair value of its commodity-related swap contracts and interest rate swaps using Level 2 inputs and the fair value of its over-the-counter commodity-related options contracts using Level 3 inputs. The Partnership’s over-the-counter options contracts are valued based on an internal option model. The inputs utilized in the model are based on publicly available information, as well as broker quotes.
The following summarizes the fair value of the Partnership’s derivative instruments and their location in the consolidated balance sheetsheets as of September 24, 201128, 2013 and September 25, 2010,29, 2012, respectively:
As of September 24, 2011 | As of September 25, 2010 | |||||||||||
Asset Derivatives | Location | Fair Value | Location | Fair Value | ||||||||
Derivatives not designated as hedging instruments: | ||||||||||||
Commodity options | Other current assets | $ | 3,710 | Other current assets | $ | 2,601 | ||||||
Other assets | 612 | Other assets | — | |||||||||
Commodity futures | Other current assets | 1,132 | Other current assets | 22 | ||||||||
$ | 5,454 | $ | 2,623 | |||||||||
Liability Derivatives | Location | Fair Value | Location | Fair Value | ||||||||
Derivatives designated as hedging instruments: | ||||||||||||
Interest rate swaps | Other current liabilities | $ | 2,662 | Other current liabilities | $ | 2,740 | ||||||
Other liabilities | 1,934 | Other liabilities | 3,561 | |||||||||
$ | 4,596 | $ | 6,301 | |||||||||
Derivatives not designated as hedging instruments: | ||||||||||||
Commodity options | Other current liabilities | $ | 2,407 | Other current liabilities | $ | 641 | ||||||
Other liabilities | 69 | Other liabilities | — | |||||||||
Commodity futures | Other current liabilities | — | Other current liabilities | 1,838 | ||||||||
$ | 2,476 | $ | 2,479 | |||||||||
As of September 28, 2013 | As of September 29, 2012 | |||||||||||||||
Location | Fair Value | Location | Fair Value | |||||||||||||
Asset Derivatives | ||||||||||||||||
Derivatives not designated as hedging instruments: | ||||||||||||||||
Commodity-related derivatives | Other current assets | $ | 2,546 | Other current assets | $ | 4,523 | ||||||||||
Other assets | 716 | Other assets | 610 | |||||||||||||
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$ | 3,262 | $ | 5,133 | |||||||||||||
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Location | Fair Value | Location | Fair Value | |||||||||||||
Liability Derivatives | ||||||||||||||||
Derivatives designated as hedging instruments: | ||||||||||||||||
Interest rate swaps | Other current liabilities | $ | 1,307 | Other current liabilities | $ | 2,430 | ||||||||||
Other liabilities | 1,121 | Other liabilities | 3,047 | |||||||||||||
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$ | 2,428 | $ | 5,477 | |||||||||||||
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Derivatives not designated as hedging instruments: | ||||||||||||||||
Commodity-related derivatives | Other current liabilities | $ | 430 | Other current liabilities | $ | 8,720 | ||||||||||
Other liabilities | — | Other liabilities | 22 | |||||||||||||
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$ | 430 | $ | 8,742 | |||||||||||||
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F-25
Fair Value Measurement Using Significant | ||||||||||||||||
Unobservable Inputs (Level 3) | ||||||||||||||||
Fiscal 2011 | Fiscal 2010 | |||||||||||||||
Assets | Liabilities | Assets | Liabilities | |||||||||||||
Beginning balance of over-the-counter options | $ | 1,509 | $ | 30 | $ | 1,675 | $ | 844 | ||||||||
Beginning balance realized during the period | (1,509 | ) | (30 | ) | (1,434 | ) | (844 | ) | ||||||||
Change in the fair value of beginning balance | — | — | (241 | ) | — | |||||||||||
Contracts purchased during the period | 1,780 | 118 | 1,509 | 30 | ||||||||||||
Ending balance of over-the-counter options | $ | 1,780 | $ | 118 | $ | 1,509 | $ | 30 | ||||||||
Fair Value Measurement Using Significant | ||||||||||||||||
Unobservable Inputs (Level 3) | ||||||||||||||||
Fiscal 2013 | Fiscal 2012 | |||||||||||||||
Assets | Liabilities | Assets | Liabilities | |||||||||||||
Beginning balance of over-the-counter options | $ | 5,002 | $ | 1,209 | $ | 1,780 | $ | 118 | ||||||||
Beginning balance realized during the period | (4,400 | ) | (1,182 | ) | (1,168 | ) | (49 | ) | ||||||||
Change in the fair value of beginning balance | (580 | ) | (27 | ) | 1,059 | 120 | ||||||||||
Contracts purchased during the period | 1,825 | — | 3,331 | 1,020 | ||||||||||||
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| |||||||||
Ending balance of over-the-counter options | $ | 1,847 | $ | — | $ | 5,002 | $ | 1,209 | ||||||||
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As of September 24, 2011,28, 2013 and September 29, 2012, the Partnership’s outstanding commodity-related derivatives were scheduled to mature during the following 15 months, and have a weighted average maturity of approximately 4 months. As of September 25, 2010, the Partnership’s outstanding commodity-related derivatives were scheduled to mature during fiscal 2011, and had a weighted average maturity of approximately 35 months.
The effect of the Partnership’s derivative instruments on the consolidated statementstatements of operations for fiscal 2011, 20102013, 2012 and 20092011 are as follows:
Amount of Gains | Gains (Losses) Reclassified from | |||||||||||
(Losses) Recognized in | Accumulated OCI into Income | |||||||||||
OCI | (Effective Portion) | |||||||||||
Derivatives in Cash Flow Hedging Relationships: | (Effective Portion) | Location | Amount | |||||||||
Fiscal 2011 | ||||||||||||
Interest rate swap | $ | (1,177 | ) | Interest expense | $ | (2,881 | ) | |||||
Fiscal 2010 | ||||||||||||
Interest rate swap | $ | (5,706 | ) | Interest expense | $ | (3,597 | ) | |||||
Fiscal 2009 | ||||||||||||
Interest rate swap | $ | (4,079 | ) | Interest expense | $ | (3,088 | ) | |||||
Amount of | ||||||
Unrealized | ||||||
Location of Gains | Gains (Losses) | |||||
(Losses) Recognized in | Recognized in | |||||
Derivatives Not Designated as Hedging Instruments: | Income | Income | ||||
Fiscal 2011 | ||||||
Options | Cost of products sold | $ | (1,517 | ) | ||
Futures | Cost of products sold | 2,948 | ||||
$ | 1,431 | |||||
Fiscal 2010 | ||||||
Options | Cost of products sold | $ | (1,275 | ) | ||
Futures | Cost of products sold | (4,125 | ) | |||
$ | (5,400 | ) | ||||
Fiscal 2009 | ||||||
Options | Cost of products sold | $ | (589 | ) | ||
Futures | Cost of products sold | 2,302 | ||||
$ | 1,713 | |||||
Amount of Gains | Gains (Losses) Reclassified from | |||||||||
(Losses) Recognized in | Accumulated OCI into Income | |||||||||
OCI (Effective | (Effective Portion) | |||||||||
Derivatives in Cash Flow Hedging Relationships: | Portion) | Location | Amount | |||||||
Fiscal 2013 | ||||||||||
Interest rate swap | $ | 584 | Interest expense | $ | (2,465 | ) | ||||
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Fiscal 2012 | ||||||||||
Interest rate swap | $ | (3,561 | ) | Interest expense | $ | (2,680 | ) | |||
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Fiscal 2011 | ||||||||||
Interest rate swap | $ | (1,177 | ) | Interest expense | $ | (2,881 | ) | |||
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Amount of | ||||||||||
Unrealized | ||||||||||
Location of Gains | Gains (Losses) | |||||||||
(Losses) Recognized in | Recognized in | |||||||||
Derivatives Not Designated as Hedging Instruments: | Income | Income | ||||||||
Fiscal 2013 | ||||||||||
Commodity-related derivatives | Cost of products sold | $ | (4,318 | ) | ||||||
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Fiscal 2012 | ||||||||||
Commodity-related derivatives | Cost of products sold | $ | 4,649 | |||||||
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Fiscal 2011 | ||||||||||
Commodity-related derivatives | Cost of products sold | $ | 1,431 | |||||||
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F-26
During fiscal 2011, 20102013, Inergy Services (a subsidiary of Inergy) and 2009, three suppliersTarga Liquids Marketing and Trade (“Targa”) provided approximately 37%, 38%34% and 40%, respectively,12% of our total propane purchases, respectively. No other single supplier accounted for more than 10% of the Partnership’s total propane supply.purchases in fiscal 2013. The Partnership believes that, if supplies from any of these three suppliers were interrupted, it would be able to secure adequate propane supplies from other sources without a material disruption of its operations.
Credit Risk. Exchange-traded futures and options contracts are traded on and guaranteed by the New York Mercantile Exchange (the “NYMEX”)NYMEX and as a result, have minimal credit risk. Futures contracts traded with brokers of the NYMEX require daily cash settlements in margin accounts. The Partnership is subject to credit risk with over- the-counter optionover-the-counter swaps and options contracts entered into with various third parties to the extent the counterparties do not perform. The Partnership evaluates the financial condition of each counterparty with which it conducts business and establishes credit limits to reduce exposure to credit risk based on non-performance. The Partnership does not require collateral to support the contracts.
Bank Debt and Senior Notes.The fair value of the Revolving Credit Facility approximates the carrying value since the interest rates are adjusted quarterly to reflect market conditions. Based upon quoted market prices, the fair value of the Partnership’s 2018 Senior Notes, 2020 Senior Notes and 2021 Senior Notes was $248,500$533,799, $268,125 and $372,143, respectively, as of September 24, 2011.
12. Commitments and Contingencies
Commitments.The Partnership leases certain property, plant and equipment, including portions of the Partnership’s vehicle fleet, for various periods under noncancelable leases. Rental expense under operating leases was $18,868, $17,561$33,036, $23,593 and $17,254$18,868 for fiscal 2013, 2012 and 2011, 2010 and 2009, respectively.
Future minimum rental commitments under noncancelable operating lease agreements as of September 24, 201128, 2013 are as follows:
Minimum | ||||
Lease | ||||
Fiscal Year | Payments | |||
2012 | $ | 15,836 | ||
2013 | 13,346 | |||
2014 | 11,540 | |||
2015 | 8,480 | |||
2016 | 4,993 | |||
2017 and thereafter | 4,709 |
Minimum | ||||
Lease | ||||
Fiscal Year | Payments | |||
2014 | 27,238 | |||
2015 | 20,488 | |||
2016 | 12,770 | |||
2017 | 7,894 | |||
2018 | 5,208 | |||
2019 and thereafter | 5,947 |
Contingencies.
Contingencies.
Legal Matters.As described in Note 2, theThe Partnership’s operations are subject to all operating hazards and risks normally incidental to handling, storing and delivering combustible liquids such as propane. The Partnership has been, and will continue to be, a defendant in various legal proceedings and litigation arising in the ordinary course of business, both as a result of these operating hazards and risks, and as a result of other aspects of its business. In this regard,During the fourth quarter of fiscal 2012, the Partnership entered into an agreement to settle a California action, in which were alleged several claims relating to two fees charged by the Partnership, on a classwide basis in return for the payment of a monetary sum and certain non-monetary consideration, and established an accrual of $4,500 for the estimated cost of the settlement. This settlement, entered into to avoid both the continued expenses and burden of defending that action and the uncertainty inherent in all litigation, was approved by the trial court in May 2013, and the Partnership completed distribution of the settlement proceeds to the class members in the fourth quarter of fiscal 2013. The Partnership is currently is a defendant in a putative suitsclass action in several states.which the court has denied class certification without prejudice. The complaints allege a number of claims, including as toPartnership believes such suit is without merit. In the Partnership’s pricing, fee disclosure and tank ownership, under various consumer statutes,putative class action, the Uniform Commercial Code, common law and antitrust law. Based on the naturePartnership has been successful in eliminating several of the allegations under these suits,claims such that only certain contractual and consumer statute claims remain. The subject matter jurisdiction of the Partnership believes thatcourt to adjudicate certain of the suits are without merit and are thecontractual claims is on appeal. The Partnership is contesting each of these suits vigorously. With respectthis putative class action vigorously and has determined, based on the allegations and discovery to the pending putative suits,date, that no reserve for a loss contingency other than for legal defense fees and expenses based onis required. The Partnership is unable to reasonably estimate the meritspossible loss or range of the allegations, a liability for a loss, contingency is not required.
if any, arising from this litigation.
F-27
14. Public Offerings
On August 10, 2009,May 17, 2013, the Partnership sold 2,200,0002,700,000 Common Units in a public offering at a price of $41.50$48.16 per Common Unit, realizing proceeds of $86,700,$124,684, net of underwriting commissions and other offering expenses. On August 24, 2009,May 22, 2013, following the underwriters’ partial exercise of their over-allotment option, the Partnership sold an additional 230,934405,000 Common Units at $41.50$48.16 per Common Unit, generating additional proceeds of $18,760, net of underwriting commissions. The net proceeds of $9,180. The aggregatefrom the offering, including the net proceeds from the underwriters’ exercise of $95,880, along with cash on hand,their over-allotment option, were used to fundredeem $133,400 of the purchase of $175,000 aggregate principal amount of 2003Partnership’s 2021 Senior Notes pursuant to a cash tender offer.
15. Segment Information
The Partnership manages and evaluates its operations in five operating segments, three of which are reportable segments: Propane, Fuel Oil and Refined Fuels and Natural Gas and Electricity. The chief operating decision maker evaluates performance of the operating segments using a number of performance measures, including gross margins and income before interest expense and provision for income taxes (operating profit). Costs excluded from these profit measures are captured in Corporate and include corporate overhead expenses not allocated to the operating segments. Unallocated corporate overhead expenses include all costs of back office support functions that are reported as general and administrative expenses within the consolidated statements of operations. In addition, certain costs associated with field operations support that are reported in operating expenses within the consolidated statements of operations, including purchasing, training and safety, are not allocated to the individual operating segments. Thus, operating profit for each operating segment includes only the costs that are directly attributable to the operations of the individual segment. The accounting policies of the operating segments are otherwise the same as those described in the summary of significant accounting policies in Note 2.
The propane segment is primarily engaged in the retail distribution of propane to residential, commercial, industrial and agricultural customers and, to a lesser extent, wholesale distribution to large industrial end users. In the residential and commercial markets, propane is used primarily for space heating, water heating, cooking and clothes drying. Industrial customers use propane generally as a motor fuel burned in internal combustion engines that power over-the-road vehicles, forklifts and stationary engines, to fire furnaces and as a cutting gas. In the agricultural markets, propane is primarily used for tobacco curing, crop drying, poultry brooding and weed control.
F-28
The natural gas and electricity segment is engaged in the marketing of natural gas and electricity to residential and commercial customers in the deregulated energy markets of New York and Pennsylvania. Under this operating segment, the Partnership owns the relationship with the end consumer and has agreements with the local distribution companies to deliver the natural gas or electricity from the Partnership’s suppliers to the customer.
Activities in the “all other” category include the Partnership’s service business, which is primarily engaged in the sale, installation and servicing of a wide variety of home comfort equipment, particularly in the areas of heating and ventilation, and activities from the Partnership’s HomeTown Hearth & Grill and Suburban Franchising subsidiaries.
F-29
Year Ended | ||||||||||||
September 24, | September 25, | September 26, | ||||||||||
2011 | 2010 | 2009 | ||||||||||
Revenues: | ||||||||||||
Propane | $ | 929,492 | $ | 885,459 | $ | 864,012 | ||||||
Fuel oil and refined fuels | 139,572 | 135,059 | 159,596 | |||||||||
Natural gas and electricity | 84,721 | 77,587 | 76,832 | |||||||||
All other | 36,767 | 38,589 | 42,714 | |||||||||
Total revenues | $ | 1,190,552 | $ | 1,136,694 | $ | 1,143,154 | ||||||
Operating income: | ||||||||||||
Propane | $ | 203,567 | $ | 230,717 | $ | 268,969 | ||||||
Fuel oil and refined fuels | 11,140 | 11,589 | 17,950 | |||||||||
Natural gas and electricity | 11,667 | 11,629 | 12,791 | |||||||||
All other | (13,750 | ) | (17,995 | ) | (16,346 | ) | ||||||
Corporate | (69,396 | ) | (82,572 | ) | (72,749 | ) | ||||||
Total operating income | 143,228 | 153,368 | 210,615 | |||||||||
Reconciliation to net income: | ||||||||||||
Loss on debt extinguishment | — | 9,473 | 4,624 | |||||||||
Interest expense, net | 27,378 | 27,397 | 38,267 | |||||||||
Provision for income taxes | 884 | 1,182 | 2,486 | |||||||||
Net income | $ | 114,966 | $ | 115,316 | $ | 165,238 | ||||||
Depreciation and amortization: | ||||||||||||
Propane | $ | 19,525 | $ | 17,505 | $ | 15,951 | ||||||
Fuel oil and refined fuels | 4,139 | 3,277 | 4,253 | |||||||||
Natural gas and electricity | 897 | 970 | 1,008 | |||||||||
All other | 111 | 261 | 436 | |||||||||
Corporate | 10,956 | 8,821 | 8,695 | |||||||||
Total depreciation and amortization | $ | 35,628 | $ | 30,834 | $ | 30,343 | ||||||
As of | ||||||||
September 24, | September 25, | |||||||
2011 | 2010 | |||||||
Assets: | ||||||||
Propane | $ | 706,008 | $ | 693,699 | ||||
Fuel oil and refined fuels | 44,973 | 57,681 | ||||||
Natural gas and electricity | 18,675 | 21,552 | ||||||
All other | 3,719 | 3,042 | ||||||
Corporate | 183,084 | 194,940 | ||||||
Total assets | $ | 956,459 | $ | 970,914 | ||||
Year Ended | ||||||||||||
September 28, | September 29, | September 24, | ||||||||||
2013 | 2012 | 2011 | ||||||||||
Revenues: | ||||||||||||
Propane | $ | 1,357,103 | $ | 843,648 | $ | 929,492 | ||||||
Fuel oil and refined fuels | 208,957 | 114,288 | 139,572 | |||||||||
Natural gas and electricity | 79,432 | 67,419 | 84,721 | |||||||||
All other | 58,114 | 38,103 | 36,767 | |||||||||
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Total revenues | $ | 1,703,606 | $ | 1,063,458 | $ | 1,190,552 | ||||||
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Operating income: | ||||||||||||
Propane | $ | 287,473 | $ | 142,548 | $ | 203,567 | ||||||
Fuel oil and refined fuels | (2,799 | ) | 890 | 11,140 | ||||||||
Natural gas and electricity | 11,565 | 6,991 | 11,667 | |||||||||
All other | (26,483 | ) | (17,239 | ) | (13,750 | ) | ||||||
Corporate | (92,780 | ) | (91,533 | ) | (69,396 | ) | ||||||
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Total operating income | 176,976 | 41,657 | 143,228 | |||||||||
Reconciliation to net income: | ||||||||||||
Loss on debt extinguishment | 2,144 | 2,249 | — | |||||||||
Interest expense, net | 95,427 | 38,633 | 27,378 | |||||||||
Provision for income taxes | 607 | 137 | 884 | |||||||||
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Net income | $ | 78,798 | $ | 638 | $ | 114,966 | ||||||
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Depreciation and amortization: | ||||||||||||
Propane | $ | 104,533 | $ | 34,826 | $ | 19,525 | ||||||
Fuel oil and refined fuels | 4,634 | 3,652 | 4,139 | |||||||||
Natural gas and electricity | 198 | 464 | 897 | |||||||||
All other | 638 | 345 | 111 | |||||||||
Corporate | 20,381 | 7,747 | 10,956 | |||||||||
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Total depreciation and amortization | $ | 130,384 | $ | 47,034 | $ | 35,628 | ||||||
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F-30
As of | ||||||||
September 28, | September 29, | |||||||
2013 | 2012 | |||||||
Assets: | ||||||||
Propane | $ | 2,452,909 | $ | 2,505,660 | ||||
Fuel oil and refined fuels | 77,473 | 77,059 | ||||||
Natural gas and electricity | 16,789 | 14,777 | ||||||
All other | 3,860 | 7,342 | ||||||
Corporate | 176,956 | 279,012 | ||||||
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Total assets | $ | 2,727,987 | $ | 2,883,850 | ||||
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SUBURBAN PROPANE PARTNERS, L.P. AND SUBSIDIARIES
Page | ||||||
Schedule II | Valuation and Qualifying | S-2 |
S-1
SUBURBAN PROPANE PARTNERS, L.P. AND SUBSIDIARIES
Balance at | Charged | Balance | ||||||||||||||||||
Beginning | (credited) to Costs | Other | at End | |||||||||||||||||
of Period | and Expenses | Additions | Deductions (a) | of Period | ||||||||||||||||
Year Ended September 26, 2009 | ||||||||||||||||||||
Allowance for doubtful accounts | $ | 6,578 | $ | 3,284 | $ | — | $ | (5,488 | ) | $ | 4,374 | |||||||||
Valuation allowance for deferred tax assets | 48,895 | (2,048 | ) | — | (1,385 | ) | 45,462 | |||||||||||||
Year Ended September 25, 2010 | ||||||||||||||||||||
Allowance for doubtful accounts | $ | 4,374 | $ | 5,141 | $ | — | $ | (4,112 | ) | $ | 5,403 | |||||||||
Valuation allowance for deferred tax assets | 45,462 | (4,806 | ) | — | — | 40,656 | ||||||||||||||
Year Ended September 24, 2011 | ||||||||||||||||||||
Allowance for doubtful accounts | $ | 5,403 | $ | 5,598 | $ | — | $ | (4,041 | ) | $ | 6,960 | |||||||||
Valuation allowance for deferred tax assets | 40,656 | (454 | ) | — | — | 40,202 |
Balance at | Charged | Balance | ||||||||||||||||||
Beginning | (credited) to Costs | Other | at End | |||||||||||||||||
of Period | and Expenses | Additions | Deductions (a) | of Period | ||||||||||||||||
Year Ended September 24, 2011 | ||||||||||||||||||||
Allowance for doubtful accounts | $ | 5,403 | $ | 5,598 | $ | — | $ | (4,041 | ) | $ | 6,960 | |||||||||
Valuation allowance for deferred tax assets | 40,656 | (454 | ) | — | — | 40,202 | ||||||||||||||
Year Ended September 29, 2012 | ||||||||||||||||||||
Allowance for doubtful accounts | $ | 6,960 | $ | 838 | $ | — | $ | (3,451 | ) | $ | 4,347 | |||||||||
Valuation allowance for deferred tax assets | 40,202 | (3,567 | ) | — | — | 36,635 | ||||||||||||||
Year Ended September 28, 2013 | ||||||||||||||||||||
Allowance for doubtful accounts | $ | 4,347 | $ | 6,717 | $ | — | $ | (4,278 | ) | $ | 6,786 | |||||||||
Valuation allowance for deferred tax assets | 36,635 | 9,771 | — | — | 46,406 |
(a) | Represents amounts that did not impact earnings. |
S-2