Delaware | | | | Delaware | | 22-3410353 | (State or other jurisdiction of | | (I.R.S. Employer | incorporation or organization) | | (I.R.S. Employer
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. Yes x☒ No ¨☐ Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨☐ No x☒ Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x☒ No ¨☐ Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x☒ No ¨☐ Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨☒ 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 | ☐ | ¨ (do(do not check if a smaller reporting company) | | 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 ¨☐ No x☒ The aggregate market value as of March 29, 201426, 2016 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 ($40.8930.01 per unit), was approximately $2,465,914,000.$1,823,192,000. | | | Documents Incorporated by Reference: None | | Total number of pages (excluding Exhibits): 141118 |
SUBURBAN PROPANE PARTNERS, L.P. AND SUBSIDIARIES INDEX TO ANNUAL REPORT ON FORM 10-K
DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS 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, and Section 21E of the Securities Exchange Act of 1934, 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: The impact of weather conditions on the demand for propane, fuel oil and other refined fuels, natural gas and electricity; Volatility in the unit cost of propane, fuel oil and other refined fuels, and natural gas and electricity, the impact of the Partnership’s hedging and risk management activities, and the adverse impact of price increases on volumes sold as a result of customer conservation; The cost savings expected from the Partnership’s acquisition of the retail propane operations formerly owned by Inergy, L.P. (the “Inergy Propane Acquisition”) may not be fully realized or realized within the expected time frame;
The costs of integrating the business acquired in the Inergy Propane Acquisition into the Partnership’s existing operations may be greater than expected;
The ability of the Partnership to compete with other suppliers of propane, fuel oil and other energy sources; The impact on the price and supply of propane, fuel oil and other refined fuels from the political, military or economic instability of the oil producing nations, global terrorism and other general economic conditions; The ability of the Partnership to acquire sufficient volumes of, and the costs to the Partnership of acquiring, transporting and storing, propane, fuel oil and other refined fuels; The ability of the Partnership to acquire and maintain reliable transportation for its propane, fuel oil and other refined fuels; The ability of the Partnership to retain customers or acquire new customers; The impact of customer conservation, energy efficiency and technology advances on the demand for propane, fuel oil and other refined fuels, natural gas and electricity; The ability of management to continue to control expenses; The impact of changes in applicable statutes and government regulations, or their interpretations, including those relating to the environment and global warming,climate change, derivative instruments and other regulatory developments on the Partnership’s business; The impact of changes in tax laws that could adversely affect the tax treatment of the Partnership for income tax purposes; The impact of legal proceedings on the Partnership’s business; The impact of operating hazards that could adversely affect the Partnership’s operating results to the extent not covered by insurance; The Partnership’s ability to make strategic acquisitions and successfully integrate them, including but not limited to Inergy Propane;them; The impact of current conditions in the global capital and credit markets, and general economic pressures; The operating, legal and regulatory risks Suburbanthe Partnership may face; and Other risks referenced from time to time in filings with the Securities and Exchange Commission (“SEC”) and those factors listed or incorporated by reference into this Annual Report under “Risk Factors.” 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.
PART I
PART I 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 Magazine dated February 2014,2016, that we are the third largest retail marketer of propane in the United States, measured by retail gallons sold in the calendar year 2013.2015. As of September 27, 2014,24, 2016, we were serving the energy needs of approximately 1.21.1 million residential, commercial, industrial and agricultural customers through approximately 710675 locations in 41 states with operations principally concentrated in the east and west coast regions of the United States, includingas well as portions of the midwest region of the United States and Alaska. We sold approximately 530.7414.8 million gallons of propane and 49.130.9 million gallons of fuel oil and refined fuels to retail customers during the year ended September 27, 2014.24, 2016. 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 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 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 was 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., which conducts a portion of our service work and appliance and parts business. Our 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 “Corporate Entities”) and, as such, are subject to corporate level income tax. Suburban Energy Finance 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 Corp. 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 commenced operations in March 1996 in connection with the Partnership’s initial public offering of Common Units. We currently file Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q and current reports on Form 8-K with the SEC. You may read and receive copies of any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Any information filed by us is also available on the SEC’s EDGAR database atwww.sec.gov. 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 27, 2014,24, 2016, each of the Quarterly Reports on 1
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. The information contained on our website is not included as part of, or incorporated by reference into, this Annual Report on Form 10-K. 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. In connection with the Inergy Propane Acquisition, we have developed, and are implementing, a detailed integration plan to combine the best practices of the two companies while, at the same time, continuingWe will continue to pursue operational efficiencies and operational excellence. Our strategy will include continuing to execute on our integration plans andwhile staying focused on providing exceptional service to the combinedour customer base. We will pursue opportunities to drive operational efficiencies across a broader geography. Our systems platform is advanced and scalable and we will seek to leverage that technology for enhanced routing, forecasting and customer relationship management, as well as centralizing certain back office functions within the former Inergy Propane operations.management. 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. We have made investments in training our people both on techniques to provide exceptional customer service to our existing customer base, as well as advanced sales training focused on growing our customer base. 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. We are very patient and deliberate in evaluating acquisition candidates. Consistent with this strategy, the Inergy Propane Acquisition, completed on August 1, 2012, was a transformative event for Suburban by expanding our geographic reach, doubling the size of our customer base and providing us with opportunities to achieve operational synergies by combining operations in overlapping territories and implementing our operating model and systems platform on a much larger business. 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. Business Segments We manage and evaluate our operations in fivefour 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 by‑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 stand‑alone energy sources. Propane use falls into three broad categories: residential and commercial applications; 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 over‑the‑road vehicles, forklifts and stationary engines, to fire furnaces, as a cutting gas and in other process applications. In the agricultural market, propane is primarily used for tobacco curing, crop drying, poultry brooding and weed control. 2
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 700660 locations in 41 states as of September 27, 2014.24, 2016. Our operations are principally concentrated in the east and west coast regions of the United States, includingas well as portions of the midwest region of the United States and Alaska. As of September 27, 2014,24, 2016, we serviced approximately 1,027,000942,000 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 proprietary 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 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 97%95% of the propane gallons sold by us in fiscal 20142016 were to retail customers: 49%45% to residential customers, 26%27% to commercial customers, 7%9% to industrial customers, 5% to agricultural customers and 13%14% to other retail users. The balance of approximately 3%5% of the propane gallons sold by us in fiscal 20142016 was for risk management activities and wholesale customers. No single customer accounted for 10% or more of our propane revenues during fiscal 2014.2016. Retail deliveries of propane are usually made to customers by means of bobtail and rack trucks. Propane is pumped from bobtail trucks, which have capacities typically ranging from 2,1252,400 gallons to 2,9753,500 gallons of propane, into a stationary storage tank on the customers’ premises. The capacity of these storage tanks ranges from approximately 100 gallons to approximately 1,200 gallons, with a typical tank having a capacity of 300 to 400 gallons. As is common in the propane industry, we own a significant portion of the storage tanks located on our customers’ premises. We also deliver propane to retail customers in portable cylinders, which typically have a capacity of 5 to 35 gallons. When these cylinders are delivered to customers, empty cylinders are refilled in place or transported for replenishment at our distribution locations. We also deliver propane to certain other bulk end users in larger trucks known as transports, which have an average capacity of approximately 9,000 gallons. End users receiving transport deliveries include industrial customers,large-scale large‑scale heating accounts, such as local gas utilities that use propane as a supplemental fuel to meet peak load delivery requirements, and large agricultural accounts that use propane for crop drying. Supply Our propane supply is purchased from approximately 5340 oil companies and natural gas processors at approximately 190180 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 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. However, during the fiscal 2014 heating season, we were adversely affected by supply constraints resulting from industry-wide supply shortages and logistics issues involving propane transportation sourcing and costs. Nevertheless, through relationships with our suppliers and extraordinary efforts by our supply and logistics personnel, we were able to effectively manage the challenging environment in fiscal 2014 without a material disruption in supply. Such supply shortages and logistics issues were not repeated during fiscal 2015 or fiscal 2016. 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 2015.2017. During fiscal 2014,2016, Crestwood MidstreamEquity Partners L.P. (“Crestwood”), Targa Liquids Marketing and Trade LLC (“Targa”) and, Enterprise Products Partners L.P. (“Enterprise”) and Phillips 66 Company (“Phillips”) provided approximately 19%, 14%, 13% and 13%10% of our total propane purchases, respectively. No other single supplier accounted for more than 10% of our propane purchases in fiscal 2014.2016. The availability of our propane supply is dependent on several factors, including the severity of winter weather, the magnitude of competing demands for available supply (e.g., crop drying and exports), the availability of 3
transportation and storage infrastructure and the price and availability of competing fuels, such as natural gas and fuel oil. We believe that if supplies from Crestwood, Enterprise, Targa or EnterprisePhillips 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 and transporting such propane might be higher and, at least on a short-term basis, our margins could be affected. Approximately 94%91% of our total propane purchases were from domestic suppliers in fiscal 2014.2016. 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 Elk Grove, 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 27, 2014,24, 2016, the majority of ourthe storage capacity at our facility in Elk Grove, California was leased to third parties. Competition According to the US Census Bureau’s 20132015 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. Propane is more expensive than natural gas on an equivalent British Thermal Unit (“BTU”) basis in locations serviced by natural gas, but it is an alternative or supplement to natural gas in rural and suburban areas where natural gas is unavailable or portability of product is required. Historically, the expansion of natural gas into traditional propane markets has been inhibited by the capital costs required to expand pipeline and retail distribution systems. Although the recent extension of natural gas pipelines to previously unserved geographic areas tends to displace propane distribution in those areas, we believe new opportunities for propane sales may arise as new neighborhoods are developed in geographically remote areas. However, over the last few years, fewer new housing developments have been started in our service areas as a result of recent economic circumstances. The increasing availability of natural gas extracted from shale deposits in the United States may accelerate the extension of natural gas pipelines in the future. 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 in20122014 Sales of Natural Gas Liquids and Liquefied Refinery Gases, as published by the American Petroleum Institute in December 2013,January 2016, andLP/Gas Magazine dated February 2014,2016, the ten largest retailers, including us, account for approximately 44%36% of the total retail sales of propane 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 57,00048,000 residential and commercial customers primarily in the northeast region of the United States. Sales of fuel oil and refined fuels for fiscal 20142016 amounted to 49.130.9 million gallons. Approximately 66% of the fuel oil and refined fuels gallons sold by us in fiscal 20142016 were to residential customers, principally for home heating, 8%7% were to commercial customers, and 7%6% to other users. Sales of diesel and gasoline accounted for the remaining 19%21% of total volumes sold in this segment during fiscal 2014.2016. 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. 4
Approximately 41%45% of our fuel oil customers receive their fuel oil under an automatic delivery system. These deliveries are scheduled through proprietary 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 2014.2016. Supply 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 14 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 approximately 2530 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 2015.2017. 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 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 overapproximately 80,000 natural gas and electricity customers in New York and Pennsylvania. During fiscal 2014,2016, we sold approximately 4.32.8 million dekatherms of natural gas and 476.2443.3 million kilowatt hours of electricity through the natural gas and electricity segment. Approximately 83%86% 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 are purchased through the 5
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. All Other We sell, install and service various types of whole-house heating products, air cleaners, humidifiers 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 two‑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” and “Suburban Cylinder Express.Propane.” 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” 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. Government Regulation; Environmental, Health and Safety Matters 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 or monitoring 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 or may have been 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 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. 6
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, 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, groundwater and/or groundwater contaminationother impacts 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 (now known as Crestwood Equity Partners LP) is contractually obligated to indemnify us for the costs associated with the investigation, monitoring, remediation and/or resolution of identified conditions. As of September 27, 2014,24, 2016, we had accrued environmental liabilities of $0.6 million representing the total estimated future liability for remediation and monitoring of all of our properties. Estimating the extent of our responsibility at a particular site, and the method and ultimate cost of remediation and monitoring of that site, requires making numerous assumptions. As a result, the ultimate cost to remediate and monitor 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, or the extent to which such additional liabilities would be subject to the contractual indemnification of Inergy. 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/installation and 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. With respect to the transportation of propane, distillates and gasoline by truck, we are subject to regulations promulgated under various Federal statutes, including the Federal Motor Carrier Safety Improvement SafetyAct and the Hazardous Materials Transportation Act. These laws and regulations cover the transportation of hazardous materials and are administered, respectively, by the Federal Motor Carrier Safety Administration and the Pipeline and Hazardous Materials Safety Administration of the United States Department of Transportation (“DOT”), or similar state agencies. We conduct ongoing training programs to help ensure that our operations are in compliance with these and other applicable safety laws and regulations. We maintain various permits that are necessary to operate our facilities, some of which may be material to our operations. In compliance with the DOT’s pipeline safety regulations for “jurisdictional” propane systems that serve multiple customers, we provide training and written instruction for our employees, provide customers with periodic awareness notices and safety information, have established written procedures to minimize the hazards resulting from gas pipeline emergencies and keep records of inspections. We believe that the procedures currently in effect at all of our facilities for the handling, storage, transportation and distribution of propane, distillates and gasoline are consistent with industry standards and are in compliance, in all material respects, with applicable laws and regulations.regulations concerning the handling, storage, transportation and distribution of propane, distillates and gasoline. TheOur operations are subject to workplace safety standards under the Federal Occupational Safety and Health Act of 1970 (OSHA) and comparable state laws that regulate the protection of worker health and safety. Compliance with these standards is monitored through required workplace injury and illness recordkeeping, and reporting. We believe that our operations are in compliance, in all material respects, with applicable worker health and safety standards. We are also subject to laws and regulations governing the security of hazardous materials, including propane, under the Federal Homeland Security Act of 2002, as administered by the Department of Homeland Security (“DHS”) has published regulations under 6 CFR Part 27. The DHS promulgated the Chemical Facility Anti-Terrorism Standards.Standards (“CFATS”) regulation to identify and secure chemical facilities that present the greatest security risk using a risk-based tiering structure. We have a number of facilities registered with the DHS. BecauseAs a result of the CFATS Act of 2014, the DHS developed a revised tiering methodology for chemical facilities. We will be required to submit revised Top Screen applications for all of our facilities areover the upcoming months. Should the number of our regulated facilities increase, we could incur additional costs for enhanced physical security measures. We currently operating undercannot determine the security programs developed under guidelines issued by the Departmentextent of Transportation, Department of Labor and Environmental Protection Agency, we do not anticipatesuch additional costs, if any, that we will incur significant costs in connection with our ongoing efforts to comply with these DHS regulations.may be required.
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 7
and require reporting by certain regulated facilities on an annual basis. The EPA’s authority to regulate GHGs was recentlyhas been upheld by the U.S. Supreme Court. Both Houses of the United States Congress also have considered adopting legislation to reduce emissions of GHGs. Although Congress has not yet enacted federal climate change legislation, numerous states and municipalities have adopted laws and policies on climate change. The adoption of federal, state or statelocal 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 climate 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. On July 21, 2010, theThe Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) was signed into law. The Dodd-Frank Act regulatessignificantly increased regulation of, and restrictions on, derivative transactions whichto include certain instruments used by the Partnership for risk management activities.
ThePursuant to the Dodd-Frank Act, requires the Commodity Futures Trading Commission (the “CFTC”) and the SEC have implemented, and continue 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 requires, or 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.
Required transactional margins,We are subject to certain regulatory requirements as a result of the Dodd-Frank Act and the implementing regulations and may be indirectly affected by regulatory requirements imposed on our derivatives counterparties. Transactional, margin, capital, recordkeeping, reporting, clearing and settlement as a result of legislation (such as the Dodd-Frank Act) and related existing and proposed administrative rulemakingother requirements may increase our operational and transactional cost of entering into and maintaining derivatives contracts and may adversely affect the number and/or creditworthiness of derivatives counterparties available to us. If we were to reduce our use of derivatives as a result of legislation and regulations,regulatory burdens or otherwise, our results of operations maycould become more volatile and our cash flow maycould be less predictable.
Many of the states in which we do business have passed laws prohibiting “unfair or deceptive practices” in transactions between consumers and sellers of products used for residential purposes, which give the Attorney General or other officials of that state the authority to investigate alleged violations of those laws. From time to time, we receive inquiries or requests for additional information under these laws from the offices of Attorneys General or other government officials in connection with the sale of our products to residential customers. Based on information to date, and because our policies and business practices are designed to comply with all applicable laws, we do not believe that the costs or liabilities associated with such inquiries or requests will result in a material adverse effect on our financial condition or results of operations; however, there can be no assurance that our financial condition or results of operations may not be materially and adversely affected as a result of current or future government investigations or civil litigation derived therefrom. Employees As of September 27, 2014,24, 2016, we had 3,7963,417 full time employees, of whom 708642 were engaged in general and administrative activities (including fleet maintenance), 3734 were engaged in transportation and product supply activities and 3,0512,741 were customer service center employees. As of September 27, 2014, 12124, 2016, 70 of our employees were represented by 169 different local chapters of labor unions. We believe that our relations with both our union andnon-union non‑union employees are satisfactory. From time to time,In addition, we hire temporary workers to meet peak seasonal demands. Investing in our common unitsCommon 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 8
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 unitsCommon Units would likely decline and you might lose part or all of the value in our common units.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. See “Disclosure Regarding Forward-Looking Statements” above. Risks Related to Our Business and Industry 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. Actual weather conditions can vary substantially from year to year, significantly affecting our financial performance. For example, average temperatures in our service territories were 17% warmer than normal, 2% warmer than normal and 3% colder than normal and 4% and 14% warmer than normal for fiscal 2014,2016, fiscal 20132015 and fiscal 2012,2014, respectively, as measured by the number of heating degree days reported by the National Oceanic and Atmospheric Administration (“NOAA”). Furthermore, variations in weather in one or more regions in which we operate can significantly affect the total volume of propane, fuel oil and other refined fuels and natural gas we sell and, consequently, our results of operations. Variations in the weather in the northeast, where we have a greater concentration of propane accounts and substantially all of our fuel oil and natural gas operations, generally have a greater impact on our operations than variations in the weather in other markets. We can give no assurance that the weather conditions in any quarter or year will not have a material adverse effect on our operations, or that our available cash will be sufficient to pay principal and interest on our indebtedness and distributions to Unitholders. Sudden increases in our costs to acquire and transport 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, or our inability to obtain adequate supplies of such products from alternative 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 costs to acquire and transport product and retail sales price. Propane, fuel oil and other refined fuels and natural gas are commodities, and the availability of those products, and the unit prices we need to pay to acquire and transport those products, are subject to volatile changes in response to changes in production and supply or other market conditions over which we have no control, including the severity of winter weather, the price and availability of competing alternative energy sources, competing demands for the products (including for export) and infrastructure (including highway, rail, pipeline and refinery) constraints. Our supply of these products from our usual sources may be interrupted due to these and other reasons that are beyond our control, necessitating the transportation of product, if it is available at all, by truck, rail car or other means from other suppliers in other areas, with resulting delay in receipt and delivery to customers and increased expense. As a result, our costs of acquiring and transporting alternative supplies of these products to our facilities 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 and transportation costs of propane, fuel oil and other refined fuels and natural gas, these increases could reduce our profitability. In addition, our inability to obtain sufficient supplies of propane, fuel oil and other refined fuels and natural gas in order for us to fully meet our customer demand for these products on a timely basis could adversely affect our revenues, and consequently our profitability. 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. 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 increases in our costs to acquire and transport propane, fuel oil and natural gas 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 9
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. Propane and fuel oil compete with electricity, natural gas and other existing and future sources of energy, some of which are, or may in the future be, less costly for equivalent energy value. For example, natural gas currently is a significantly less expensive source of energy than propane and fuel oil on an equivalent BTU basis. As a result, except for some industrial and commercial applications, propane and fuel oil are generally not economically competitive with natural gas in areas where natural gas pipelines already exist. The gradual expansion of the nation’s natural gas distribution systems has made natural gas available in many areas that previously depended upon propane or fuel oil. We expect this trend to continue, and, with the increasingly abundant supply of natural gas from domestic sources, perhaps accelerate. Propane and fuel oil compete to a lesser extent with each other due to the cost of converting from one to the other. 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 reduction of business activity generally. As a result of thisThis turmoil, especially when coupled with increasing energy prices, may cause our customers mayto experience cash flow shortages which in turn 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 and the rate of mortgage foreclosures 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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Our operating results and ability to generate sufficient cash flow to pay principal and interest on our indebtedness, and to pay distributions to Unitholders, may be affected by our ability to continue to control expenses. 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, groundwater and other environmental media, and the 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. 11
If we are unable to make acquisitions on economically acceptable terms or effectively integrate such acquisitions into our operations, our financial performance may be adversely affected. 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, tothat we can 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. The EPA’s authority to regulate GHGs was recentlyhas been upheld by the U.S. Supreme Court. Both Houses of the United States Congress also have considered adopting legislation to reduce emissions of GHGs. Although Congress has not yet enacted federal climate change legislation, numerous states and municipalities have adopted laws and policies on climate change. The adoption of federal, state or statelocal 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 climate 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. Our use of derivative contracts involves credit and regulatory risk and may expose us to financial loss. From time to time, we enter into hedging transactions to reduce our business risks arising from fluctuations in commodity prices and interest rates. Hedging transactions expose us to risk of financial loss in some circumstances, including if the other party to the contract defaults on its obligations to us or if there is a change in the expected differential between the price of the underlying commodity or financial metric provided in the hedging agreement and the actual amount received. Required transactional margins,Transactional, margin, capital, recordkeeping, reporting, clearing and settlementother requirements imposed on parties to derivatives transactions as a result of legislation (such as the Dodd-Frank Act) and related existing and proposed administrative rulemaking may increase our operational and transactional cost of entering into and maintaining derivatives contracts and may adversely affect the number and/or creditworthiness of derivatives counterparties available to us. If we were to reduce our use of derivatives as a result of legislation and regulations,regulatory burdens or otherwise, our results of operations maycould become more volatile and our cash flow maycould be less predictable.
Because we depend on particular management information systems to effectively manage all aspects of our delivery of propane, a failure in our operational systems or cyber security attacks on any of our facilities, or those of third parties, may adversely affect our financial results. 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. If any of our financial, operational, or other data processing systems fail or have other significant shortcomings, our financial results could be adversely affected. Our financial results also could be adversely affected if an employee or third party causes our operational systems to fail, either as a result of inadvertent error or by deliberately tampering with or manipulating our operational systems. In addition, dependence upon automated systems may further increase the risk that operational system flaws, employee 12
tampering or manipulation of those systems will result in losses that are difficult to detect or recoup, including damage to our reputation. To the extent customer data is hacked or misappropriated, we could be subject to liability to affected persons. Risks Related to the Inergy Propane Acquisition and the Related Transactions We may not be able to successfully complete the integration of 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 need to fully combine and integrate the businesses and operations of Inergy Propane with ours. Although we have developed, and have substantially implemented, a detailed integration plan, the complete integration of two large businesses is a complex and costly process. We continue to devote significant management attention and resources to integrating all of 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 not completed effectively, may preclude realization of the full expected benefits of the transaction.
Our failure to meet the challenges involved in successfully completing the full 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. Although not yet experienced to any significant degree, possible difficulties that may yet arise from our continuing efforts to fully combine our two operations could include, among others:
operating a significantly larger combined company with operations in more geographic areas;
maintaining employee morale and retaining key employees;
developing and implementing employment polices to facilitate workforce integration, and, where applicable, labor and union relations;
preserving important strategic and customer relationships; and
fully integrating the cultures of Suburban and Inergy Propane.
In addition, even if we are able to successfully complete the full 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 have 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. 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 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.
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: the impact of the risks inherent in our business operations, as described above; required principal and interest payments on our debt and restrictions contained in our debt instruments; issuances of debt and equity securities; our ability to control expenses; fluctuations in working capital; capital expenditures; and financial, business and other factors, a number of which will be beyond our control. 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 27, 2014,24, 2016, our long-term debt borrowings consisted of $250.0 million in aggregate principal amount of 7.375% senior notes due March 15, 2020 (excluding unamortized discount of $1.2 million), $346.2 million in aggregate principal amount of 7.375% senior notes due August 1, 2021 (excluding unamortized premium of $22.7$17.0 million), $525.0 million in aggregate principal amount of 5.5% senior notes due June 1, 2024, $250.0 million in aggregate principal amount of 5.75% senior notes due March 1, 2025 and $100.0 million under our $500.0 million 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 common unitsCommon Units if there is, or after giving effect to such distribution, there would be, an event of default under the indentures governing the senior notes.notes and the senior secured revolving credit facility. The amount of distributions that we may make to holders of our common unitsCommon Units is limited by the senior notes, and the amount of distributions that the Operating Partnership may make to us is limited by our revolving credit facility. The revolving credit facility and the senior notes both contain various restrictive and affirmative covenants applicable to us, and the Operating Partnership and its subsidiaries, 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 our consolidated interest coverage ratio, as defined, to be not less than 2.02.5 to 1.0 as of the end of any fiscal quarter (and commencing with the third quarter of fiscal 2014, such minimum ratio is 2.5 to 1.0);quarter; (b) prohibiting our total consolidated leverage ratio, as defined, from being greater than 4.755.5 to 1.0 (or 5.0 to 1.0 during an acquisition period, as defined in the credit agreement governing the credit facility) as of the end of any fiscal quarter; and (c) prohibiting the senior secured consolidated leverage ratio, as defined, of the Operating Partnership from being greater than 3.0 to 1.0 as of the end of any fiscal quarter. Under the indentures governing the senior notes, we 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 our consolidated fixed charge coverage ratio, as defined, is greater than 1.75 to 1. We and the Operating Partnership were in compliance with all covenants and terms of the senior notes and the revolving credit facility as of September 27, 2014.24, 2016. 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 13
beyond our control. As interest expense increases (whether due to an increase in interest rates and/or the size of aggregate outstanding debt), our ability to fund distributions on our Common Units may be impacted, depending on the level of revenue generation, which is not assured. Unitholders have limited voting rights. A Board of Supervisors governs our operations. 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. Unitholders may not have limited liability in some circumstances. 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: a court or government agency determined that we were conducting business in the state but had not complied with the state’s limited partnership statute; or Unitholders’ rights to act together to remove or replace the General Partner or take other actions under our Partnership Agreement are deemed to constitute “participation in the control” of our business for purposes of the state’s limited partnership statute. 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. 14
Tax Risks to Unitholders 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. If 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 partnership will be taxable as a corporation for U.S. federal income tax 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 CongressOn May 5, 2015, the U.S. Treasury Department and the President has considered substantive changes toInternal Revenue Service issued proposed regulations interpreting the definitionscope of qualifying income. Oneincome for publicly traded partnerships by providing industry-specific guidance with respect to activities that will generate qualifying income for purposes of the requirements for such classification is that at least 90%qualifying income requirement. The proposed regulations could modify the amount of our gross income that we are able to treat as qualifying income for each taxable year has been and will be “qualifying income” withinpurposes of the meaningqualifying income requirement. Based on the legislative history of Section 7704 of the Internal Revenue Code. WhetherCode and previous Internal Revenue Service guidance, we will continue to be classified as a partnership in part depends ondo not believe that the proposed regulations should affect our ability to meet thisqualify as a publicly traded partnership or the characterization of the income from our propane activities as qualifying income test inincome. However, there are no assurances that the future.proposed regulations, when published as final regulations, will not take a position that is contrary to our interpretation of Section 7704 of the Internal Revenue Code. We have not requested, and do not plan to request, a ruling from the IRS on this or any other tax matter affecting us. We are unable to predict whether any of these changes, or other proposals, will ultimately be enacted. Any such changes could negatively impact the value of an investment in our 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. If the IRS makes audit adjustments to our income tax returns for tax years beginning after 2017, it (and some states) may collect any resulting taxes (including any applicable penalties and interest) directly from the Partnership, in which case cash available to service debt or to pay distributions to our unitholders, if and when resumed, might be substantially reduced. Pursuant to the Bipartisan Budget Act of 2015, if the IRS makes audit adjustments to our income tax returns for tax years beginning after 2017, it may collect any resulting taxes (including any applicable penalties and interest) directly from us. We will generally have the ability to shift any such tax liability to our unitholders in accordance with their interests in us during the year under audit, but there can be no assurance that we will be able to do so (and will choose to do so) under all circumstances, or that we will be able to (or choose to) effect corresponding shifts in state income or similar tax liability resulting from the IRS adjustment in states in which we do business in the year under audit or in the adjustment year. If we make payments of taxes, penalties and interest resulting from audit adjustments, cash available to service debt or to resume payment of distributions to our unitholders could be reduced. 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.
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A Unitholder’s tax liability could exceed cash distributions on its Common Units. Because our Unitholders are treated as partners, a Unitholder is required to pay U.S. federal income taxes and state and local income taxes on its allocable share of our income, without regard to whether we make cash distributions 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 U.S. federal income tax returns and pay tax on their share of our taxable income. Tax-exempt organizations and foreign persons should consult, and should depend on, their own tax advisors in analyzing the U.S. federal, state, local and foreign income tax and other tax consequences of the acquisition, ownership or disposition of Common Units. The ability of a Unitholder to deduct its share of our losses may be limited. Various limitations may apply to the ability of a Unitholder to deduct its share of our losses. For example, in the case of taxpayers subject to the passive activity loss rules (generally, individuals and closely held corporations), any losses generated by us will only be available to offset our future income and cannot be used to offset income from other activities, including other passive activities or investments. Such unused losses may be deducted when the Unitholder disposes of its entire investment in us in a fully taxable transaction with an unrelated party, such as a sale by a Unitholder of all of its Common Units in the open market. A Unitholder’s share of any net passive income may be offset by unused losses from us carried over from prior years, but not by losses from other passive activities, including losses from other publicly-traded partnerships. 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 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. In addition, because the amount realized will include a holder’s share of our nonrecourse liabilities, if a Unitholder sells its Common Units, such Unitholder may incur a tax liability in excess of the amount of cash it receives from the sale. Reporting of partnership tax information is complicated and subject to audits. We intend to furnish to each Unitholder, within 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 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 that 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.
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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 our common units.Common Units. However, if the IRS were to challenge our proration method, we may be required to change the allocation of items of income, gain, loss and deduction among our Unitholders. Unitholders may have negative tax consequences if we default on our debt or sell assets. 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 capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes. We will be considered to have terminated 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 capital and profits within a twelve-month period. Our 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. In 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 more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. Our termination currently would not affect our treatment as a partnership for U.S. federal income tax purposes, but instead, after our termination we would be treated as a new partnership for U.S. federal income tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred. There are state, local and other tax considerations for our Unitholders. In addition to U.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 U.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 disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those Common Units may not be reportable by the Unitholder and any cash distribution received by the Unitholder as to those Common Units could be fully taxable as ordinary income. Unitholders desiring to ensure their status as partners and avoid the risk of gain recognition from a loan to a short seller should consult their own tax advisors to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their Common Units. ITEM 1B. | UNRESOLVED STAFF COMMENTS |
None.
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ITEM 1B. | UNRESOLVED STAFF COMMENTS |
None. As of September 27, 2014,24, 2016, we owned approximately 73%74% 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 27, 2014,24, 2016, we had a fleet of 127 transport truck tractors, of which we owned 5,1, and 23 railroad tank cars, of which we owned none. In addition, as of September 27, 201424, 2016 we had 1,3471,150 bobtail and rack trucks, of which we owned 51%50%, 139113 fuel oil tankwagons, of which we owned 63%79%, and 1,3601,215 other delivery and service vehicles, of which we owned 54%57%. We lease the vehicles we do not own. As of September 27, 2014,24, 2016, we also owned 950,257approximately 845,000 customer propane storage tanks with typical capacities of 100 to 500 gallons, 69,29458,000 customer propane storage tanks with typical capacities of over 500 gallons and 403,967270,000 portable propane cylinders with typical capacities of five to ten gallons. Litigation Our operations are subject to 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 as a result of these operating hazards and risks, and as a result of other aspects of our business. Although any litigation is inherently uncertain, based on past experience, the information currently available to us, and the amount of our accrued insurance liabilities, we do not believe that currently pending or threatened litigation matters, or known claims or known contingent claims, will have a material adverse effect on our results of operations, financial condition or cash flow. ITEM 4. | MINE SAFETY DISCLOSURES |
None. PART II
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PART II 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 24, 2014, there were 670
| (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, 2016, there were 647 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. |
| | Common Unit Price Range | | | Cash Distribution Declared per | | | | High | | | Low | | | Common Unit | | Fiscal 2016 | | | | | | | | | | | | | First Quarter | | $ | 36.69 | | | $ | 22.69 | | | $ | 0.8875 | | Second Quarter | | | 30.94 | | | | 20.93 | | | | 0.8875 | | Third Quarter | | | 37.10 | | | | 27.77 | | | | 0.8875 | | Fourth Quarter | | | 35.95 | | | | 31.50 | | | | 0.8875 | | | | | | | | | | | | | | | Fiscal 2015 | | | | | | | | | | | | | First Quarter | | $ | 46.05 | | | $ | 40.81 | | | $ | 0.8750 | | Second Quarter | | | 45.87 | | | | 42.55 | | | | 0.8875 | | Third Quarter | | | 44.75 | | | | 39.47 | | | | 0.8875 | | Fourth Quarter | | | 41.14 | | | | 31.00 | | | | 0.8875 | |
| | 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. The amount of distributions that we may make to holders of our Common Units is limited by the senior notes, and the amount of distributions that the Operating Partnership may make to us is limited by our revolving credit facility. See “Risk Factors—We have substantial indebtedness. Our debt agreements may limit our ability to make distributions to Unitholders, as well as our financial flexibility” and “Management’s Discussion and Analysis—Liquidity and Capital Resources.” |
| | 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. |
| | | | | | | | | | | | | | | | Common Unit Price
Range | | | Cash Distribution
Declared per
Common Unit | | | | | High | | | Low | | | Fiscal 2014 | | | | | | | | | | | | | First Quarter | | $ | 48.90 | | | $ | 44.21 | | | $ | 0.8750 | | Second Quarter | | | 47.16 | | | | 39.91 | | | | 0.8750 | | Third Quarter | | | 48.61 | | | | 40.94 | | | | 0.8750 | | Fourth Quarter | | | 46.21 | | | | 41.13 | | | | 0.8750 | | | | | | 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 | |
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. The amount of distributions that we may make to holders of our Common Units is limited by the senior notes, and the amount of distributions that the Operating Partnership may make to us is limited by our revolving credit facility. See “Risk Factors—We have substantial indebtedness. Our debt agreements may limit our ability to make distributions to Unitholders, as well as our financial flexibility” and “Management’s Discussion and Analysis—Liquidity and Capital Resources.”
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.19
(b) Not applicable.
(c) None.
ITEM 6. | SELECTEDSELECTED FINANCIAL DATA |
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 | | | Year Ended | | | | | September 27,
2014 | | September 28,
2013 | | September 29,
2012 (a) | | September 24,
2011 | | September 25,
2010 | | | September 24, 2016 | | | September 26, 2015 | | | September 27, 2014 | | | September 28, 2013 | | | September 29, 2012 (a) | | Statement of Operations Data | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Revenues | | $ | 1,938,257 | | | $ | 1,703,606 | | | $ | 1,063,458 | | | $ | 1,190,552 | | | $ | 1,136,694 | | | $ | 1,046,111 | | | $ | 1,416,979 | | | $ | 1,938,257 | | | $ | 1,703,606 | | | $ | 1,063,458 | | Costs and expenses | | | 1,748,131 | | | 1,526,630 | | | 1,003,885 | | | 1,047,324 | | | 980,508 | | | | 965,474 | | | | 1,239,221 | | | | 1,748,131 | | | | 1,526,630 | | | | 1,003,885 | | Gain on sale of business (b) | | | | 9,769 | | | | — | | | | — | | | | — | | | | — | | Acquisition-related costs (b)(c) | | | — | | | | — | | | 17,916 | | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | 17,916 | | Pension settlement charge (c) | | | — | | | | — | | | | — | | | | — | | | 2,818 | | | Operating income | | | 190,126 | | | 176,976 | | | 41,657 | | | 143,228 | | | 153,368 | | | | 90,406 | | | | 177,758 | | | | 190,126 | | | | 176,976 | | | | 41,657 | | Interest expense, net | | | 83,261 | | | 95,427 | | | 38,633 | | | 27,378 | | | 27,397 | | | | 75,086 | | | | 77,634 | | | | 83,261 | | | | 95,427 | | | | 38,633 | | Pension settlement charge (d) | | | | 2,000 | | | | 2,000 | | | | — | | | | — | | | | — | | Loss on debt extinguishment (d)(e) | | | 11,589 | | | 2,144 | | | 2,249 | | | | — | | | 9,473 | | | | 292 | | | | 15,072 | | | | 11,589 | | | | 2,144 | | | | 2,249 | | Provision for income taxes | | | 767 | | | 607 | | | 137 | | | 884 | | | 1,182 | | | | 588 | | | | 700 | | | | 767 | | | | 607 | | | | 137 | | Net income | | | 94,509 | | | 78,798 | | | 638 | | | 114,966 | | | 115,316 | | | | 14,440 | | | | 84,352 | | | | 94,509 | | | | 78,798 | | | | 638 | | Net income per Common Unit—basic (e) | | | 1.56 | | | 1.35 | | | 0.02 | | | 3.24 | | | 3.26 | | | Net income per Common Unit—diluted (e) | | | 1.56 | | | 1.34 | | | 0.02 | | | 3.22 | | | 3.24 | | | Net income per Common Unit - basic (f) | | | | 0.24 | | | | 1.39 | | | | 1.56 | | | | 1.35 | | | | 0.02 | | Net income per Common Unit - diluted (f) | | | | 0.24 | | | | 1.38 | | | | 1.56 | | | | 1.34 | | | | 0.02 | | Cash distributions declared per unit | | $ | 3.50 | | | $ | 3.50 | | | $ | 3.41 | | | $ | 3.41 | | | $ | 3.35 | | | $ | 3.55 | | | $ | 3.54 | | | $ | 3.50 | | | $ | 3.50 | | | $ | 3.41 | | | | | | | | | | | | | | | | | | | | | | | | Balance Sheet Data | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Cash and cash equivalents | | $ | 92,639 | | | $ | 107,232 | | | $ | 134,317 | | | $ | 149,553 | | | $ | 156,908 | | | $ | 37,341 | | | $ | 152,338 | | | $ | 92,639 | | | $ | 107,232 | | | $ | 134,317 | | Current assets | | | 294,865 | | | 293,322 | | | 337,515 | | | 297,822 | | | 296,427 | | | | 147,299 | | | | 273,413 | | | | 294,865 | | | | 293,322 | | | | 337,515 | | Total assets | | | 2,609,363 | | | 2,727,987 | | | 2,883,850 | | | 956,459 | | | 970,914 | | | | 2,295,969 | | | | 2,485,730 | | | | 2,609,363 | | | | 2,727,987 | | | | 2,883,850 | | Current liabilities | | | 222,266 | | | 233,894 | | | 253,715 | | | 151,514 | | | 164,514 | | | | 205,054 | | | | 210,346 | | | | 222,266 | | | | 233,894 | | | | 253,715 | | Total debt | | | 1,242,685 | | | 1,245,237 | | | 1,422,078 | | | 348,169 | | | 347,953 | | | | 1,238,172 | | | | 1,241,107 | | | | 1,242,685 | | | | 1,245,237 | | | | 1,422,078 | | Total liabilities | | | 1,587,910 | | | 1,598,861 | | | 1,793,351 | | | 598,241 | | | 608,258 | | | | 1,587,738 | | | | 1,587,410 | | | | 1,587,910 | | | | 1,598,861 | | | | 1,793,351 | | Partners’ capital—Common Unitholders | | $ | 1,067,358 | | | $ | 1,176,479 | | | $ | 1,151,606 | | | $ | 418,134 | | | $ | 419,882 | | | Partners' capital - Common Unitholders | | | $ | 754,063 | | | $ | 947,203 | | | $ | 1,067,358 | | | $ | 1,176,479 | | | $ | 1,151,606 | | | | | | | | | | | | | | | | | | | | | | | | Statement of Cash Flows Data | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Cash provided by (used in) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Operating activities | | $ | 225,551 | | | $ | 214,306 | | | $ | 110,973 | | | $ | 132,786 | | | $ | 155,797 | | | $ | 157,108 | | | $ | 324,209 | | | $ | 225,551 | | | $ | 214,306 | | | $ | 110,973 | | Investing activities | | | (16,532 | ) | | (14,663 | ) | | (239,758 | ) | | (19,505 | ) | | (30,111 | ) | | | (53,905 | ) | | | (35,972 | ) | | | (16,532 | ) | | | (14,663 | ) | | | (239,758 | ) | Financing activities | | $ | (223,612 | ) | | $ | (226,728 | ) | | $ | 113,549 | | | $ | (120,636 | ) | | $ | (131,951 | ) | | $ | (218,200 | ) | | $ | (228,538 | ) | | $ | (223,612 | ) | | $ | (226,728 | ) | | $ | 113,549 | | | | | | | | | | | | | | | | | | | | | | | | Other Data | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Depreciation and amortization | | $ | 136,399 | | | $ | 130,384 | | | $ | 47,034 | | | $ | 35,628 | | | $ | 30,834 | | | $ | 129,616 | | | $ | 133,294 | | | $ | 136,399 | | | $ | 130,384 | | | $ | 47,034 | | EBITDA (f)(g) | | | 314,936 | | | 305,216 | | | 86,442 | | | 178,856 | | | 174,729 | | | | 219,730 | | | | 295,980 | | | | 314,936 | | | | 305,216 | | | | 86,442 | | Adjusted EBITDA (f)(g) | | | 338,502 | | | 329,253 | | | 108,536 | | | 179,425 | | | 192,420 | | | | 223,043 | | | | 334,039 | | | | 338,502 | | | | 329,253 | | | | 108,536 | | Capital expenditures—maintenance and growth (g) | | $ | 30,052 | | | $ | 27,823 | | | $ | 17,476 | | | $ | 22,284 | | | $ | 19,131 | | | Capital expenditures - maintenance and growth (h) | | | $ | 38,375 | | | $ | 41,213 | | | $ | 30,052 | | | $ | 27,823 | | | $ | 17,476 | | Retail gallons sold | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Propane | | | 530,743 | | | 534,621 | | | 283,841 | | | 298,902 | | | 317,906 | | | | 414,776 | | | | 480,372 | | | | 530,743 | | | | 534,621 | | | | 283,841 | | Fuel oil and refined fuels | | | 49,071 | | | 53,710 | | | 28,491 | | | 37,241 | | | 43,196 | | | | 30,878 | | | | 41,878 | | | | 49,071 | | | | 53,710 | | | | 28,491 | |
(a) | Fiscal 2012 includes 53 weeks of operations compared to 52 weeks in each of fiscal 2016, 2015, 2014 2013, 2011 and 2010.2013. 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, fiscal 2014, fiscal 2015 and fiscal 2014,2016, 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 |
(b) | On April 22, 2016, we sold certain assets and operations in a non-strategic market of Inergy Propane included within the Notes to the Consolidated Financial Statements section elsewherepropane segment for $26.0 million, including $5.0 million of non-compete consideration that will be received over a five-year period, resulting in this Annual Report.a gain of $9.8 million. |
(b)(c) | Due to the Inergy Propane Acquisition on August 1, 2012 we recorded acquisition-related costs of $17.9 million during fiscal 2012. These costs were primarily attributable to investment banker, legal, accounting and other consulting fees. |
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(c)(d) | We incurred non-cash pension settlement charges of $2.8$2.0 million during fiscal 20102016 and 2015 to accelerate the recognition of actuarial losses in our defined benefit pension plan as a result of the level of lump sum retirement benefit payments made. |
(d)(e) | On May 27, 2014, we repurchased and satisfied and discharged all of our 2018 Senior Notes with net proceeds from the issuance of the 2024 Senior Notes and cash on hand pursuant to a tender offer and redemption. In connection with this tender offer and redemption, we recognized a loss on the extinguishment of debt of $11.6 million consisting of $31.6 million for the redemption premium and related fees, as well as the write-off of $5.3 million and ($25.3) million in unamortized debt origination costs and unamortized premium, respectively. 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 27, 2014, 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, weWe recognized a loss on debt extinguishment of $9.5 million induring 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.following periods: |
On March 3, 2016, we entered into a Second Amended and Restated Credit Agreement (“the “Amended Credit Agreement”) that provides for a five-year $500.0 million revolving credit facility (the “Revolving Credit Facility”), of which $100.0 million was outstanding as of September 24, 2016. As of the end of fiscal 2015, 2014, 2013 and 2012, $100.0 million was outstanding under the revolving credit facility of the previous credit agreement, which was rolled into the Revolving Credit Facility of the Amended Credit Agreement. The Amended Credit Agreement amends and restates the previous credit agreement to, among other things, extend the maturity date from January 5, 2017 to March 3, 2021, reduce the borrowing rate, amend certain affirmative and negative covenants and increase the revolving credit facility from $400.0 million to $500.0 million. In connection with the Amended Credit Agreement, we recognized a non-cash charge of $0.3 million to write-off a portion of unamortized debt origination costs of the previous credit agreement. On February 25, 2015, we repurchased and satisfied and discharged all of our 2020 Senior Notes with net proceeds from the issuance of the 2025 Senior Notes and cash on hand pursuant to a tender offer and redemption. In connection with this tender offer and redemption, we recognized a loss on the extinguishment of debt of $15.1 million consisting of $11.1 million for the redemption premium and related fees, as well as the write-off of $2.9 million and $1.1 million in unamortized debt origination costs and unamortized discount, respectively. On May 27, 2014, we repurchased and satisfied and discharged all of our 2018 Senior Notes with net proceeds from the issuance of the 2024 Senior Notes and cash on hand pursuant to a tender offer and redemption. In connection with this tender offer and redemption, we recognized a loss on the extinguishment of debt of $11.6 million consisting of $31.6 million for the redemption premium and related fees, as well as the write-off of $5.3 million and ($25.3) million in unamortized debt origination costs and unamortized premium, respectively. 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. During fiscal 2012, we amended the then outstanding credit agreement to increase the five-year $250.0 million revolving credit facility to $400.0 million and also to extend the maturity date from June 25, 2013 to January 5, 2017. In connection with the execution of the previous 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 then previous 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. (e)(f) | 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 2000 and 2009 Restricted Unit Plans (which we collectively refer to as the “Restricted Unit Plans” or the “RUP”) to retirement-eligible grantees. The final awards under the 2000 Restricted Unit Plan vested during the first quarter of fiscal 2015. Computations of diluted earnings per Common Unit were performed by dividing net income by the weighted average number of outstanding Common Units and unvested restricted units granted under our Restricted Unit Plans. On May 17, 2013, we sold 2.7 million Common Units in a public offering. On May 22, 2013, following the underwriters’ exercise of their over-allotment option, we sold an additional 0.4 million Common Units. On August 1, 2012, in connection with the Inergy Propane Acquisition, we issued 14.2 million Common Units, and on August 14, 2012, we sold 7.2 million Common Units in a secondary offering. Those Common Units have been included in basic and diluted earnings per common unit from the respective dates of issuance. |
On May 17, 2013, we sold 2.7 million Common Units in a public offering. On May 22, 2013, following the underwriters’ exercise of their over-allotment option, we sold an additional 0.4 million Common Units. On August 1, 2012, in connection with the Inergy Propane Acquisition, we issued 14.2 million Common Units, and on August 14, 2012, we sold 7.2 million Common Units in a secondary offering. The aforementioned Common Units have been included in basic and diluted earnings per Common Unit from the respective dates of issuance. (f)(g) | 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 and other certain items, as applicable, as provided in the table below. Our management uses EBITDA and Adjusted EBITDA as supplemental measures of liquidityoperating performance 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.operating results. EBITDA and Adjusted EBITDA are not recognized terms under accounting principles generally accepted in the United States of America (“US GAAP”)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. |
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The following table sets forth (i) our calculations of EBITDA and Adjusted EBITDA and (ii) a reconciliation of EBITDA and Adjusted EBITDA, as so calculated, to our net cash provided by operating activities (amounts in thousands):EBITDA: | | | | | | | | | | | | Year Ended | | | | | Fiscal
2014 | | Fiscal
2013 | | Fiscal
2012 | | Fiscal
2011 | | Fiscal
2010 | | | September 24, 2016 | | | September 26, 2015 | | | September 27, 2014 | | | September 28, 2013 | | | September 29, 2012 (a) | | Net income | | $ | 94,509 | | | $ | 78,798 | | | $ | 638 | | | $ | 114,966 | | | $ | 115,316 | | | $ | 14,440 | | | $ | 84,352 | | | $ | 94,509 | | | $ | 78,798 | | | $ | 638 | | Add: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Provision for income taxes | | | 767 | | | 607 | | | 137 | | | 884 | | | 1,182 | | | | 588 | | | | 700 | | | | 767 | | | | 607 | | | | 137 | | Interest expense, net | | | 83,261 | | | 95,427 | | | 38,633 | | | 27,378 | | | 27,397 | | | | 75,086 | | | | 77,634 | | | | 83,261 | | | | 95,427 | | | | 38,633 | | Depreciation and amortization | | | 136,399 | | | 130,384 | | | 47,034 | | | 35,628 | | | 30,834 | | | | 129,616 | | | | 133,294 | | | | 136,399 | | | | 130,384 | | | | 47,034 | | | | | | | | | | | | | | | | | | | EBITDA | | | 314,936 | | | | 305,216 | | | | 86,442 | | | | 178,856 | | | | 174,729 | | | | 219,730 | | | | 295,980 | | | | 314,936 | | | | 305,216 | | | | 86,442 | | Unrealized (non-cash) (gains) losses on changes in fair value of derivatives | | | (306 | ) | | | 4,318 | | | | (4,649 | ) | | | (1,431 | ) | | | 5,400 | | | | 1,190 | | | | (1,855 | ) | | | (306 | ) | | | 4,318 | | | | (4,649 | ) | Gain on sale of business | | | | (9,769 | ) | | | — | | | | — | | | | — | | | | — | | Multi-employer pension plan withdrawal charge | | | | 6,600 | | | | 11,300 | | | | — | | | | 7,000 | | | | — | | Product liability settlement | | | | 3,000 | | | | — | | | | — | | | | — | | | | — | | Pension settlement charge | | | | 2,000 | | | | 2,000 | | | | — | | | | — | | | | — | | Loss on debt extinguishment | | | | 292 | | | | 15,072 | | | | 11,589 | | | | 2,144 | | | | 2,249 | | Integration-related costs | | | 12,283 | | | | 10,575 | | | | — | | | | — | | | | — | | | | — | | | | 11,542 | | | | 12,283 | | | | 10,575 | | | | — | | Loss on debt extinguishment | | | 11,589 | | | | 2,144 | | | | 2,249 | | | | — | | | | 9,473 | | | Multi-employer pension plan withdrawal charge | | | — | | | | 7,000 | | | | — | | | | — | | | | — | | | Acquisition-related costs | | | — | | | | — | | | | 17,916 | | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | 17,916 | | Loss on legal settlement | | | — | | | | — | | | | 4,500 | | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | 4,500 | | Loss on asset disposal | | | — | | | | — | | | | 2,078 | | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | 2,078 | | Severance charges | | | — | | | | — | | | | — | | | | 2,000 | | | | — | | | Pension settlement charge | | | — | | | | — | | | | — | | | | — | | | | 2,818 | | | | | | | | | | | | | | | | | | | | Adjusted EBITDA | | | 338,502 | | | | 329,253 | | | | 108,536 | | | | 179,425 | | | | 192,420 | | | $ | 223,043 | | | $ | 334,039 | | | $ | 338,502 | | | $ | 329,253 | | | $ | 108,536 | | Add (subtract): | | | | | | | | | | | | Provision for income taxes | | | (767 | ) | | | (607 | ) | | | (137 | ) | | | (884 | ) | | | (1,182 | ) | | Interest expense, net | | | (83,261 | ) | | | (95,427 | ) | | | (38,633 | ) | | | (27,378 | ) | | | (27,397 | ) | | Unrealized (non-cash) gains (losses) on changes in fair value of derivatives | | | 306 | | | | (4,318 | ) | | | 4,649 | | | | 1,431 | | | | (5,400 | ) | | Integration-related costs | | | (12,283 | ) | | | (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 | | | 7,390 | | | | 3,888 | | | | 4,059 | | | | 3,922 | | | | 4,005 | | | (Gain) loss on disposal of property, plant and equipment, net | | | (521 | ) | | | (3,543 | ) | | | (727 | ) | | | (2,772 | ) | | | 38 | | | Changes in working capital and other assets and liabilities | | | (23,815 | ) | | | 2,635 | | | | 55,642 | | | | (18,958 | ) | | | (6,687 | ) | | | | | | | | | | | | | | | | | | | Net cash provided by operating activities | | $ | 225,551 | | | $ | 214,306 | | | $ | 110,973 | | | $ | 132,786 | | | $ | 155,797 | | | | | | | | | | | | | | | | | | | |
(g)(h) | 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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ITEM 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
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 our costs to acquire and transport products. 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. Changes in our costs to acquire and transport products 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 acquisition and transportation cost increases fully or immediately, particularly when such costs increase rapidly. Therefore, average retail sales prices can vary significantly from year to year as our costs fluctuate with the propane, fuel oil, crude oil and natural gas commodity markets and infrastructure conditions. In addition, periods of sustained higher commodity and/or transportation 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 two‑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 the following fiscal year first quarter. Weather 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.
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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 swap agreements with third parties, and use futures and options 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 options 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 swap contracts are generally settled at the expiration of the contract through a net settlement mechanism. 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 fivesix 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—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 1.21.1 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. Pension and Other Postretirement Benefits. We estimate the rate of return on plan assets, the discount rate used to estimate the present value of future benefit obligations and the expected cost of future health care benefits in determining our annual pension and other postretirement benefit costs. In October 2014, the Society of Actuaries (“SOA”) issued new mortality tables (RP-2014) and a new mortality improvement scale (MP-2014). We use SOA and other actuarial life expectancy information when developing the annual mortality assumptions for our pension and postretirement benefit plans, which are used to measure net periodic benefit costs and the obligation under these plans. While we believe that our assumptions are appropriate, significant differences in our actual experience or significant changes in market conditions may materially affect our pension and other postretirement benefit obligations and our future expense. With other assumptions held constant, an increase or decrease of 100 basis points in the discount rate would have an immaterial impact on net pension and postretirement benefit costs. See “Liquidity and Capital Resources—Pension Plan Assets and Obligations” below for additional disclosure regarding pension benefits.
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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 self‑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. We contribute to multi-employer pension plans (“MEPPs”) in accordance with various collective bargaining agreements covering union employees. As one of the many participating employers in these MEPPs, we are responsible with the other participating employers for any plan underfunding. Due to the uncertainty regarding future factors that could impact the withdrawal liability, we are unable to determine the timing of the payment of the future withdrawal liability, or additional future withdrawal liability, if any. Fair Values of Acquired Assets and Liabilities.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 Net income for fiscal 2014 amounted to $94.52016 was $14.4 million, or $1.56$0.24 per Common Unit, compared to $78.8$84.4 million, or $1.35$1.39 per Common Unit, in fiscal 2013. Earnings before interest, taxes, depreciation2015. Net income and amortization (“EBITDA”)EBITDA (as defined and reconciled below) for fiscal 2014 amounted2016 included: (i) a $9.8 million gain from the sale of certain assets and operations in a non-strategic market of the propane segment; (ii) a $6.6 million charge related to $314.9the voluntary full withdrawal from a MEPP covering certain employees acquired in the Inergy Propane Acquisition; (iii) a $3.0 million comparedcharge related to $305.2 million for fiscal 2013.the settlement of a product liability matter; (iv) a pension settlement charge of $2.0 million; and (v) a loss on debt extinguishment of $0.3 million. Net income and EBITDA for fiscal 20142015 included: (i) $12.3a loss on debt extinguishment of $15.1 million; (ii) $11.5 million in expenses related to the ongoing integration of Inergy Propane and (ii) a loss on debt extinguishment of $11.6 million. Net income and EBITDA for fiscal 2013 included: (i) $10.6 million in expenses related to the ongoing integration of Inergy Propane; (ii) $7.0(iii) an $11.3 million in chargescharge related to ourthe voluntary partial withdrawal from multi-employer pension plansa MEPP covering certain employees acquired in the Inergy Propane Acquisition; and (iii)(iv) a loss on debt extinguishmentpension settlement charge of $2.1$2.0 million. Excluding the effects of these charges, as well as the foregoing items and unrealized (non-cash) mark-to-market adjustments on derivative instruments in both years, Adjusted EBITDA (as defined and reconciled below) amounted to $338.5$223.0 million forin fiscal 2014, an increase of $9.2 million, or 2.8%,2016, compared to Adjusted EBITDA of $329.3$334.0 million in fiscal 2013.2015. Retail propane gallons sold forin fiscal 20142016 decreased 3.965.6 million gallons, or 0.7%13.7%, to 530.7414.8 million gallons from 534.6 million gallons in fiscal 2013.gallons. Sales of fuel oil and other refined fuels also decreased 8.6%11.0 million gallons, or 26.3%, to 49.130.9 million gallons from 53.7 million gallons in the prior year.gallons. According to the NOAA, averageNational Oceanic and Atmospheric Administration, the winter of 2015-2016 was the warmest on record in the contiguous United States. Average temperatures (as measured by heating degree days) across all of our service territories duringfor fiscal 20142016 were 3% colder17% warmer than normal and 7% colder15% warmer than the prior year. While average temperatures were considerably warmer than the prior year period. However,in nearly all service 25
territories, California experienced cooler weather compared to the weather pattern duringprior year, which contributed to a 13% increase in propane volumes sold in that market. Revenues for fiscal 2016 of $1,046.1 million decreased $370.9 million, or 26.2%, compared to the winter heating season (October 2013 through March 2014) was characterized by considerably colderprior year, primarily due to the lower volumes sold, combined with lower retail selling prices associated with lower wholesale costs. Cost of products sold for fiscal 2016 of $362.0 million decreased $231.4 million, or 39.0%, compared to the prior year, primarily due to lower wholesale propane costs and, to a lesser extent, lower volumes sold. Average posted propane prices (basis Mont Belvieu, Texas) and fuel oil prices were 18.4% and 31.0% lower than normal temperaturesthe prior year, respectively. Cost of products sold for fiscal 2016 included a $1.2 million unrealized (non-cash) loss attributable to the mark-to-market adjustment for derivative instruments used in our service territoriesrisk management activities, compared to a $1.9 million unrealized (non-cash) gain for fiscal 2015. These unrealized gains and losses are excluded from Adjusted EBITDA for both periods in the easttable below. Combined operating and midwest regions, whereas our service territoriesgeneral and administrative expenses of $473.9 million for fiscal 2016 were $38.6 million, or 7.5%, lower than fiscal 2015. Excluding the impact of the items discussed above in the west experienced unseasonably warm temperatures throughoutcomputation of Adjusted EBITDA from both periods, combined operating and general and administrative expenses decreased 5.2% compared to the period. Average temperaturesprior year, primarily due to savings in payroll and benefit-related expenses from a lower headcount, lower vehicle expenses stemming from a reduced vehicle count, as well as lower volume-related variable costs and continued operating efficiencies. Depreciation and amortization expense of $129.6 million for fiscal 2016 decreased $3.7 million, or 2.8%, primarily due to the western territories during this past winter heating season were 11% warmer than normal and 6% warmer than the comparable periodacceleration of depreciation expense recorded in the prior year which negatively impacted volumes soldfor assets taken out of service. Net interest expense of $75.1 million for fiscal 2016 decreased $2.5 million, or 3.2%, primarily due to savings from the refinancing of certain of our senior notes completed in those territories. Additionally, volumes soldthe second quarter of fiscal 2015 and the refinancing of our revolving credit facility during the second quarter of fiscal 2014 were adversely affected by supply constraints resulting from industry-wide supply shortages and logistics issues, as well as customer conservation attributable to a significant rise in wholesale propane prices.2016. During fiscal 2014,2016, we madesucceeded in accomplishing many significant progress, not only in our integration efforts with regards to Inergy Propane, but also in executing our strategic financing initiatives. Togoals. The following highlight a few key accomplishments for fiscal 2014: 2016: We completedacquired the assets and operations of Propane USA Distribution, LLC, which expanded our system conversions and much ofpresence in the physical blending activities associated with the integration of Inergy Propane;South Florida market; We have installedextended our operating model across the entire platform and have migrated to one common brand;reach in certain strategic markets that were not previously served by our existing footprint; We successfully refinanced our previous 7.5% Senior Notes due 2018 with new 5.5% Senior Notes due in 2024,revolving credit facility which effectivelyimproved our cost of capital, further extended maturities on this portion of our debt by six yearsmaturities until 2021 and reducedincreased our available borrowing capacity; We made further refinements to our operating model to streamline our operational activities, reduce our cost structure and enhance our position in several markets; and We funded all working capital needs from cash interest requirement byon hand without the need to borrow under our revolving credit facility and ended the year with more than $8$37.0 million annually; andof cash. We have successfully transitioned our senior leadership team in accordance with Board-approved succession plans.
As we look ahead to fiscal 2015,2017, our anticipated cash requirements include: (i) maintenance and growth capital expenditures of approximately $34.0$38.0 million; (ii) approximately $79.4$74.8 million of interest and income tax payments; and (iii) approximately $211.6$216.6 million of distributions to Unitholders, assuming distributions remain at the current annualized rate of $3.50$3.55 per Common Unit. Based on our current cash position of $92.6$37.3 million as of September 27, 2014 and24, 2016, availability of funds under the Revolving Credit Facility (unused borrowing capacity of $255.1 million at September 27, 2014) and expected cash flow from operating activities, we expect to have sufficient funds to meet our current and future obligations.
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Fiscal Year 20142016 Compared to Fiscal Year 20132015 Revenues (Dollars and gallons in thousands) | | | | | | | | | | | | | | | | | | | Fiscal | | | Fiscal | | | | | | | Percent | | | | 2016 | | | 2015 | | | Decrease | | | Decrease | | Revenues | | | | | | | | | | | | | | | | | Propane | | $ | 884,169 | | | $ | 1,176,980 | | | $ | (292,811 | ) | | | (24.9 | )% | Fuel oil and refined fuels | | | 68,759 | | | | 127,495 | | | | (58,736 | ) | | | (46.1 | )% | Natural gas and electricity | | | 50,763 | | | | 66,865 | | | | (16,102 | ) | | | (24.1 | )% | All other | | | 42,420 | | | | 45,639 | | | | (3,219 | ) | | | (7.1 | )% | Total revenues | | $ | 1,046,111 | | | $ | 1,416,979 | | | $ | (370,868 | ) | | | (26.2 | )% | Retail gallons sold | | | | | | | | | | | | | | | | | Propane | | | 414,776 | | | | 480,372 | | | | (65,596 | ) | | | (13.7 | )% | Fuel oil and refined fuels | | | 30,878 | | | | 41,878 | | | | (11,000 | ) | | | (26.3 | )% |
| | | | | | | | | | | | | | | | | | (Dollars in thousands) | | Fiscal
2014 | | | Fiscal
2013 | | | Increase /
(Decrease) | | | Percent
Increase /
(Decrease) | | Revenues | | | | | | | | | | | | | | | | | Propane | | $ | 1,606,840 | | | $ | 1,357,102 | | | $ | 249,738 | | | | 18.4 | % | Fuel oil and refined fuels | | | 194,684 | | | | 208,957 | | | | (14,273 | ) | | | (6.8 | %) | Natural gas and electricity | | | 87,093 | | | | 79,432 | | | | 7,661 | | | | 9.6 | % | All other | | | 49,640 | | | | 58,115 | | | | (8,475 | ) | | | (14.6 | %) | | | | | | | | | | | | | | | | | | Total revenues | | $ | 1,938,257 | | | $ | 1,703,606 | | | $ | 234,651 | | | | 13.8 | % | | | | | | | | | | | | | | | | | |
Total revenues increased $234.7decreased $370.9 million, or 13.8%26.2%, to $1,938.3$1,046.1 million for fiscal 20142016 compared to $1,703.6$1,417.0 million for the prior year due to higherlower volumes sold driven by record warm temperatures experienced during the fiscal 2016 heating season, combined with lower average propane, fuel oil and refined fuels and natural gas selling prices offset to an extent byassociated with lower volumes sold.wholesale costs. As discussed above, average temperatures (as measured in heating degree days) across all of our service territories for fiscal 20142016 were 3% colder than normal, compared to 4% warmer than normal in the prior year. However, the weather pattern during the fiscal 2014 heating season was characterized by warmer than normal temperatures for the first two months of the period, followed by significantly colder than normal temperatures for the remainder of the heating season. In addition, during the peak of our heating season, we experienced considerably colder than normal temperatures in our east and midwest service territories, but sustained unseasonably warm temperatures in our western territories. Average temperatures in our western territories during the fiscal 2014 heating season were 11%17% warmer than normal and 6%15% warmer than the prior year. During the heating season (October through March), average temperatures were 18% warmer than normal and 19% warmer than the comparable prior year period. The unseasonably warm weather was persistent as temperatures were warmer than both normal and the prior year throughout the heating season in nearly all of our service territories. While average temperatures were considerably warmer than the prior year in nearly all service territories, California experienced cooler weather compared to the prior year (although temperatures were still 24% warmer than normal), which helped contribute to a 13% year-over-year increase in sales volumes in that market. Revenues from the distribution of propane and related activities of $1,606.8$884.2 million for fiscal 2014 increased $249.72016 decreased $292.8 million, or 18.4%24.9%, compared to $1,357.1$1,177.0 million for the prior year, primarily due to higherlower retail volumes sold resulting from the impact of record warm temperatures on customer demand for heating needs, coupled with lower average retail selling prices associated with higherlower wholesale costs. Retail propane costs, partially offset bygallons sold in fiscal 2016 decreased 65.6 million gallons, or 13.7%, resulting in a decrease in retail propane volumes sold.revenues of $150.4 million. Average propane selling prices for fiscal 2014 increased 20.0%2016 decreased 13.5% compared to the prior year, as a result of higher wholesale propane costs, resulting in a $254.6$128.1 million increasedecrease in revenues year-over-year. Retail propane gallons sold in fiscal 2014 decreased 3.9 million gallons, or 0.7%, to 530.7 million gallons from 534.6 million gallons in the prior year. Volumes sold during fiscal 2014 were adversely affected by supply constraints resulting from industry-wide supply shortages and logistics issues adversely affecting propane transportation sourcing and costs that persisted throughout much of our heating season. Customer conservation attributable to the significant rise in propane prices also adversely affected volumes sold. Lower retail propane volumes sold resulted in a decrease in revenues of $9.3 million for fiscal 2014 compared to the prior year. Included within the propane segment are revenues from other propane activities of $79.1$61.1 million for fiscal 2014,2016, which increased $4.4decreased $14.3 million compared to the prior year. Revenues from the distribution of fuel oil and refined fuels of $194.7$68.8 million for fiscal 20142016 decreased $14.3$58.7 million, or 6.8%46.1%, from $209.0$127.5 million for the prior year, primarily due to lower volumes sold partially offset by higherresulting from the record warm temperatures discussed above, particularly in the northeast region of the country in which the majority of our fuel oil customers reside, and lower average selling prices.prices associated with lower wholesale costs. Fuel oil and refined fuels gallons sold in fiscal 20142016 decreased 4.611.0 million gallons, or 8.6%26.3%, to 49.1 million gallons from 53.7 million gallons in the prior year, primarily due to a decline in lower margin gasoline and diesel volumes. Lower fuel oil and refined fuels volumes sold resultedresulting in a decrease in revenues of $18.0 million for fiscal 2014 compared to the prior year.$33.4 million. Average selling prices in our fuel oil and refined fuels segment in fiscal 2014 increased 2.0% compared to the prior year,decreased 26.9%, resulting in a $3.7$25.3 million increasedecrease in revenues year-over-year.revenues. Revenues in our natural gas and electricity segment increased $7.7decreased $16.1 million, or 9.6%24.1%, to $87.1$50.8 million in fiscal 20142016 compared to $79.4$66.9 million in the prior year as a result of higherlower average selling prices for natural gas and electricity as a result of higherassociated with lower average wholesale costs, partially offset byand lower electricity usage.natural gas usage resulting from the warm weather discussed above. Cost of Products Sold (Dollars in thousands) | | | | | | | | | | | | | | | | | | | | | | | | | | | | Fiscal | | | Fiscal | | | | | | | Percent | | | (Dollars in thousands) | | Fiscal
2014 | | Fiscal
2013 | | Increase /
(Decrease) | | Percent
Increase /
(Decrease) | | | | | | 2016 | | | 2015 | | | Decrease | | | Decrease | | Cost of products sold | | | | | | | | | | | | | | | | | | | | | | | | | Propane | | $ | 844,855 | | | $ | 612,240 | | | $ | 232,615 | | | 38.0 | % | | $ | 275,091 | | | $ | 443,538 | | | $ | (168,447 | ) | | | (38.0 | )% | Fuel oil and refined fuels | | | 155,773 | | | 172,022 | | | (16,249 | ) | | (9.4 | %) | | | 42,890 | | | | 92,628 | | | | (49,738 | ) | | | (53.7 | )% | Natural gas and electricity | | | 64,448 | | | 55,995 | | | 8,453 | | | 15.1 | % | | | 30,676 | | | | 42,313 | | | | (11,637 | ) | | | (27.5 | )% | All other | | | 15,674 | | | 21,648 | | | (5,974 | ) | | (27.6 | %) | | | 13,296 | | | | 14,901 | | | | (1,605 | ) | | | (10.8 | )% | | | | | | | | | | | | | | Total cost of products sold | | $ | 1,080,750 | | | $ | 861,905 | | | $ | 218,845 | | | | 25.4 | % | | $ | 361,953 | | | $ | 593,380 | | | $ | (231,427 | ) | | | (39.0 | )% | | | | | | | | | | | | | | | As a percent of total revenues | | | 55.8 | % | | | 50.6 | % | | | | | | | 34.6 | % | | | 41.9 | % | | | | | | | | |
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. Given the retail nature of our operations, we maintain a certain level of priced physical inventory to help ensure that our field operations have adequate supply commensurate with the time of year. Our strategy has been, and will continue to be, to keep our physical inventory priced relatively close to market for our field operations. Consistent with past practices, we principally utilize futures and/or options contracts traded on the NYMEX to mitigate the price risk associated with our priced physical inventory. Under this risk management strategy, realized gains or losses on futures or options contracts, which are reported in cost of products sold, will typically offset losses or gains on the physical inventory once the product is sold (which may or may not occur in the same accounting period). We do not use futures or options contracts, or other derivative instruments, for speculative trading purposes. 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. In the commodities markets, the downward trend in propane prices were extremely volatile during(basis Mont Belvieu, Texas) experienced in fiscal 2014 as a result of the supply2015 continued in fiscal 2016 and logistics issues that started late in the first fiscal quarterextended into February 2016. Thereafter, propane prices rallied and continued throughout most of the second quarter.generally traded between $0.40 and $0.50 per gallon. Overall, average posted prices for propane and fuel oil for fiscal 20142016 were 24.8% higher18.4% and 31.0% lower than the prior year, while fuel oil prices were 2.1% lower than the prior year.respectively. The net change in the fair value of derivative instruments during the period resulted in unrealized (non-cash) (losses) gains of $0.3($1.2) million and unrealized (non-cash) losses of $4.3$1.9 million reported in cost of products sold in fiscal 20142016 and 2013,2015, respectively, resulting in a decreasean increase of $4.6$3.1 million in cost of products sold in fiscal 20142016 compared to the prior year, $4.4$2.2 million of which was reported in the propane segment and $0.9 million was reported in the fuel oil and refined fuels segment. Cost of products sold associated with the distribution of propane and related activities of $844.9$275.1 million for fiscal 2014 increased $232.62016 decreased $168.4 million, or 38.0%, compared to the prior year, primarily due to higherlower wholesale costs and, higher transportation costs associated with the extraordinary measures we took to ensure adequate propane supplies were delivered to our customer service centers to meet customer demand during the heating season. Highera lesser extent, lower volumes sold. Lower average propane costs resulted in an increase of $233.3 million, partially offset by a decrease of $4.3 million related toand lower propane volumes sold during fiscal 2014 compared to the prior year.2016 resulted in a decrease of $106.8 million and $59.5 million, respectively. Cost of products sold from other propane activities increased $8.0decreased $4.3 million. Cost of products sold associated with our fuel oil and refined fuels segment of $155.8$42.9 million for fiscal 20142016 decreased $16.2$49.7 million, or 9.4%53.7%, compared to the prior year. Lower fuel oil and refined fuels wholesale costs and lower volumes sold coupled with lower wholesale costs resulted in decreases of $14.8$26.2 million and $1.4$24.4 million, respectively, in costs of products sold during fiscal 20142016 compared to the prior year. Cost of products sold in our natural gas and electricity segment of $64.4$30.7 million for fiscal 2014 increased $8.52016 decreased $11.6 million, or 15.1%27.5%, compared to the prior year, primarily due to higherlower natural gas and electricity wholesale costs partially offset bycoupled with lower volumes sold.usage. Total cost of products sold as a percent of total revenues increased 5.2decreased 7.3 percentage points to 55.8%34.6% in fiscal 20142016 from 50.6%41.9% in the prior year, primarily due to the risedecline in wholesale propane costs outpacing the risedecline in propane average selling prices during fiscal 2014.prices. Operating Expenses (Dollars in thousands) | | | | | | | | | | | | | | | | | | | | | | | | | | | | Fiscal | | | Fiscal | | | | | | | Percent | | | (Dollars in thousands) | | Fiscal
2014 | | Fiscal
2013 | | Decrease | | Percent
Decrease | | | | | | 2016 | | | 2015 | | | Decrease | | | Decrease | | Operating expenses | | $ | 466,389 | | | $ | 469,496 | | | $ | (3,107 | ) | | (0.7 | %) | | $ | 412,756 | | | $ | 444,251 | | | $ | (31,495 | ) | | | (7.1 | )% | As a percent of total revenues | | | 24.1 | % | | 27.6 | % | | | | | | | 39.5 | % | | | 31.4 | % | | | | | | | | |
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. 28
Operating expenses of $466.4$412.8 million for fiscal 20142016 decreased $3.1$31.5 million, or 0.7%7.1%, compared to $469.5$444.3 million in the prior year, primarily due to synergies realized as a result of the continuing integration of Inergy Propane operations, which waslower payroll and benefit-related expenses attributable to reduced headcount, lower variable compensation associated with lower earnings, lower vehicle expenses due to reduced vehicle count and lower fuel costs to operate our fleet; offset to an extent by higher overtimean increase in insurance and vehicle expenses attributable to harsh weather conditions during our fiscal 2014 heating season, as well as higher provisions for potential uncollectible accounts. product liability expenses. Operating expenses for fiscal 20142016 included integration-relateda $6.6 million accrual for our voluntary full withdrawal from a MEPP, a charge of $3.0 million related to the settlement of a product liability matter, and a pension settlement charge of $2.0 million. Operating expenses for fiscal 2015 included expenses of $8.1$9.7 million associated with the integration of the Inergy Propane operations, compared to $4.6 million in the prior year. In addition, fiscal 2013 included a $7.0an $11.3 million charge related to our voluntary partial withdrawal from a multi-employerMEPP, and a pension plan and full withdrawal from four multi-employer pension plans for certain employees acquired in the Inergy Propane Acquisition.settlement charge of $2.0 million. These chargesitems were excluded from our calculation of Adjusted EBITDA below. General and Administrative Expenses (Dollars in thousands) | | | | | | | | | | | | | | | | | | | | | | | | | | | | Fiscal | | | Fiscal | | | | | | | Percent | | | (Dollars in thousands) | | Fiscal
2014 | | Fiscal
2013 | | Decrease | | Percent
Decrease | | | | | | 2016 | | | 2015 | | | Decrease | | | Decrease | | General and administrative expenses | | $ | 64,593 | | | $ | 64,845 | | | $ | (252 | ) | | (0.4 | %) | | $ | 61,149 | | | $ | 68,296 | | | $ | (7,147 | ) | | | (10.5 | )% | As a percent of total revenues | | | 3.3 | % | | 3.8 | % | | | | | | | 5.8 | % | | | 4.8 | % | | | | | | | | |
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 $64.6$61.1 million for fiscal 2014 was relatively flat2016 decreased $7.1 million, or 10.5%, compared to $68.3 million in the prior year.year, primarily due to lower variable compensation associated with lower earnings, partially offset by increased professional services fees for strategic initiatives. General and administrative expenses for fiscal 20142015 included $1.9 million of professional services and 2013 included $4.2other expenses associated with the integration of the Inergy Propane operations. This item was excluded from our calculation of Adjusted EBITDA below. Depreciation and Amortization (Dollars in thousands) | | | | | | | | | | | | | | | | | | | Fiscal | | | Fiscal | | | | | | | Percent | | | | 2016 | | | 2015 | | | Decrease | | | Decrease | | Depreciation and amortization | | $ | 129,616 | | | $ | 133,294 | | | $ | (3,678 | ) | | | (2.8 | )% | As a percent of total revenues | | | 12.4 | % | | | 9.4 | % | | | | | | | | |
Depreciation and amortization expense of $129.6 million in fiscal 2016 decreased $3.7 million from $133.3 million in the prior year, primarily as a result of accelerated depreciation expense recorded in the prior year for assets taken out of service from integration activities. Interest Expense, net (Dollars in thousands) | | | | | | | | | | | | | | | | | | | Fiscal | | | Fiscal | | | | | | | Percent | | | | 2016 | | | 2015 | | | Decrease | | | Decrease | | Interest expense, net | | $ | 75,086 | | | $ | 77,634 | | | $ | (2,548 | ) | | | (3.3 | )% | As a percent of total revenues | | | 7.2 | % | | | 5.5 | % | | | | | | | | |
Net interest expense of $75.1 million for fiscal 2016 decreased $2.5 million from $77.6 million in the prior year, primarily due to the refinancing of $250.0 million of 7.375% Senior Notes due 2020 with $250.0 million of 5.75% Senior Notes due 2025 in the second quarter of fiscal 2015, and savings from the refinancing of our revolving credit facility. See Liquidity and Capital Resources below for additional discussion. Gain on Sale of Business On April 22, 2016, we sold certain assets and operations in a non-strategic market of the propane segment for $26.0 million, including $5.0 million of non-compete consideration that will be received over a five-year period, resulting in a gain of $9.8 million that was recognized during the third quarter of fiscal 2016. The corresponding net assets and results of operations were not material to our results of operations, financial position and cash flows. 29
Loss on Debt Extinguishment On March 3, 2016, we entered into a Second Amended and Restated Credit Agreement (“Amended Credit Agreement”) that provides for a five-year $500.0 million revolving credit facility. In connection with the Amended Credit Agreement, we recognized a non-cash charge of $0.3 million to write-off a portion of unamortized debt origination costs of the previous credit agreement. On February 25, 2015, we repurchased and satisfied and discharged all of our previously outstanding 2020 Senior Notes with net proceeds from the issuance of the 2025 Senior Notes and cash on hand, pursuant to a tender offer and redemption. In connection with this tender offer and redemption, during the second quarter of fiscal 2015 we recognized a loss on the extinguishment of debt of $15.1 million, consisting of $11.1 million for the redemption premium and related fees, as well as the write-off of $2.9 million and $6.0$1.1 million in unamortized debt origination costs and unamortized discount, respectively. Net Income and Adjusted EBITDA Net income for fiscal 2016 amounted to $14.4 million, or $0.24 per Common Unit, compared to $84.4 million, or $1.39 per Common Unit, in fiscal 2015. Earnings before interest, taxes, depreciation and amortization (“EBITDA”) for fiscal 2016 amounted to $219.7 million, compared to $296.0 million for fiscal 2015. Net income and EBITDA for fiscal 2016 included: (i) a gain on sale of business of $9.8 million; (ii) a $6.6 million charge related to our voluntary full withdrawal from a MEPP; (iii) a $3.0 million charge related to the settlement of a product liability matter; (iv) a pension settlement charge of $2.0 million; and (v) a loss on debt extinguishment of $0.3 million. Net income and EBITDA for fiscal 2015 included: (i) a loss on debt extinguishment of $15.1 million; (ii) $11.5 million in expenses related to the integration of Inergy Propane; (iii) an $11.3 million charge related to our voluntary partial withdrawal from a MEPP; and (iv) a pension settlement charge of $2.0 million. Excluding the effects of these items, as well as the unrealized (non-cash) mark-to-market adjustments on derivative instruments in both years, Adjusted EBITDA amounted to $223.0 million for fiscal 2016, compared to Adjusted EBITDA of $334.0 million in fiscal 2015. EBITDA represents net income before deducting interest expense, income taxes, depreciation and amortization. Adjusted EBITDA represents EBITDA excluding the unrealized net gain or loss on mark-to-market activity for derivative instruments and other items, as applicable, as provided in the table below. Our management uses EBITDA and Adjusted EBITDA as supplemental measures of operating performance and we are including them because we believe that they provide our investors and industry analysts with additional information to evaluate our operating results. 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. The following table sets forth our calculations of EBITDA and Adjusted EBITDA: (Dollars in thousands) | | Year Ended | | | | September 24, | | | September 26, | | | | 2016 | | | 2015 | | Net income | | $ | 14,440 | | | $ | 84,352 | | Add: | | | | | | | | | Provision for income taxes | | | 588 | | | | 700 | | Interest expense, net | | | 75,086 | | | | 77,634 | | Depreciation and amortization | | | 129,616 | | | | 133,294 | | EBITDA | | | 219,730 | | | | 295,980 | | Unrealized (non-cash) losses (gains) on changes in fair value of derivatives | | | 1,190 | | | | (1,855 | ) | Gain on sale of business | | | (9,769 | ) | | | — | | Multi-employer pension plan withdrawal charge | | | 6,600 | | | | 11,300 | | Product liability settlement | | | 3,000 | | | | — | | Pension settlement charge | | | 2,000 | | | | 2,000 | | Loss on debt extinguishment | | | 292 | | | | 15,072 | | Integration-related costs | | | — | | | | 11,542 | | Adjusted EBITDA | | $ | 223,043 | | | $ | 334,039 | |
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Fiscal Year 2015 Compared to Fiscal Year 2014 Revenues (Dollars and gallons in thousands) | | | | | | | | | | | | | | | | | | | Fiscal | | | Fiscal | | | | | | | Percent | | | | 2015 | | | 2014 | | | Decrease | | | Decrease | | Revenues | | | | | | | | | | | | | | | | | Propane | | $ | 1,176,980 | | | $ | 1,606,840 | | | $ | (429,860 | ) | | | (26.8 | )% | Fuel oil and refined fuels | | | 127,495 | | | | 194,684 | | | | (67,189 | ) | | | (34.5 | )% | Natural gas and electricity | | | 66,865 | | | | 87,093 | | | | (20,228 | ) | | | (23.2 | )% | All other | | | 45,639 | | | | 49,640 | | | | (4,001 | ) | | | (8.1 | )% | Total revenues | | $ | 1,416,979 | | | $ | 1,938,257 | | | $ | (521,278 | ) | | | (26.9 | )% | Retail gallons sold | | | | | | | | | | | | | | | | | Propane | | | 480,372 | | | | 530,743 | | | | (50,371 | ) | | | (9.5 | )% | Fuel oil and refined fuels | | | 41,878 | | | | 49,071 | | | | (7,193 | ) | | | (14.7 | )% |
Total revenues decreased $521.3 million, or 26.9%, to $1,417.0 million for fiscal 2015 compared to $1,938.3 million for the prior year due to lower average propane, fuel oil and refined fuels and natural gas selling prices and, to a lesser extent, lower volumes sold. Average temperatures (as measured in heating degree days) across all of our service territories for fiscal 2015 were 2% warmer than normal and 5% warmer than the prior year. The weather pattern during the fiscal 2015 heating season was characterized by warmer than normal temperatures for the first quarter of fiscal 2015, particularly during the month of December 2014 (December 2014 was 15% warmer than normal and 21% warmer than December 2013), followed by inconsistent temperatures in our eastern and midwestern territories during the latter half of the heating season. We also experienced sustained warmer than normal temperatures in our western territories throughout fiscal 2015 as average temperatures were 23% warmer than normal and 9% warmer than the comparable prior year period. Revenues from the distribution of propane and related activities of $1,177.0 million for fiscal 2015 decreased $429.9 million, or 26.8%, compared to $1,606.8 million for the prior year, primarily due to lower average retail selling prices associated with lower wholesale propane costs and, to a lesser extent, lower volumes sold. Average propane selling prices for fiscal 2015 decreased 20.3% compared to the prior year, resulting in a $281.0 million decrease in revenues year-over-year. Retail propane gallons sold in fiscal 2015 decreased 50.4 million gallons, or 9.5%, resulting in a decrease in revenues of $145.0 million. Volumes sold during fiscal 2015 were adversely affected by the unseasonably warm weather during key parts of the winter heating season discussed above. Included within the propane segment are revenues from other propane activities of $75.3 million for fiscal 2015, which decreased $3.9 million compared to the prior year. Revenues from the distribution of fuel oil and refined fuels of $127.5 million for fiscal 2015 decreased $67.2 million, or 34.5%, from $194.7 million for the prior year, primarily due to lower average selling prices and, to a lesser extent, lower volumes sold. Average selling prices in our fuel oil and refined fuels segment decreased 23.2%, resulting in a $38.5 million decrease in revenues. Fuel oil and refined fuels gallons sold in fiscal 2015 decreased 7.2 million gallons, or 14.7%, resulting in a decrease in revenues of $28.7 million. The decrease in volumes sold was primarily due to the impact of the unfavorable weather trends discussed above. Revenues in our natural gas and electricity segment decreased $20.2 million, or 23.2%, to $66.9 million in fiscal 2015 compared to $87.1 million in the prior year as a result of lower average selling prices for natural gas and electricity as a result of lower average wholesale costs and, to a lesser extent, lower natural gas and electricity usage. Cost of Products Sold (Dollars in thousands) | | | | | | | | | | | | | | | | | | | Fiscal | | | Fiscal | | | | | | | Percent | | | | 2015 | | | 2014 | | | Decrease | | | Decrease | | Cost of products sold | | | | | | | | | | | | | | | | | Propane | | $ | 443,538 | | | $ | 844,855 | | | $ | (401,317 | ) | | | (47.5 | )% | Fuel oil and refined fuels | | | 92,628 | | | | 155,773 | | | | (63,145 | ) | | | (40.5 | )% | Natural gas and electricity | | | 42,313 | | | | 64,448 | | | | (22,135 | ) | | | (34.3 | )% | All other | | | 14,901 | | | | 15,674 | | | | (773 | ) | | | (4.9 | )% | Total cost of products sold | | $ | 593,380 | | | $ | 1,080,750 | | | $ | (487,370 | ) | | | (45.1 | )% | As a percent of total revenues | | | 41.9 | % | | | 55.8 | % | | | | | | | | |
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From a commodity perspective, propane prices declined rather sharply during the first quarter of fiscal 2015 and continued to trend downward for the remainder of the fiscal year, primarily due to sustained record or near-record high U.S. propane inventories. The movement in commodity prices in fiscal 2015 was in stark contrast to the prior year, when prices were rising rapidly due to industry-wide supply and logistics challenges, particularly during the peak of the fiscal 2014 heating season. Overall, average posted prices for propane (basis Mont Belvieu, Texas) and fuel oil prices for fiscal 2015 were 52.7% and 35.5% lower than the prior year, respectively. The net change in the fair value of derivative instruments during the period resulted in unrealized (non-cash) gains of $1.9 million and $0.3 million reported in cost of products sold in fiscal 2015 and 2014, respectively, resulting in a decrease of $1.6 million in cost of products sold in fiscal 2015 compared to the prior year, $1.3 million of which was reported in the propane segment and $0.3 million was reported in the fuel oil and refined fuels segment. Cost of products sold associated with the distribution of propane and related activities of $443.5 million for fiscal 2015 decreased $401.3 million, or 47.5%, compared to the prior year primarily due to lower wholesale costs and, to a lesser extent, lower volumes sold. Lower average propane costs and lower propane volumes sold during fiscal 2015 resulted in a decrease of $310.3 million and $78.2 million, respectively. Cost of products sold from other propane activities decreased $11.5 million. Cost of products sold associated with our fuel oil and refined fuels segment of $92.6 million for fiscal 2015 decreased $63.1 million, or 40.5%, compared to the prior year. Lower fuel oil and refined fuels wholesale costs and lower volumes sold, resulted in decreases of $39.8 million and $23.0 million, respectively, in costs of products sold during fiscal 2015 compared to the prior year. Cost of products sold in our natural gas and electricity segment of $42.3 million for fiscal 2015 decreased $22.1 million, or 34.3%, compared to the prior year, primarily due to lower natural gas and electricity wholesale costs and, to a lesser extent, lower usage. Total cost of products sold as a percent of total revenues decreased 13.9 percentage points to 41.9% in fiscal 2015 from 55.8% in the prior year, primarily due to the decline in wholesale costs outpacing the decline in average selling prices in all segments during fiscal 2015. Operating Expenses (Dollars in thousands) | | | | | | | | | | | | | | | | | | | Fiscal | | | Fiscal | | | | | | | Percent | | | | 2015 | | | 2014 | | | Decrease | | | Decrease | | Operating expenses | | $ | 444,251 | | | $ | 466,389 | | | $ | (22,138 | ) | | | (4.7 | )% | As a percent of total revenues | | | 31.4 | % | | | 24.1 | % | | | | | | | | |
Operating expenses of $444.3 million for fiscal 2015 decreased $22.1 million, or 4.7%, compared to $466.4 million in the prior year, primarily due to operating efficiencies and synergies realized as a result of the integration of Inergy Propane; including lower payroll and benefit-related expenses attributable to reduced headcount, lower vehicles expenses attributable to reduced vehicle count and lower fuel costs to operate our fleet, and lower bad debt and insurance expenses. Operating expenses for fiscal 2015 included expenses of $9.7 million associated with the integration of the Inergy Propane operations, an $11.3 million charge related to our voluntary partial withdrawal from a MEPP, and a pension settlement charge of $2.0 million. Operating expenses for fiscal 2014 included integration-related expenses of $8.1 million. These items were excluded from our calculation of Adjusted EBITDA below. General and Administrative Expenses (Dollars in thousands) | | | | | | | | | | | | | | | | | | | Fiscal | | | Fiscal | | | | | | | Percent | | | | 2015 | | | 2014 | | | Increase | | | Increase | | General and administrative expenses | | $ | 68,296 | | | $ | 64,593 | | | $ | 3,703 | | | | 5.7 | % | As a percent of total revenues | | | 4.8 | % | | | 3.3 | % | | | | | | | | |
General and administrative expenses of $68.3 million for fiscal 2015 increased $3.7 million from $64.6 million in the prior year, primarily due to higher payroll expenses, including variable compensation, and higher professional service fees associated with uninsured legal matters. General and administrative expenses for fiscal 2015 and 2014 included $1.9 million and $4.2 million, respectively, of professional services and other expenses associated with the integration of the Inergy Propane operations. These items were excluded from our calculation of Adjusted EBITDA below.
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Depreciation and Amortization (Dollars in thousands) | | | | | | | | | | | | | | | | | | | | | | | | | | | | Fiscal | | | Fiscal | | | | | | | Percent | | | (Dollars in thousands) | | Fiscal
2014 | | Fiscal
2013 | | Increase | | | Percent
Increase | | | | | | 2015 | | | 2014 | | | Decrease | | | Decrease | | Depreciation and amortization | | $ | 136,399 | | | $ | 130,384 | | | $ | 6,015 | | | | 4.6 | % | | $ | 133,294 | | | $ | 136,399 | | | $ | (3,105 | ) | | | (2.3 | )% | As a percent of total revenues | | | 7.0 | % | | 7.7 | % | | | | | | | 9.4 | % | | | 7.0 | % | | | | | | | | |
Depreciation and amortization expense of $133.3 million in fiscal 2015 decreased $3.1 million from $136.4 million in fiscal 2014 increased $6.0 million,the prior year, primarily as a result of accelerated depreciation expense on buildings, vehicles and equipmentrecorded in the prior year for assets taken out of service as a result of thefrom integration of Inergy Propane operations.activities. Interest Expense, net (Dollars in thousands) | | | | | | | | | | | | | | | | | | | | | | | | | | | | Fiscal | | | Fiscal | | | | | | | Percent | | | (Dollars in thousands) | | Fiscal
2014 | | Fiscal
2013 | | Decrease | | Percent
Decrease | | | | | | 2015 | | | 2014 | | | Decrease | | | Decrease | | Interest expense, net | | $ | 83,261 | | | $ | 95,427 | | | $ | (12,166 | ) | | (12.7 | %) | | $ | 77,634 | | | $ | 83,261 | | | $ | (5,627 | ) | | | (6.8 | )% | As a percent of total revenues | | | 4.3 | % | | 5.6 | % | | | | | | | 5.5 | % | | | 4.3 | % | | | | | | | | |
Net interest expense of $83.3$77.6 million for fiscal 20142015 decreased $12.2$5.6 million compared to $95.4from $83.3 million in the prior year, primarily due to the reduction of $157.3 million in long-term borrowings during the fourth quarter of fiscal 2013 and, to a lesser extent, the impact of the refinancing of our$496.6 million of 7.5% Senior Notes due 2018 with $525.0 million of 5.5% Senior Notes due 2024 completed duringin the third quarter of fiscal 2014.2014, and the refinancing of $250.0 million of 7.375% Senior Notes due 2020 with $250.0 million of 5.75% Senior Notes due 2025 in the second quarter of fiscal 2015. See Liquidity and Capital Resources below for additional discussion. Loss on Debt Extinguishment On February 25, 2015, we repurchased and satisfied and discharged all of our previously outstanding 2020 Senior Notes with net proceeds from the issuance of the 2025 Senior Notes and cash on hand, pursuant to a tender offer and redemption. In connection with this tender offer and redemption, during the second quarter of fiscal 2015 we recognized a loss on the extinguishment of debt of $15.1 million, consisting of $11.1 million for the redemption premium and related fees, as well as the write-off of $2.9 million and $1.1 million in unamortized debt origination costs and unamortized discount, respectively. On May 27, 2014, we repurchased and satisfied and discharged all of our previously outstanding 2018 Senior Notes with net proceeds from the issuance of the 2024 Senior Notes and cash on hand pursuant to a tender offer and redemption. In connection with this tender offer and redemption, we recognized a loss on the extinguishment of debt of $11.6 million consisting of $31.6 million for the redemption premium and related fees, as well as the write-off of $5.3 million and ($25.3) million in unamortized debt origination costs and unamortized premium, respectively. On August 2, 2013, we repurchased, pursuant to an 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.
Net Income and Adjusted EBITDA Net income for fiscal 20142015 amounted to $84.4 million, or $1.39 per Common Unit, compared to $94.5 million, or $1.56 per Common Unit, compared to $78.8 million, or $1.35 per Common Unit, in fiscal 2013.2014. Earnings before interest, taxes, depreciation and amortization (“EBITDA”) for fiscal 20142015 amounted to $296.0 million, compared to $314.9 million compared to $305.2 million for fiscal 2013.2014. Net income and EBITDA for fiscal 2015 included: (i) a loss on debt extinguishment of $15.1 million; (ii) $11.5 million in expenses related to the integration of Inergy Propane; (iii) an $11.3 million charge related to our voluntary partial withdrawal from a MEPP; and (iv) a pension settlement charge of $2.0 million. Net income and EBITDA for fiscal 2014 included: (i) a loss on debt extinguishment of $11.6 million; and (ii) $12.3 million in expenses related to the ongoing integration of Inergy Propane and (ii) a loss on debt extinguishment of $11.6 million. Net income and EBITDA for fiscal 2013 included: (i) $10.6 million in expenses related to the ongoing 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 Inergy Propane Acquisition; and (iii) a loss on debt extinguishment of $2.1 million.Propane. Excluding the effects of these charges,items, as well as the unrealized (non-cash) mark-to-market adjustments on derivative instruments in both years, Adjusted EBITDA amounted to $338.5$334.0 million for fiscal 2014,2015, compared to Adjusted EBITDA of $329.3$338.5 million in fiscal 2013.2014. Adjusted EBITDA represents EBITDA excluding the unrealized net gain or loss from mark-to-market activity for derivative instruments and 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. 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.
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The following table sets forth (i) our calculations of EBITDA and adjusted EBITDA and (ii) a reconciliation of both EBITDA and adjusted EBITDA, as so calculated, to our net cash provided by operating activitiesAdjusted EBITDA: | | | | | | | | | | | | Year Ended | | | (Dollars in thousands) | | September 27,
2014 | | | September 28,
2013 | | Net income | | $ | 94,509 | | | $ | 78,798 | | Add: | | | | | | | | | Provision for income taxes | | | 767 | | | | 607 | | Interest expense, net | | | 83,261 | | | | 95,427 | | Depreciation and amortization | | | 136,399 | | | | 130,384 | | | | | | | | | | | EBITDA | | | 314,936 | | | | 305,216 | | Unrealized (non-cash) (gains) losses on changes in fair value of derivatives | | | (306 | ) | | | 4,318 | | Integration-related costs | | | 12,283 | | | | 10,575 | | Loss on debt extinguishment | | | 11,589 | | | | 2,144 | | Multi-employer pension plan withdrawal charge | | | — | | | | 7,000 | | | | | | | | | | | Adjusted EBITDA | | | 338,502 | | | | 329,253 | | Add (subtract): | | | | | | | | | Provision for income taxes | | | (767 | ) | | | (607 | ) | Interest expense, net | | | (83,261 | ) | | | (95,427 | ) | Unrealized (non-cash) gains (losses) on changes in fair value of derivatives | | | 306 | | | | (4,318 | ) | Integration-related costs | | | (12,283 | ) | | | (10,575 | ) | Multi-employer pension plan withdrawal charge | | | — | | | | (7,000 | ) | Compensation cost recognized under Restricted Unit Plans | | | 7,390 | | | | 3,888 | | Gain on disposal of property, plant and equipment, net | | | (521 | ) | | | (3,543 | ) | Changes in working capital and other assets and liabilities | | | (23,815 | ) | | | 2,635 | | | | | | | | | | | | | | Net cash provided by operating activities | | $ | 225,551 | | | $ | 214,306 | | | | | | | | | | |
Fiscal Year 2013 Compared to Fiscal Year 2012
Revenues
(Dollars in thousands) | | Year Ended | | | | September 26, | | | September 27, | | | | 2015 | | | 2014 | | Net income | | $ | 84,352 | | | $ | 94,509 | | Add: | | | | | | | | | Provision for income taxes | | | 700 | | | | 767 | | Interest expense, net | | | 77,634 | | | | 83,261 | | Depreciation and amortization | | | 133,294 | | | | 136,399 | | EBITDA | | | 295,980 | | | | 314,936 | | Unrealized (non-cash) (gains) losses on changes in fair value of derivatives | | | (1,855 | ) | | | (306 | ) | Loss on debt extinguishment | | | 15,072 | | | | 11,589 | | Integration-related costs | | | 11,542 | | | | 12,283 | | Multi-employer pension plan withdrawal charge | | | 11,300 | | | | — | | Pension settlement charge | | | 2,000 | | | | — | | Adjusted EBITDA | | $ | 334,039 | | | $ | 338,502 | |
| | | | | | | | | | | | | | | | | | (Dollars in thousands) | | Fiscal
2013 | | | Fiscal
2012 | | | Increase | | | Percent
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 | % | | | | | | | | | | | | | | | | | | Total revenues | | $ | 1,703,606 | | | $ | 1,063,458 | | | $ | 640,148 | | | | 60.2 | % | | | | | | | | | | | | | | | | | |
Total revenues increased $640.1 million, or 60.2%, to $1,703.6 million for fiscal 2013 compared to $1,063.5 million for the prior year due to higher volumes sold, offset to an extent by lower average propane, fuel oil and refined fuels and natural gas selling prices. The increase in sales volumes 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 measured in heating degree days) across all of our service territories for fiscal 2013 were 4% warmer than normal, compared to 14% warmer than normal for the prior year.
Revenues from the distribution of propane and related activities of $1,357.1 million for fiscal 2013 increased $513.5 million, or 60.9%, compared to $843.6 million for the prior year, primarily due to higher volumes sold, partially offset by lower average selling prices associated with lower product costs. Retail propane gallons sold in fiscal 2013 increased 250.8 million gallons, or 88.4%, to 534.6 million gallons from 283.8 million gallons in the prior year, primarily as a result of the addition of Inergy Propane, as well as increases in our legacy operations resulting from colder average temperatures. Higher retail propane volumes sold resulted in an increase in revenues of $679.8 million for fiscal 2013 compared to the prior year. Average propane selling prices for fiscal 2013 decreased 11.5% compared to the prior year due to lower wholesale product costs, resulting in a $166.9 million decrease in revenues year-over-year. Included within the propane segment are revenues from risk management activities and other propane activities of $74.7 million for fiscal 2013, which increased $0.6 million compared to the prior year as higher volumes from other propane activities were substantially offset by lower volumes from wholesale and risk management activities.
Revenues from the distribution of fuel oil and refined fuels of $209.0 million for fiscal 2013 increased $94.7 million, or 82.8%, from $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 the addition of Inergy Propane, as well as increases in our legacy operations resulting from colder average temperatures. Higher fuel oil and refined fuels volumes 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 2013 decreased 2.6% compared to the prior year, resulting in a $5.8 million decrease in revenues year-over-year.
Revenues in our natural gas and electricity segment increased $12.0 million, or 17.8%, to $79.4 million in fiscal 2013 compared to $67.4 million in the prior year as a result of higher natural gas volumes sold, and higher electricity average selling prices. The increase in volumes sold was primarily attributable to the more favorable weather pattern in fiscal 2013, compared to the unseasonably warm weather in the prior year.
Cost of Products Sold
| | | | | | | | | | | | | | | | | | (Dollars in thousands) | | Fiscal
2013 | | | Fiscal
2012 | | | Increase | | | Percent
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 | % | | | | | | | | | | | | | | | | | | Total cost of products sold | | $ | 861,905 | | | $ | 599,059 | | | $ | 262,846 | | | | 43.9 | % | | | | | | | | | | | | | | | | | | | | | | | As a percent of total revenues | | | 50.6 | % | | | 56.3 | % | | | | | | | | | | | | | | | | | | | | | | | | | |
Average posted prices for propane for fiscal 2013 were 19.2% lower than the prior year, and fuel oil prices were essentially flat year-over-year. Total cost of products sold increased $262.8 million, or 43.9%, to $861.9 million in fiscal 2013 compared to $599.1 million in the prior year due to higher volumes sold, partially offset by lower average propane product costs. The net change in the fair value of derivative instruments during the period resulted in unrealized (non-cash) losses of $4.3 million and unrealized (non-cash) gains of $4.6 million reported in cost of products sold in fiscal 2013 and 2012, respectively, resulting in an increase of $8.9 million in cost of products sold in fiscal 2013 compared to the prior year, all of which was reported in the propane segment.
Cost of products sold associated with the distribution of propane and related activities of $612.2 million for fiscal 2013 increased $164.1 million, or 36.6%, compared to the prior year. Higher retail propane volumes sold resulted in an increase of $368.4 million in cost of products sold during fiscal 2013 compared to the prior year. The impact of the increase in volumes sold was partially offset by lower average propane costs, which resulted in a $190.0 million decrease in cost of products sold year-over-year. Cost of products sold from other propane activities decreased $23.2 million in fiscal 2013 compared to the prior year, primarily due to lower sales from wholesale and risk management activities.
Cost of products sold associated with our fuel oil and refined fuels segment of $172.0 million for fiscal 2013 increased $80.8 million, or 88.5%, compared to the prior year primarily due to higher fuel oil and refined fuels volumes sold.
Cost of products sold in our natural gas and electricity segment of $56.0 million for fiscal 2013 increased $9.1 million, or 19.4%, compared to the prior year, primarily due to higher natural gas volumes sold, and higher electricity product costs.
Total cost of products sold as a percent of total revenues decreased 5.7 percentage points to 50.6% in fiscal 2013 from 56.3% in the prior year, primarily due to the decline in propane wholesale product costs outpacing the decline in propane average selling prices. In addition, colder average temperatures and the inclusion of Inergy Propane operations resulted in a higher concentration of residential volumes sold in fiscal 2013 compared to the prior year, which had a favorable impact on overall gross margins.
Operating Expenses
| | | | | | | | | | | | | | | | | | (Dollars in thousands) | | Fiscal
2013 | | | Fiscal
2012 | | | Increase | | | Percent
Increase | | Operating expenses | | $ | 469,496 | | | $ | 298,772 | | | $ | 170,724 | | | | 57.1 | % | As a percent of total revenues | | | 27.6 | % | | | 28.1 | % | | | | | | | | |
Operating expenses of $469.5 million for fiscal 2013 increased $170.7 million, or 57.1%, compared to $298.8 million in the prior year, primarily due to the addition of Inergy Propane, offset to an extent by lower payroll and benefit related expenses in our legacy operations resulting from operating 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 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 charges were excluded 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 the combined operating expenses of Inergy Propane and our legacy operations.
General and Administrative Expenses
| | | | | | | | | | | | | | | | | | (Dollars in thousands) | | Fiscal
2013 | | | Fiscal
2012 | | | Increase | | | Percent
Increase | | General and administrative expenses | | $ | 64,845 | | | $ | 59,020 | | | $ | 5,825 | | | | 9.9 | % | As a percent of total revenues | | | 3.8 | % | | | 5.5 | % | | | | | | | | |
General and administrative expenses of $64.8 million for fiscal 2013 increased $5.8 million compared to $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 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
2013 | | | Fiscal
2012 | | | Increase | | | Percent
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
2013 | | | Fiscal
2012 | | | Increase | | | Percent
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 due to the issuance of $496.6 million in aggregate principal amount of 7.5% senior notes due October 1, 2018 and $503.4 million in aggregate principal amount of 7.375% senior notes due August 1, 2021 in connection with the Inergy Propane Acquisition on August 1, 2012. See Liquidity and Capital Resources below for additional discussion.
Loss on Debt Extinguishment
On August 2, 2013, we repurchased, pursuant to an 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, 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 for fiscal 2013 amounted to $78.8 million, or $1.35 per Common Unit, compared to $0.6 million, or $0.02 per Common Unit, in fiscal 2012. Earnings before interest, taxes, depreciation and amortization (“EBITDA”) for fiscal 2013 amounted to $305.2 million, compared to $86.4 million for fiscal 2012.
Net income and EBITDA for fiscal 2013 included: (i) $10.6 million in expenses related to the ongoing 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 Inergy Propane Acquisition; and (iii) a loss on debt extinguishment of $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 legal settlement; (iii) a $2.1 million non-cash charge from a loss on disposal of an 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 Adjusted EBITDA of $108.5 million in fiscal 2012.
The following table sets forth (i) our calculations of EBITDA and adjusted EBITDA and (ii) a reconciliation of both EBITDA and adjusted EBITDA, as so calculated, to our net cash provided by operating activities:
| | | | | | | | | | | | Year Ended | | | (Dollars in thousands) | | September 28,
2013 | | | September 29,
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 | | | | — | | Loss on debt extinguishment | | | 2,144 | | | | 2,249 | | Multi-employer pension plan withdrawal charge | | | 7,000 | | | | — | | 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 | | | | | | | | | | |
Liquidity and Capital Resources Analysis of Cash Flows Operating Activities. Net cash provided by operating activities for fiscal 20142016 amounted to $225.5$157.1 million, an increasea decrease of $11.2$167.1 million compared to the prior year. The increasedecrease was primarily attributable to an increase inlower earnings after adjusting for non-cash items in both periods. In addition, average posted prices for propane during(discussed above) coupled with a lower amount of working capital realized as a result of a lower level of working capital at the beginning of fiscal 2014 increased 24.8%2016 compared to the prior year, which resultedbeginning of fiscal 2015. The decline in a substantial increase in working capital requirements year-over-year. Cash flows from operating activities for fiscal 2013 benefited to an extent by the realizationamount of working capital acquiredwas due to the impact of the steep decline in the Inergy Propane Acquisition. wholesale product costs on our accounts receivable and inventory in fiscal 2015.Investing Activities. Net cash used in investing activities of $16.5$53.9 million for fiscal 20142016 consisted of $42.9 million for the acquisition of Propane USA and capital expenditures of $30.1$38.4 million (including $18.2 million for maintenance expenditures and $11.9$21.8 million to support the growth of operations),operations and $16.6 million for maintenance expenditures); partially offset by $21.5 million in proceeds from the sale of assets and operations in a non-strategic market and $6.0 million in net proceeds of $13.5 million from the sale of property, plant and equipment. Net cash used in investing activities of $14.7$36.0 million for fiscal 20132015 consisted of capital expenditures of $27.8$41.2 million (including $8.3 million for maintenance expenditures and $19.5$21.8 million to support the growth of operations),operations and $19.4 million for maintenance expenditures) and $6.5 million for the acquisition of a business; partially offset by the$11.7 million in 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.equipment. Financing Activities. Net cash used in financing activities for fiscal 20142016 of $223.6$218.2 million reflects the quarterly distribution to Common Unitholders at a rate of $0.8875 per Common Unit paid in respect of the fourth quarter of fiscal 2015 and the first, second and third quarters of fiscal 2016. Upon the execution of the amendment and restatement of our credit agreement on March 3, 2016, we rolled the $100.0 million then-outstanding under the revolving credit facility of the previous credit agreement into the revolving credit facility of the new second amended and restated credit agreement. This resulted in the repayment of the $100.0 million then-outstanding under the revolving credit facility of the previous credit agreement with proceeds from borrowings under the revolving credit facility of the new credit agreement. Financing activities for fiscal 2016 also reflects the payment of $2.7 million in debt origination costs associated with the refinancing of the credit agreement. Net cash used in financing activities for fiscal 2015 of $228.5 million reflects the quarterly distribution to Common Unitholders at a rate of $0.8750 per Common Unit paid in respect of the fourth quarter of fiscal 20132014 and the first quarter of fiscal 2015, and at a rate of $0.8875 per Common Unit paid in respect of the second and third quarters of fiscal 2014.2015. In addition, cash used in financing activities included proceeds of $525.0$250.0 million from the issuance of the 20242025 Senior Notes in May 2014. The net proceeds from the 2024 Senior Notes offeringFebruary 2015 which were used, along with cash on hand, to repurchase and satisfy and discharge all of the previously outstanding 20182020 Senior Notes, as well as to pay tender premiums and other related fees of $31.6$11.1 million and debt issuance costs of $9.5$4.6 million, pursuant to a tender offer and redemption. Net cash used in financing activities for fiscal 2013 of $226.7 million reflects the quarterly distribution to Common Unitholders at a rate of $0.8525 per Common Unit paid in respect of the fourth quarter of fiscal 2012 and at a rate of $0.8750 per Common Unit paid in respect of the first, second and third quarters of fiscal 2013. In addition, net cash used in financing activities for fiscal 2013 includes proceeds of $143.4 million from the issuance of 3,105,000 of our Common Units in May 2013. The net proceeds from the equity offering, along with cash on hand, were used to redeem $157.3 million of our 2021 Senior Notes in August 2013.
Equity Offering
On May 17, 2013, we sold 2,700,000 Common Units in a public offering at a price of $48.16 per Common Unit realizing proceeds of $124.7 million, net of underwriting commissions and other offering expenses. On May 22, 2013, following the underwriters’ exercise of their over-allotment option, we sold an additional 405,000 Common Units at $48.16 per Common Unit, generating additional proceeds of $18.7 million, net of underwriting commissions. The net proceeds from the offering, including the net proceeds from the underwriters’ exercise of their over-allotment option, were used to redeem $133.4 million of our 2021 senior notes in August 2013, including prepayment premiums and other expenses.
Summary of Long-Term Debt Obligations and Revolving Credit Lines As of September 27, 2014,24, 2016, our long-term debt consisted of $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 (excluding unamortized premium of $17.0 million), $525.0 million in aggregate principal amount of 5.5% senior 34
notes due June 1, 2024, $250.0 million in aggregate principal amount of 5.75% senior notes due March 1, 2025 and $100.0 million outstanding 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 See Part IV, Note 8 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.
On May 27, 2014, we repurchased and satisfied and discharged all of our 2018 Senior Notes with net proceeds from the issuance of the 2024 Senior Notes, as defined below, and cash on hand, pursuant to a tender offer and redemption during the third quarter of fiscal 2014. In connection with this tender offer and redemption, we recognized a loss on the extinguishment of debt of $11.6 million consisting of $31.6 million for the redemption premium and related fees, as well as the write-off of $5.3 million and ($25.3) million in unamortized debt origination costs and unamortized premium, respectively. The 2018 Senior Notes required semi-annual interest payments in April and October, and the 2021 Senior Notes require semi-annual interest payments in February and August.
The 2021 Senior Notes are redeemable, at our option, in whole or in part, at any time on or 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 then-outstanding unregistered 7.5% senior notes due 2018 and 7.375% senior notes due 2021 (collectively, the “Old Notes”) for an equal principal amount of 7.5% senior notes due 2018 and 7.375% senior notes due 2021 (collectively, 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 amount, 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, the 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 and require semi-annual interest payments in March and September.
The 2020 Senior Notes are redeemable, at our option, in whole or in part, at any time on or after March 15, 2015, 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 | | 2015 | | | 103.688 | % | 2016 | | | 102.458 | % | 2017 | | | 101.229 | % | 2018 and thereafter | | | 100.000 | % |
2024 Senior Notes
As previously discussed, on May 27, 2014, the Partnership and its 100%-owned subsidiary, Suburban Energy Finance Corp., completed a public offering of $525.0 million in aggregate principal amount of 5.5% senior notes due June 1, 2024 (the “2024 Senior Notes”). The 2024 Senior Notes were issued at 100% of the principal amount and require semi-annual interest payments in June and December, beginning in December 2014. The net proceeds from the issuance of the 2024 Senior Notes, along with cash on hand, were used to repurchase and satisfy and discharge all of the 2018 Senior Notes.
The 2024 Senior Notes are redeemable, at our option, in whole or in part, at any time on or after June 1, 2019, 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 | | 2019 | | | 102.750 | % | 2020 | | | 101.833 | % | 2021 | | | 100.917 | % | 2022 and thereafter | | | 100.000 | % |
Our obligations under the 2020 Senior Notes, 2021 Senior Notes and 2024 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 each have a change of control provision that would require us 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.
Credit Agreement
Our Operating Partnership has an amended and restated credit agreement entered into on January 5, 2012, as amended on August 1, 2012 and May 9, 2014 (collectively, the “Amended Credit Agreement”) that provides for a five-year $400.0 million revolving credit facility (the “Revolving Credit Facility”), of which $100.0 million was outstanding as of September 27, 2014 and September 28, 2013. Borrowings under the Revolving Credit Facility may be used for general corporate purposes, including working capital, capital expenditures and acquisitions. Our Operating Partnership has the right to prepay any borrowings under the Revolving Credit Facility, in whole or in part, without penalty at any time prior to maturity.
During the second quarter of fiscal 2014, we experienced a significant increase in working capital requirements as a result of the impact of the significant increase in wholesale propane costs. This increase in working capital requirements resulted in the net borrowing of $61.7 million under our Revolving Credit Facility during fiscal 2014. The borrowings were repaid in full during fiscal 2014 with internally generated cash.
The amendment and restatement of 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.
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 second quarter of fiscal 2014, such minimum ratio is 2.5 to 1.0. The maximum consolidated leverage ratio decreases over time, as well as upon the occurrence of certain events, and, commencing with the second quarter of fiscal 2013, such maximum ratio is 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.
The second amendment to the Amended Credit Agreement on May 9, 2014 made certain technical amendments with respect to agreements relating to debt refinancing.
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 the Operating Partnership’s option, LIBOR plus the applicable margin or the base rate, defined as the higher of the Federal Funds Rate plus 1⁄2 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 our ratio of Consolidated Total Debt to Consolidated EBITDA, as defined in the Revolving Credit Facility. As of September 27, 2014, the interest rate for the Revolving Credit Facility was approximately 2.5%. The interest rate and the applicable margin will be reset at the end of each calendar quarter.
In connection with the Amended Credit Agreement, our Operating Partnership entered into an interest rate swap agreement with a June 25, 2013 effective date and a maturity date of January 5, 2017. Under this 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. The interest rate swap has been designated as a cash flow hedge.
As of September 27, 2014, our Operating Partnership had standby letters of credit issued under the Revolving Credit Facility in the aggregate amount of $44.9 million which expire periodically through April 3, 2015. Therefore, as of September 27, 2014, after giving effect to $100.0 million in outstanding borrowings, we had available borrowing capacity of $255.1 million under the Revolving Credit Facility.
The Amended Credit Agreement and the 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. Under the Amended Credit Agreement and the indentures governing the Senior Notes, the Operating Partnership and 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, 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 Senior Notes and the Amended Credit Agreement as of September 27, 2014.
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 2014, we recognized charges of $5.3 million to write-off unamortized debt origination costs associated with the tender offer and redemption of our 2018 Senior Notes. 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. Other assets at September 27, 2014 and September 28, 2013 include debt origination costs with a net carrying amount of $21.0 million and $21.3 million, respectively.Annual Report.
The aggregate amounts of long-term debt maturities subsequent to September 27, 201424, 2016 are as follows: fiscal 2015 through fiscal 2016:2017: $-0-; fiscal 2017: $100.0 million; fiscal 2018: $-0-; fiscal 2019: $-0-; fiscal 2020: $-0-; fiscal 2021: $446.2 million; and thereafter: $1,121.2$775.0 million. Partnership Distributions We are required to make distributions in an amount equal to all of our Available Cash, as defined in our Third Amended and Restated Partnership Agreement, as amended (the “Partnership Agreement”), no more than 45 days after the end of each fiscal quarter to holders of record on the applicable record dates. Available Cash, as defined in 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 23, 2014,20, 2016, we announced that our Board of Supervisors had declared a quarterly distribution of $0.8750$0.8875 per Common Unit for the three months ended September 27, 2014.24, 2016. This quarterly distribution rate equates to an annualized rate of $3.50$3.55 per Common Unit. The distribution was paid on November 10, 20148, 2016 to Common Unitholders of record as of November 3, 2014.1, 2016. Pension Plan Assets and Obligations We have a noncontributory defined benefit pension plan which was originally designed to cover all of our eligible employees 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. We made a minimum required funding payment of $0.7 million in fiscal 2016. There were no minimumsuch funding requirements for the defined benefit pension plan duringin fiscal 2014, 20132015 or 2012.2014. As of September 27, 201424, 2016 and September 28, 201326, 2015 the plan’s projected benefit obligation exceeded the fair value of plan assets by $32.1$49.3 million and $27.9$42.6 million, respectively. As a result, the net liability recognized in the consolidated financial statements for the defined benefit pension plan increased by $4.2$6.7 million during fiscal 2014,2016, which was primarily attributable to an increase in the present valuebenefit obligation as a result of the decrease in discount rates used to measure the obligation, partially offset by a return on plan assets that outpaced the interest cost of the benefit obligation dueobligation. During fiscal 2017, the Partnership expects to contribute approximately $10.7 million to the defined benefit pension plan in the form of a general decrease in market interest rates.minimum funding requirement. 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 recent fiscal years, significant declines in interest rates relevant to our benefit obligations, and/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 27, 201424, 2016 and September 28, 2013,26, 2015, we used a discount rate of 3.875%3.125% and 4.375%3.875%, respectively, reflecting current market rates for debt obligations of a similar duration to our pension obligations. During fiscal 2014, fiscal 20132016 and fiscal 2012,2015, lump sum settlement payments of $5.8 million in each year exceeded the interest and service cost components of the net periodic pension cost. As a result, we recorded a non-cash settlement charge of $2.0 million during the fourth quarter of fiscal 2016 and fiscal 2015, respectively, 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 2014, the amount of the pension benefit obligationobligations settled through lump sum payments did not exceed the settlement threshold (combined service and interest costs of net periodic pension cost); therefore, a settlement charge was not required to be recognized in any of those fiscal years.recognized. 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,March 31, 1998, we terminatedfroze participation 35
in our postretirement health care benefit plan, for allwith no new retirees eligible employees retiring after March 1, 1998.to participate in the plan. 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. Long-Term Debt Obligations and Operating Lease Obligations Contractual Obligations The following table summarizes payments due under our known contractual obligations as of September 27, 2014:24, 2016: (Dollars in thousands) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Fiscal | | | (Dollars in thousands) | | Fiscal
2015 | | | Fiscal
2016 | | | Fiscal
2017 | | | Fiscal
2018 | | | Fiscal
2019 | | | Fiscal
2020 and
thereafter | | | | | | Fiscal | | | Fiscal | | | Fiscal | | | Fiscal | | | Fiscal | | | 2022 and | | | | | 2017 | | | 2018 | | | 2019 | | | 2020 | | | 2021 | | | thereafter | | Long-term debt obligations | | $ | — | | | $ | — | | | $ | 100,000 | | | $ | — | | | $ | — | | | $ | 1,121,180 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 446,180 | | | $ | 775,000 | | Interest payments | | | 77,999 | | | | 77,999 | | | | 75,493 | | | | 72,843 | | | | 72,843 | | | | 204,655 | | | | 73,937 | | | | 73,064 | | | | 73,064 | | | | 73,064 | | | | 71,660 | | | | 136,938 | | Operating lease obligations (a) | | | 25,266 | | | | 17,781 | | | | 12,199 | | | | 9,224 | | | | 6,131 | | | | 7,469 | | | | 22,580 | | | | 18,796 | | | | 15,050 | | | | 12,519 | | | | 9,497 | | | | 15,841 | | Self-insurance obligations (b) | | | 14,356 | | | | 12,236 | | | | 9,232 | | | | 5,374 | | | | 3,369 | | | | 17,883 | | | | 10,168 | | | | 10,383 | | | | 8,833 | | | | 7,201 | | | | 6,012 | | | | 16,451 | | Other contractual obligations (c) | | | 4,308 | | | | 4,156 | | | | 4,054 | | | | 2,201 | | | | 1,282 | | | | 16,592 | | | | | | | | | | | | | | | | | | | | | | | Pension contributions (c) | | | | 10,704 | | | | 9,570 | | | | 7,570 | | | | 9,175 | | | | 5,400 | | | | — | | Other contractual obligations (d) | | | | 3,232 | | | | 3,944 | | | | 3,354 | | | | 1,811 | | | | 1,502 | | | | 13,985 | | Total | | $ | 121,929 | | | $ | 112,172 | | | $ | 200,978 | | | $ | 89,642 | | | $ | 83,625 | | | $ | 1,367,779 | | | $ | 120,621 | | | $ | 115,757 | | | $ | 107,871 | | | $ | 103,770 | | | $ | 540,251 | | | $ | 958,215 | | | | | | | | | | | | | | | | | | | | | |
(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 amount to $3.9 million, $3.5$2.7 million, $2.7 million, $2.4 million, $1.7 million, $1.5 million $0.9 million and $5.8$4.5 million for each of the next five fiscal years and thereafter, respectively, and are included in other assets on the consolidated balance sheet. |
(c) | Amounts represent estimated minimum funding requirements for our pension plan. |
(d) | These amounts are included in our consolidated balance sheet and primarily include payments for postretirement and long-term incentive benefits. |
Additionally, we have standby letters of credit in the aggregate amount of $44.9$43.3 million, in support of retention levels under our casualty insurance programs and certain lease obligations, which expire periodically through April 3, 2015.2017. Operating Leases We lease certain property, plant and equipment for various periods under noncancelable operating leases, including 47%46% of our vehicle fleet, approximately 27%26% of our customer service centers and portions of our information systems equipment. Rental expense under operating leases was $31.8$29.2 million, $33.0$32.7 million and $23.6$31.8 million for fiscal 2014, 20132016, 2015 and 2012,2014, respectively. Future minimum rental commitments under noncancelable operating lease agreements as of September 27, 201424, 2016 are presented in the table above. Off-Balance Sheet Arrangements Guarantees Certain of our operating leases, primarily those for transportation equipment with remaining lease periods scheduled to expire periodically through fiscal 2021,2023, 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, was approximately $14.1$16.0 million. The fair value of residual value guarantees for outstanding operating leases was de minimis as of September 27, 201424, 2016 and September 28, 2013.26, 2015. 36
Recently Issued Accounting Pronouncements.Pronouncements In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-09 “Revenue from Contracts with Customers” (“ASU 2014-09”). This update provides a principles-based approach to revenue recognition, requiring revenue recognition to depict the transferSee Part IV, Note 2 of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The ASU provides a five-step model to be applied to all contracts with customers. The five steps are to identify the contract(s) with the customer, identify the performance obligations in the contract, determine the transaction price, allocate the transaction price to the performance obligations in the contract and recognize revenue when each performance obligation is satisfied. The revenue standard is effective for the first interim period within annual reporting periods beginning after December 15, 2016, which will be our first quarter of fiscal year 2018. ASU 2014-09 can be applied either retrospectively to each prior reporting period presented or retrospectively with the cumulative effect of initially applying the update recognized at the date of the initial application along with additional disclosures. We are evaluating the impacts, if any, the adoption of ASU 2014-09 will have on our results of operations, financial position or cash flows.
Recently Adopted Accounting Pronouncements.
In December 2011, the FASB issued an ASU regarding disclosures about offsetting assets and liabilities (“ASU 2011-11”). The new guidance requires an entity to disclose information about offsetting and related arrangements to enable users of financial statements to understand the effect of those arrangements on its financial position. The amendment, further clarified with ASU 2013-01, enhances 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. We adopted ASU 2011-11 and ASU 2013-01 on September 29, 2013 and included further disclosure regarding offsetting assets and liabilities for derivative instruments accounted for under ASC 815. As this guidance affects disclosures only, its adoption had no impact on our financial position, results of operations or cash flows.Annual Report.
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”). We adopted ASU 2013-02 on September 29, 2013 and its adoption did not change the items that must be reported in other comprehensive income, nor did it have an impact on our financial position, results of operations or cash flows.
ITEM 7A. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
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. Product cost changes can occur rapidly over a short period of time and can impact profitability. We attempt to reduce commodity price risk by pricing product on a short-term basis. The level of priced, physical product maintained in storage facilities and at our customer service centers for immediate sale to our customers will vary depending on several factors, including, but not limited to, price, supply and demand dynamics for a given time of the year. Typically, our on hand priced position does not exceed more than four to eight weeks of our supply needs, depending on the time of the year. In the course of normal operations, we routinely enter into contracts such as forward priced physical contracts for the purchase or sale of propane and fuel oil that, under accounting rules for derivative instruments and hedging activities, qualify for and are designated as normal purchase or normal sale contracts. Such contracts are exempted from fair value accounting and are accounted for at the time product is purchased or sold under the related contract. Under our hedging and risk management strategies, we enter into a combination of exchange-traded futures and options contracts and, in certain instances, over-the-counter options 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 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, or delivered to customers as it pertains to fixed price contracts. Futures are traded with brokers of the NYMEX and require daily cash settlements in margin accounts. Forward contracts are generally settled at the expiration of the contract term by physical delivery, and swap and options contracts are generally settled at expiration through a net settlement mechanism. Market risks associated with our 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 options 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 options 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 plus 1⁄2 ½ 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 37
consolidated leverage ratio (the 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 27, 2014,24, 2016, the fair value of the interest rate swaps was a net liability of $1.5$0.2 million, which is included within other current liabilities and other liabilities, as applicable, with a corresponding unrealized loss reflected in accumulated other comprehensive income. Derivative Instruments and Hedging Activities All of our derivative instruments are reported on the balance sheet at their fair values. On the date that derivative 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 27, 2014.24, 2016. |
| 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 derivative instruments as of September 27, 201424, 2016 indicates an increase in potential future net losses of $2.7$1.0 million. 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. 38
ITEM 8. | FINANCIAL STATEMENTSSTATEMENTS AND SUPPLEMENTARY DATA |
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 Quarter | | | Second Quarter | | | Third Quarter | | | Fourth Quarter | | | Total Year | | | | | First
Quarter | | Second
Quarter | | Third
Quarter | | Fourth
Quarter | | Total
Year | | | Fiscal 2014 | | | | | | | | | | | | Fiscal 2016 | | | | | | | | | | | | | | | | | | | | | | Revenues | | $ | 526,056 | | | $ | 873,772 | | | $ | 297,143 | | | $ | 241,286 | | | $ | 1,938,257 | | | $ | 275,857 | | | $ | 404,140 | | | $ | 205,099 | | | $ | 161,015 | | | $ | 1,046,111 | | Cost of products sold | | | 280,526 | | | 517,198 | | | 161,482 | | | 121,544 | | | 1,080,750 | | | Costs of products sold | | | | 92,506 | | | | 137,009 | | | | 75,497 | | | | 56,941 | | | | 361,953 | | Gain on sale of business (a) | | | | — | | | | — | | | | 9,769 | | | | — | | | | 9,769 | | Operating income (loss) | | | 80,055 | | | 171,044 | | | (26,575 | ) | | (34,398 | ) | | 190,126 | | | | 31,344 | | | | 111,213 | | | | (10,780 | ) | | | (41,371 | ) | | | 90,406 | | Loss on debt extinguishment (a) | | | — | | | | — | | | 11,589 | | | | — | | | 11,589 | | | Loss on debt extinguishment (b) | | | | — | | | | 292 | | | | — | | | | — | | | | 292 | | Net income (loss) | | | 58,671 | | | 149,547 | | | (58,989 | ) | | (54,720 | ) | | 94,509 | | | | 12,266 | | | | 92,011 | | | | (29,598 | ) | | | (60,239 | ) | | | 14,440 | | Net income (loss) per common unit—basic (b) | | | 0.97 | | | 2.47 | | | (0.98 | ) | | (0.90 | ) | | 1.56 | | | Net income (loss) per common unit—diluted (b) | | | 0.97 | | | 2.46 | | | (0.98 | ) | | (0.90 | ) | | 1.56 | | | Net income (loss) per Common Unit - basic (c) | | | $ | 0.20 | | | $ | 1.51 | | | $ | (0.49 | ) | | $ | (0.99 | ) | | $ | 0.24 | | Net income (loss) per Common Unit - diluted (c) | | | $ | 0.20 | | | $ | 1.51 | | | $ | (0.49 | ) | | $ | (0.99 | ) | | $ | 0.24 | | | | | | | | | | | | | | | | | | | | | | | | Cash provided by (used in): | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Operating activities | | | 4,161 | | | 16,226 | | | 124,583 | | | 80,581 | | | 225,551 | | | | 10,351 | | | | 70,136 | | | | 48,173 | | | | 28,448 | | | | 157,108 | | Investing activities | | | (3,424 | ) | | (4,947 | ) | | (3,731 | ) | | (4,430 | ) | | (16,532 | ) | | | (52,505 | ) | | | (11,399 | ) | | | 14,542 | | | | (4,543 | ) | | | (53,905 | ) | Financing activities | | | (52,702 | ) | | 2,232 | | | (120,313 | ) | | (52,829 | ) | | (223,612 | ) | | | (53,722 | ) | | | (56,517 | ) | | | (54,011 | ) | | | (53,950 | ) | | | (218,200 | ) | EBITDA (c) | | $ | 114,882 | | | $ | 204,326 | | | $ | (5,172 | ) | | $ | 900 | | | $ | 314,936 | | | Adjusted EBITDA (c) | | $ | 117,708 | | | $ | 206,269 | | | $ | 10,023 | | | $ | 4,502 | | | $ | 338,502 | | | EBITDA (d) | | | $ | 62,982 | | | $ | 144,071 | | | $ | 21,508 | | | $ | (8,831 | ) | | $ | 219,730 | | Adjusted EBITDA (d) | | | $ | 67,192 | | | $ | 145,102 | | | $ | 18,395 | | | $ | (7,646 | ) | | $ | 223,043 | | Retail gallons sold | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Propane | | | 157,858 | | | 213,689 | | | 83,156 | | | 76,040 | | | 530,743 | | | | 109,764 | | | | 161,597 | | | | 80,184 | | | | 63,231 | | | | 414,776 | | Fuel oil and refined fuels | | | 13,997 | | | 22,617 | | | 6,981 | | | 5,476 | | | 49,071 | | | | 8,565 | | | | 13,296 | | | | 5,771 | | | | 3,246 | | | | 30,878 | | | | | | | | | | | | | | | | | | | | | | | | Fiscal 2013 | | | | | | | | | | | | Fiscal 2015 | | | | | | | | | | | | | | | | | | | | | | Revenues | | $ | 490,703 | | | $ | 678,426 | | | $ | 290,805 | | | $ | 243,672 | | | $ | 1,703,606 | | | $ | 422,944 | | | $ | 599,389 | | | $ | 220,302 | | | $ | 174,344 | | | $ | 1,416,979 | | Cost of products sold | | | 245,100 | | | 346,999 | | | 148,176 | | | 121,630 | | | 861,905 | | | Costs of products sold | | | | 187,921 | | | | 253,667 | | | | 94,198 | | | | 57,594 | | | | 593,380 | | Operating income (loss) | | | 82,308 | | | 153,977 | | | (20,654 | ) | | (38,655 | ) | | 176,976 | | | | 75,968 | | | | 171,591 | | | | (21,834 | ) | | | (47,967 | ) | | | 177,758 | | Loss on debt extinguishment (a) | | | — | | | | — | | | | — | | | 2,144 | | | 2,144 | | | Loss on debt extinguishment (b) | | | | — | | | | 15,072 | | | | — | | | | — | | | | 15,072 | | Net income (loss) | | | 57,620 | | | 129,484 | | | (45,187 | ) | | (63,119 | ) | | 78,798 | | | | 55,807 | | | | 136,634 | | | | (40,952 | ) | | | (67,137 | ) | | | 84,352 | | Net income (loss) per common unit—basic (b) | | | 1.05 | | | 2.29 | | | (0.77 | ) | | (1.05 | ) | | 1.35 | | | Net income (loss) per common unit—diluted (b) | | | 1.04 | | | 2.28 | | | (0.77 | ) | | (1.05 | ) | | 1.34 | | | Net income (loss) per Common Unit - basic (c) | | | $ | 0.92 | | | $ | 2.26 | | | $ | (0.67 | ) | | $ | (1.11 | ) | | $ | 1.39 | | Net income (loss) per Common Unit - diluted (c) | | | $ | 0.92 | | | $ | 2.24 | | | $ | (0.67 | ) | | $ | (1.11 | ) | | $ | 1.38 | | | | | | | | | | | | | | | | | | | | | | | | Cash provided by (used in): | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Operating activities | | | 61,537 | | | 72,426 | | | 66,505 | | | 13,838 | | | 214,306 | | | | 33,605 | | | | 126,332 | | | | 99,205 | | | | 65,067 | | | | 324,209 | | Investing activities | | | 1,847 | | | (4,999 | ) | | (6,532 | ) | | (4,979 | ) | | (14,663 | ) | | | (11,453 | ) | | | (10,083 | ) | | | (8,419 | ) | | | (6,017 | ) | | | (35,972 | ) | Financing activities | | | (48,605 | ) | | (49,965 | ) | | 93,459 | | | (221,617 | ) | | (226,728 | ) | | | (52,777 | ) | | | (68,197 | ) | | | (53,843 | ) | | | (53,721 | ) | | | (228,538 | ) | EBITDA (c) | | $ | 112,835 | | | $ | 185,293 | | | $ | 10,850 | | | $ | (3,762 | ) | | $ | 305,216 | | | Adjusted EBITDA (c) | | $ | 117,473 | | | $ | 190,668 | | | $ | 19,171 | | | $ | 1,941 | | | $ | 329,253 | | | EBITDA (d) | | | $ | 108,597 | | | $ | 189,748 | | | $ | 10,896 | | | $ | (13,261 | ) | | $ | 295,980 | | Adjusted EBITDA (d) | | | $ | 101,005 | | | $ | 214,316 | | | $ | 12,067 | | | $ | 6,651 | | | $ | 334,039 | �� | Retail gallons sold | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Propane | | | 153,933 | | | 210,314 | | | 92,109 | | | 78,265 | | | 534,621 | | | | 134,534 | | | | 199,690 | | | | 77,633 | | | | 68,515 | | | | 480,372 | | Fuel oil and refined fuels | | | 15,885 | | | 23,223 | | | 8,331 | | | 6,271 | | | 53,710 | | | | 11,261 | | | | 19,898 | | | | 6,181 | | | | 4,538 | | | | 41,878 | |
(a) | DuringOn April 22, 2016, we sold certain assets and operations in a non-strategic market of the propane segment for $26.0 million, including $5.0 million of non-compete consideration that will be received over a five-year period, resulting in a gain of $9.8 million that was recognized during the third quarter of fiscal 2014,2016. |
(b) | During the second quarter of fiscal 2016, we entered into a Second Amended and Restated Credit Agreement that provides for a five-year $500.0 million revolving credit facility. In connection with the Amended Credit Agreement, we recognized a non- |
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| cash charge of $0.3 million to write-off a portion of unamortized debt origination costs of the previous credit agreement. During the second quarter of fiscal 2015, we repurchased and satisfied and discharged all of our 20182020 Senior Notes with net proceeds from the issuance of the 20242025 Senior Notes and cash on hand, pursuant to a tender offer and redemption. In connection with this tender offer and redemption, we recognized a loss on the extinguishment of debt of $11.6$15.1 million consisting of $31.6$11.1 million for the redemption premium and related fees, as well as the write-off of $5.3$2.9 million and ($25.3)$1.1 million in unamortized debt origination costs and unamortized premium,discount, respectively. During the fourth quarter of fiscal 2013, we repurchased pursuant to an 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, 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. |
(b)(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 Restricted Unit Plans to retirement-eligible grantees. Computations of diluted net income per Common Unit are performed by dividing net income by the weighted average number of outstanding Common Units and unvested restricted units granted under our Restricted Unit Plans. Diluted loss per Common Unit for the periods where a net loss was reported does not include unvested restricted units granted under our Restricted Unit Plans as their effect would be anti-dilutive. On May 17, 2013, we sold 2.7 million Common Units in a public offering. On May 22, 2013, following the underwriters’ exercise of their over-allotment option, we sold an additional 0.4 million Common Units. |
(c)(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 fromon mark-to-market activity for derivative instruments and other certain items, as applicable, as provided in the table below. Our management uses EBITDA and Adjusted EBITDA as supplemental measures of liquidityoperating performance 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.operating results. 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. The following table sets forth (i) our calculations of EBITDA and (ii) a reconciliation of EBITDA, as so calculated, to our net cash provided by (used in) operating activities (amounts in thousands):Adjusted EBITDA: |
| | | | | | | | | | | | | | | | | | | | | Fiscal 2014 | | First
Quarter | | | Second
Quarter | | | Third
Quarter | | | Fourth
Quarter | | | Total
Year | | Net income (loss) | | $ | 58,671 | | | $ | 149,547 | | | $ | (58,989 | ) | | $ | (54,720 | ) | | $ | 94,509 | | Add: | | | | | | | | | | | | | | | | | | | | | Provision for income taxes | | | 177 | | | | 271 | | | | 163 | | | | 156 | | | | 767 | | Interest expense, net | | | 21,207 | | | | 21,226 | | | | 20,662 | | | | 20,166 | | | | 83,261 | | Depreciation and amortization | | | 34,827 | | | | 33,282 | | | | 32,992 | | | | 35,298 | | | | 136,399 | | | | | | | | | | | | | | | | | | | | | | | EBITDA | | | 114,882 | | | | 204,326 | | | | (5,172 | ) | | | 900 | | | | 314,936 | | Unrealized (non-cash) losses (gains) on changes in fair value of derivatives | | | 290 | | | | (291 | ) | | | (707 | ) | | | 402 | | | | (306 | ) | Integration related costs | | | 2,536 | | | | 2,234 | | | | 4,313 | | | | 3,200 | | | | 12,283 | | Loss on debt extinguishment | | | — | | | | — | | | | 11,589 | | | | — | | | | 11,589 | | | | | | | | | | | | | | | | | | | | | | | Adjusted EBITDA | | | 117,708 | | | | 206,269 | | | | 10,023 | | | | 4,502 | | | | 338,502 | | Add (subtract): | | | | | | | | | | | | | | | | | | | | | Provision for income taxes | | | (177 | ) | | | (271 | ) | | | (163 | ) | | | (156 | ) | | | (767 | ) | Interest expense, net | | | (21,207 | ) | | | (21,226 | ) | | | (20,662 | ) | | | (20,166 | ) | | | (83,261 | ) | Unrealized (non-cash) (losses) gains on changes in fair value of derivatives | | | (290 | ) | | | 291 | | | | 707 | | | | (402 | ) | | | 306 | | Integration related costs | | | (2,536 | ) | | | (2,234 | ) | | | (4,313 | ) | | | (3,200 | ) | | | (12,283 | ) | Compensation cost recognized under Restricted Unit Plans | | | 1,638 | | | | 1,951 | | | | 2,074 | | | | 1,727 | | | | 7,390 | | (Gain) loss on disposal of property, plant and equipment, net | | | (237 | ) | | | (282 | ) | | | 179 | | | | (181 | ) | | | (521 | ) | Changes in working capital and other assets and liabilities | | | (90,738 | ) | | | (168,272 | ) | | | 136,738 | | | | 98,457 | | | | (23,815 | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | Net cash provided by operating activities | | $ | 4,161 | | | $ | 16,226 | | | $ | 124,583 | | | $ | 80,581 | | | $ | 225,551 | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | Fiscal 2013 | | First
Quarter | | | Second
Quarter | | | Third
Quarter | | | Fourth
Quarter | | | Total
Year | | Net income (loss) | | $ | 57,620 | | | $ | 129,484 | | | $ | (45,187 | ) | | $ | (63,119 | ) | | $ | 78,798 | | Add: | | | | | | | | | | | | | | | | | | | | | Provision for income taxes | | | 132 | | | | 150 | | | | 148 | | | | 177 | | | | 607 | | Interest expense, net | | | 24,556 | | | | 24,343 | | | | 24,385 | | | | 22,143 | | | | 95,427 | | Depreciation and amortization | | | 30,527 | | | | 31,316 | | | | 31,504 | | | | 37,037 | | | | 130,384 | | | | | | | | | | | | | | | | | | | | | | | EBITDA | | | 112,835 | | | | 185,293 | | | | 10,850 | | | | (3,762 | ) | | | 305,216 | | Unrealized (non-cash) losses (gains) on changes in fair value of derivatives | | | 3,614 | | | | 2,646 | | | | 73 | | | | (2,015 | ) | | | 4,318 | | Integration related costs | | | 1,024 | | | | 2,729 | | | | 2,248 | | | | 4,574 | | | | 10,575 | | Loss on debt extinguishment | | | — | | | | — | | | | — | | | | 2,144 | | | | 2,144 | | Multi-employer pension plan withdrawal charge | | | — | | | | — | | | | 6,000 | | | | 1,000 | | | | 7,000 | | | | | | | | | | | | | | | | | | | | | | | Adjusted EBITDA | | | 117,473 | | | | 190,668 | | | | 19,171 | | | | 1,941 | | | | 329,253 | | Add (subtract): | | | | | | | | | | | | | | | | | | | | | Provision for income taxes | | | (132 | ) | | | (150 | ) | | | (148 | ) | | | (177 | ) | | | (607 | ) | Interest expense, net | | | (24,556 | ) | | | (24,343 | ) | | | (24,385 | ) | | | (22,143 | ) | | | (95,427 | ) | Unrealized (non-cash) (losses) gains on changes in fair value of derivatives | | | (3,614 | ) | | | (2,646 | ) | | | (73 | ) | | | 2,015 | | | | (4,318 | ) | Integration related costs | | | (1,024 | ) | | | (2,729 | ) | | | (2,248 | ) | | | (4,574 | ) | | | (10,575 | ) | Multi-employer pension plan withdrawal charge | | | — | | | | — | | | | (6,000 | ) | | | (1,000 | ) | | | (7,000 | ) | Compensation cost recognized under Restricted Unit Plans | | | 1,240 | | | | 1,173 | | | | 840 | | | | 635 | | | | 3,888 | | Gain on disposal of property, plant and equipment, net | | | (2,267 | ) | | | (323 | ) | | | (301 | ) | | | (652 | ) | | | (3,543 | ) | Changes in working capital and other assets and liabilities | | | (25,583 | ) | | | (89,224 | ) | | | 79,649 | | | | 37,793 | | | | 2,635 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Net cash provided by operating activities | | $ | 61,537 | | | $ | 72,426 | | | $ | 66,505 | | | $ | 13,838 | | | $ | 214,306 | | | | | | | | | | | | | | | | | | | | | | |
| | First Quarter | | | Second Quarter | | | Third Quarter | | | Fourth Quarter | | | Total Year | | Fiscal 2016 | | | | | | | | | | | | | | | | | | | | | Net income (loss) | | $ | 12,266 | | | $ | 92,011 | | | $ | (29,598 | ) | | $ | (60,239 | ) | | $ | 14,440 | | Add: | | | | | | | | | | | | | | | | | | | | | Provision for income taxes | | | 185 | | | | 58 | | | | 180 | | | | 165 | | | | 588 | | Interest expense, net | | | 18,893 | | | | 18,852 | | | | 18,638 | | | | 18,703 | | | | 75,086 | | Depreciation and amortization | | | 31,638 | | | | 33,150 | | | | 32,288 | | | | 32,540 | | | | 129,616 | | EBITDA | | | 62,982 | | | | 144,071 | | | | 21,508 | | | | (8,831 | ) | | | 219,730 | | Unrealized (non-cash) (gains) losses on changes in fair value of derivatives | | | 1,210 | | | | 739 | | | | 56 | | | | (815 | ) | | | 1,190 | | Gain on sale of business | | | — | | | | — | | | | (9,769 | ) | | | — | | | | (9,769 | ) | Multi-employer pension plan withdrawal charge | | | — | | | | — | | | | 6,600 | | | | — | | | | 6,600 | | Product liability settlement | | | 3,000 | | | | — | | | | — | | | | — | | | | 3,000 | | Pension settlement charge | | | — | | | | — | | | | — | | | | 2,000 | | | | 2,000 | | Loss on debt extinguishment | | | — | | | | 292 | | | | — | | | | — | | | | 292 | | Adjusted EBITDA | | $ | 67,192 | | | $ | 145,102 | | | $ | 18,395 | | | $ | (7,646 | ) | | $ | 223,043 | | | | | | | | | | | | | | | | | | | | | | | Fiscal 2015 | | | | | | | | | | | | | | | | | | | | | Net income (loss) | | $ | 55,807 | | | $ | 136,634 | | | $ | (40,952 | ) | | $ | (67,137 | ) | | $ | 84,352 | | Add: | | | | | | | | | | | | | | | | | | | | | Provision for income taxes | | | 162 | | | | 174 | | | | 185 | | | | 179 | | | | 700 | | Interest expense, net | | | 19,999 | | | | 19,711 | | | | 18,933 | | | | 18,991 | | | | 77,634 | | Depreciation and amortization | | | 32,629 | | | | 33,229 | | | | 32,730 | | | | 34,706 | | | | 133,294 | | EBITDA | | | 108,597 | | | | 189,748 | | | | 10,896 | | | | (13,261 | ) | | | 295,980 | | Unrealized (non-cash) losses (gains) on changes in fair value of derivatives | | | (9,505 | ) | | | 7,433 | | | | 37 | | | | 180 | | | | (1,855 | ) | Loss on debt extinguishment | | | — | | | | 15,072 | | | | — | | | | — | | | | 15,072 | | Integration-related costs | | | 1,913 | | | | 2,063 | | | | 1,134 | | | | 6,432 | | | | 11,542 | | Multi-employer pension plan withdrawal charge | | | — | | | | — | | | | — | | | | 11,300 | | | | 11,300 | | Pension settlement charge | | | — | | | | — | | | | — | | | | 2,000 | | | | 2,000 | | Adjusted EBITDA | | $ | 101,005 | | | $ | 214,316 | | | $ | 12,067 | | | $ | 6,651 | | | $ | 334,039 | |
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ITEM 9. | CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTSACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE |
None. ITEM 9A. | CONTROLS AND PROCEDURES |
Evaluation of 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 and submissions 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 27, 2014.24, 2016. Based on this evaluation, the Partnership’s principal executive officer and principal financial officer concluded that the Partnership’sas of September 24, 2016, such disclosure controls and procedures were effective atto provide the reasonable assurance level as of September 27, 2014.described above. 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 27, 2014,24, 2016, 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’sPartnership's internal control over financial reporting is designed to provide reasonable assurance as to the reliability of the Partnership’sPartnership'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 27, 2014.24, 2016. In making this assessment, the Partnership used the criteria established by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) in “Internal Control-Integrated Framework (1992)(2013).” These criteria are in the areas of control environment, risk assessment, control activities, information and communication, and monitoring. The Partnership’sPartnership'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 27, 2014,24, 2016, the Partnership’s internal control over financial reporting was effective. Our independent registered public accounting firm, PricewaterhouseCoopers LLP, issued an attestation report dated November 26, 201423, 2016 on the effectiveness of our internal control over financial reporting, which is included herein. ITEM 9B. | OTHER INFORMATION |
None. PART III
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PART III ITEM 10. | DIRECTORS, EXECUTIVE OFFICERS AND PARTNERSHIP GOVERNANCE |
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. Under the current Partnership Agreement, members of our Board of Supervisors are elected by the Unitholders for three-year terms. All of our current Supervisors, namely Messrs. Harold R. Logan Jr., Lawrence C. Caldwell, Matthew J. Chanin, John D. Collins, Dudley C. Mecum,Michael A. Stivala, John Hoyt Stookey and Ms. Jane Swift, were elected to their current three-year terms at the Tri-Annual Meeting of our Unitholders convenedheld on May 1, 2012 and then reconvened on May 14, 2012.13, 2015. At its regular meeting on November 13, 2012,15, 2016, our Board of Supervisors, pursuant to authority granted to the Board under the Partnership Agreement, and acting on the recommendation of the Board’s Nominating/Governance Committee, increased the size of the Board from six (6)eight (8) Supervisors to eight (8) Supervisors.nine (9) Supervisors, effective January 1, 2017. At the same meeting and again pursuant to authority granted to the Board under the Partnership Agreement and in accordance with the recommendation of its Nominating/Governance Committee, the Board elected Messrs. Lawrence C. CaldwellTerence J. Connors and Matthew J. ChaninWilliam M. Landuyt to fill the two vacancies on the Board created byfollowing the increase in size of the Board, effective immediately.January 1, 2017. Messrs. CaldwellConnors and ChaninLanduyt were each elected for a term due to expire at the next Tri-Annual Meeting of our Unitholders, currently scheduledplanned for Spring 2015.2018. At this time neither Mr. Connors nor Mr. Landuyt has been named to any Board committees. AtThree Supervisors, who are not officers or employees of the Partnership or its meeting on November 12, 2014, and upon the recommendation of its Nominating/Governance Committee, our Board of Supervisors elected Michael A. Stivala, our current President and Chief Executive Officer, to fill the vacancysubsidiaries, currently serve on the Board created by the retirement from the Board of Michael J. Dunn, Jr. effective on September 27, 2014, concurrently with Mr. Dunn’s retirement as our Chief Executive Officer. Mr. Stivala was elected for a term due to expire at the next Tri-Annual Meeting of our Unitholders, currently scheduled for Spring 2015.
The Audit Committee of our Board of Supervisors has thewith 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 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 (i) integrity of the Partnership’s financial statements and internal control over financial reporting; (ii) the Partnership’s compliance with applicable laws, regulations and its code of conduct; (iii) independence and qualifications of the independent registered public accounting firm; (iv) performance of the internal audit function and the independent registered public accounting firm; and (v) accounting complaints.
Until July 22, 2014,The Board of Supervisors has determined that all three current members of the Audit Committee, consisted of all seven of our non-employee Supervisors (namely, Messrs. Logan, Stookey, Mecum,John D. Collins, Lawrence C. Caldwell Chanin and Ms. Swift), all of whom had been determined by our Board of Supervisors to beJane Swift, are independent and (with the exception of Ms. Swift) 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. At its meeting on July 22, 2014, the Board reduced the size of the Audit Committee to four—Messrs. Caldwell, Collins, Mecum and Ms. Swift—and reaffirmed the above determinations with respect to those four members. 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 regular meetings of the Board of Supervisors. 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 42
Board of Supervisors and Executive Officers of the Partnership The following table sets forth certain information with respect to the members of the Board of Supervisors and our executive officers as of November 26, 2014.23, 2016 and with respect to Terence J. Connors and William M. Landuyt, who have been elected to become members of the Board of Supervisors as of January 1, 2017. Officers are appointed by the Board of Supervisors forone-year one‑year terms and Supervisors (other than those elected by the Board to fill vacancies) are elected by the Unitholders forthree-year three‑year terms. | | | | | | | Name | | Age | | | Position With the Partnership | Michael A. Stivala | | 47 | 45 | | | President and Chief Executive Officer; Member of the Board of Supervisors | Mark Wienberg
| | | 52 | | | Chief Operating Officer | Michael A. Kuglin | | 46 | 44 | | | Chief Financial Officer & Chief Accounting Officer | Paul Abel | | 63 | 61 | | | Senior Vice President, General Counsel and Secretary | Steven C. Boyd | | 52 | 50 | | | Senior Vice President—FieldPresident – Operations | Douglas T. Brinkworth | | 55 | 53 | | | Senior Vice President—President – Product Supply, Purchasing & Logistics | Michael M. Keating
| | | 61 | | | Senior Vice President | Neil E. Scanlon | | 51 | 49 | | | Senior Vice President—President – Information Services | A. Davin D’Ambrosio | | 52 | 50 | | | Vice President and Treasurer | Keith P. Onderdonk | | 52 | | Vice President – Operational Support | Sandra N. Zwickel | | 50 | 48 | | | Vice President—President – Human Resources | Daniel S. Bloomstein | | 43 | 41 | | | Controller | Harold R. Logan, Jr. | | 72 | 70 | | | Member of the Board of Supervisors (Chairman) | John Hoyt Stookey | | 86 | 84 | Member of the Board of Supervisors | John D. Collins | | 78 | | Member of the Board of Supervisors (Chairman of the Audit Committee) | Jane Swift | | 51 | | Member of the Board of Supervisors | Lawrence C. Caldwell | | 70 | | Member of the Board of Supervisors | Matthew J. Chanin | | 62 | | Member of the Board of Supervisors (Chairman of the Compensation Committee) | Dudley C. MecumTerence J. Connors
| | 61 | 79 | | | Member of the Board of Supervisors | John D. CollinsWilliam M. Landuyt
| | 61 | 76 | | | Member of the Board of Supervisors (Chairman of the Audit Committee) | Jane Swift
| | | 49 | | | Member of the Board of Supervisors | Lawrence C. Caldwell
| | | 68 | | | Member of the Board of Supervisors | Matthew J. Chanin
| | | 60 | | | Member of the Board of Supervisors |
Mr. Stivala has served as our President since April 2014 and as our Chief Executive Officer since September 2014. Mr. Stivala has served as a Supervisor since November 2014. From November 2009 until March 2014 he was our Chief Financial Officer, and, before that, 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’s qualifications to sit on our Board include his thirteenfifteen years of experience in the propane industry, including as our current President and Chief Executive Officer and, before that, as our Chief Financial Officer for almost 7seven years, which day to day leadership roles have provided him with intimate knowledge of our operations. Mr. Wienberg has served as our Chief Operating Officer since April 2014 and before that was 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.
Mr. Kuglin has served as our Chief Financial Officer & Chief Accounting Officer since September 2014 and was our Vice President—President – Finance and Chief Accounting Officer from April 2014 through September 2014. Prior to that he served as our Vice President and Chief Accounting Officer since November 2011, our Controller and Chief Accounting Officer since November 2009 and our 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 as Manager in the Assurance practice. Mr. Kuglin is a Certified Public Accountant and a member of the American Institute of Certified Public Accountants. Mr. Abel has served as our General Counsel and Secretary since June 2006, was additionally made a Vice President in October 2007 and a Senior Vice President in April 2014. Prior to joining the Partnership, Mr. Abel served as senior in-house legal counsel (including as a General Counsel) for several technology companies. Mr. Boyd has served as our Senior Vice President—President – Operations since September 2015 and before that was our Senior Vice President – Field Operations since April 2014; previously2014. Previously he was our Vice President—President – Field Operations (formerly Vice President—President – Operations) since October 2008. Prior to that he was2008, our Southeast and Western Area Vice President since March 2007, Managing Director—Director – Area Operations since November 2003 and Regional Manager—Manager – Northern California since May 1997. Mr. Boyd held various managerial positions with predecessors of the Partnership from 1986 through 1996. Mr. Brinkworth has served as our Senior Vice President—President – Product Supply, Purchasing & Logistics since April 2014 and was previously our Vice President – Product Supply (formerly Vice President—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. Keating has served as our Senior Vice President since October 2014 and before that was 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.
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Mr. Scanlon became our Senior Vice President—President – Information Services in April 2014, after serving as our Vice President—President – Information Services since November 2008. Prior to that he served as our Assistant Vice President—President – Information Services since November 2007, Managing Director—Director – Information Services from November 2002 to November 2007 and Director—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—President – Corporate Systems and earlier held several positions with Andersen Consulting, an international systems consulting firm, most recently as Manager. 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. Onderdonk has served as our Vice President – Operational Support since November 2015 and before that was our Assistant Vice President – Financial Planning and Analysis since November 2013. Prior to that, he served as our Managing Director, Financial Planning and Analysis from November 2010 to November 2013. Mr. Onderdonk joined the Partnership in September 2001 after fourteen years in the consumer products industry. Ms. Zwickel has served as our Vice President—President – Human Resources since November 2013. Prior to that, she was our Assistant Vice President—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. Bloomstein joined the Partnership as its Controller in April 2014. For the ten years prior to joining the Partnership, he held several executive financial and accounting positions with The Access Group, a network of professional services companies, and with Dow Jones & Company, Inc., a global news and financial information company. Mr. Bloomstein started his career with the international accounting firm PricewaterhouseCoopers LLP, working his way to the level of Manager in the Assurance/Business Advisory Services practice. Mr. Bloomstein is a Certified Public Accountant and a member of the American Institute of Certified Public Accountants. 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—President – 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 InfraREIT, Inc., Cimarex Energy Co., Graphic Packaging Holding Company and Hart Energy Publishing LLP. Over the past forty 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 nineten public companies and has served on audit, compensation and governance committees. Mr. Stookey has served as a Supervisor since March 1996. He was Chairman of the Board of Supervisors from March 1996 through January 2007. From 1986 until September 1993, he was the Chairman, President and Chief Executive Officer of Quantum.Quantum Chemical Corporation, a predecessor of the Partnership. He served as non-executive Chairman and a Director of Quantum from its acquisition by Hanson plc, a global diversified industrial conglomerate, in September 1993 until October 1995, at which time he retired. Since then, Mr. Stookey has served as a trustee of a number of non-profit organizations, including founding and serving as non-executive Chairman of Per Scholas Inc. (a non-profit organization dedicated to training inner city individuals to become computer and software technicians), The Berkshire Choral Festival and Landmark Volunteers and also currently serves on the Board of Directors of The Clark Foundation and The Robert Sterling Clark Foundation and as a Life Trustee of the Boston Symphony Orchestra. Mr. Stookey’s qualifications to sit on our Board include his extensive experience as Chief Executive Officer of four 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 was a Managing Director of Capricorn Holdings, LLC (a sponsor of and investor in leveraged buyouts) from 1997 to 2011 and a partner of G.L. Ohrstrom & Co. (a sponsor of and investor in leveraged buyouts) from 1989 to 1996.
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 fifteen years of service overseeing or managing various companies. Mr. Mecum has over twenty years of service as a director of various publicly-owned companies, including, until 2007, Citigroup, Inc.44
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. Until recently, Mr. Collins was a Director of Montpelier Re, Columbia Atlantic Funds and Mrs. Fields Original Cookies, Inc. Mr. Collins’ qualifications to sit on our Board, and serve as Chairman of its Audit Committee, include his 40forty 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—President – 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., Animated Speech Company, and The Young Writers Project and currently serves on the boards of Sally Ride Science Inc. andMs. Swift currently serves on several not-for-profit boards, including the National Alliance for Public Charter Schools.Schools and Vermont PBS; and on the advisory boards of School of Leadership Afghanistan and Vote, Run, Lead. Ms. Swift is also a Trustee for Champlain College. Prior to joining Arcadia, Ms. Swift served for fifteen 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 fifteen years in state government. Mr. Caldwell has served as a Supervisor since November 2012. He was a Co-Founder of New Canaan Investments, Inc. (“NCI”), a private equity investment firm, where he was one of three senior officers of the firm from 1988 to 2005. NCI was an active “fix and build” investor in packaging, chemicals, and automotive components companies. Mr. Caldwell held a number of board directorships and senior management positions in these companies until he retired in 2005. The largest of these companies was Kerr Group, Inc., a plastic closure and bottle company where Mr. Caldwell served as Director for eight years and Chief Financial Officer for six years. From 1985 to 1988, Mr. Caldwell was head of acquisitions for Moore McCormack Resources, Inc., an oil and gas exploration, shipping, and construction materials company. Mr. Caldwell is currently a director of Magnuson Products, LLC, a private company which manufactures specialty engine components for automotive original equipment manufacturers and aftermarket. Mr. Caldwell also currently serves on the Board of Trustees and as Chairman of the Investment and Finance Committee of Historic Deerfield, and on the Board of Directors and as Chairman of both the Finance and Strategic Planning CommitteesCommittee of the Leventhal Map Center; both of which non-profit institutions focus on enriching educational programs for K-12 children locally and nationwide. Mr. Caldwell’sCaldwell's qualifications to sit on our Board include over forty years of successful investing in and managing of a broad range of public and private businesses in a number of different industries. This experience has encompassed both turnaround situations, and the building of companies through internal growth and acquisitions. 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 threetwo private companies that are in Prudential Capital Partners funds’ portfolios, and provides consulting services to Prudential and one other client. Mr. Chanin’s qualifications to sit on our Board include 35 years of investment experience with a focus on highly structured private placements in companies in a broad range of industries, with a particular focus on energy companies. He has previously served on the audit committee of a public company board and is currently a member of the auditcompensation committee for a private company board. Mr. Chanin has earned an MBA and is a Chartered Financial Analyst. Mr. Connors will commence service as a Supervisor on January 1, 2017. Mr. Connors retired in September 2015 from KPMG LLP after nearly forty years in public accounting. Prior to joining KPMG in 2002 he was a partner with another large international accounting firm. During his career, he served as a senior audit and global lead partner for numerous public companies, including Fortune 500 companies. At KPMG he was a professional practice partner, SEC Reviewing Partner and was elected to serve as a member of KPMG’s board of directors (2011-2015), where he chaired the Audit, Finance & Operations Committee. Mr. Connors currently serves as a director and audit committee chairman of the largest privately-held automotive parts remanufacturer in the world. Mr. Connors’ qualifications to sit on our Board include his extensive experience as a lead audit partner for numerous public companies across a variety of industries, which enables him to provide helpful insights to the Board in connection with its oversight of financial, accounting and internal control matters. 45
Mr. Landuyt will commence service as a Supervisor on January 1, 2017. Since 2003, Mr. Landuyt has served as a Managing Director at Charterhouse Equity Partners, LLC, a private equity firm with a focus on build-ups, management buyouts, and growth capital investments primarily in the business services and healthcare services sectors, and has served on the Boards of Directors of a number of portfolio companies of that firm. From 1996 to 2003, Mr. Landuyt served as Chairman of the Board, President and Chief Executive Officer of Millennium Chemicals, Inc. (“Millennium”), and from 1983 to 1996 he served in several senior executive positions with Hanson Industries (“Hanson,” the US subsidiary of Hanson plc), including Vice President and Chief Financial Officer and ultimately Director, President and Chief Executive Officer. Hanson and Millennium were both previous owners of the Partnership or its predecessor through 1996 and 1999, respectively. He joined Hanson after spending six years as a Certified Public Accountant and auditor at Price Waterhouse & Co., where he rose to the position of Senior Manager. Mr. Landuyt has previously served on the Boards of Directors (including their Audit and Compensation Committees) of public companies, including Bethlehem Steel Corp., MxEnergy Holdings, Inc., a leading retail marketer of natural gas and electricity contracts, and Top Image Systems, Inc. Mr. Landuyt is also the Co-Founder and Executive Director of Celtic Charms, Inc., a non-profit therapeutic horsemanship center serving people with physical and cognitive disabilities and disorders. Mr. Landuyt’s qualifications to sit on our Board include forty years of financial and executive management experience for both public and private companies, including extensive experience with mergers and acquisitions and corporate governance. Additionally, his specific responsibility for supervision of the Partnership’s predecessors, as well as his subsequent board-level involvement in the distribution, petrochemical and retail energy sectors through Charterhouse’s investments in those sectors, gives Mr. Landuyt extensive expertise in areas directly relevant to the business of the Partnership. 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 year 2014.2016. 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 Principles in accordance with the NYSE corporate governance listing standards in effect as of the date of this Annual Report. In addition, we have adopted certain Corporate Governance Policies, including an Equity Holding Policy for Supervisors and Executives and an Incentive Compensation Recoupment Policy. A copy of our Corporate Governance Guidelines and Principles, as well as a copy of the Corporate Governance Policies, 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 Until July 22, 2014, all sevenThree Supervisors, who are not officers or employees of the Partnership or its subsidiaries, (namely, Messrs. Logan, Stookey, Mecum, Collins, Caldwell, Chanin and Ms. Swift) servedcurrently serve on the Compensation Committee. The Board of Supervisors hadhas determined that all seventhree current members of the Compensation Committee, Matthew J. Chanin, Harold R. Logan, Jr. and John Hoyt Stookey, are independent. At its meeting on July 22, 2014, the Board reduced the size of the Compensation Committee to three – Messrs. Chanin, Logan and Stookey – and reaffirmed the above determination with respect to those three members.
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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 2014,2016, the Compensation Committee independently retained Willis Towers Watson & Co. (“Towers Watson”), a human resources consulting firm, formerly known as Towers Watson & Co., to assist the Compensation Committee in developing competitive compensation packages for thosethe Partnership’s executive officers identified by the Compensation Committee as our senior core executive officers pursuant to a succession plan approved by the Board of Supervisors.officers. See Item 11 below. Nominating/Governance Committee Charter The Nominating/Governance Committee participates in Board succession planning and development and identifies individuals qualified to become Board members, recommends to the Board the persons to be nominated for election as Supervisors at any Tri-Annual Meeting of the Unitholders and the persons (if any) to be elected by the Board to fill any vacancies on the Board, develops and recommends to the Board changes to the Partnership’s Corporate Governance Guidelines and Principles when appropriate, and oversees the annual evaluation of the Board. The Committee’s current members are Harold R. Logan, Jr. (its Chairman), Lawrence C. Caldwell, Matthew J. Chanin, John D. Collins, John Hoyt Stookey and Jane Swift, all of whom are independent in accordance with our Corporate Governance Guidelines and Principles and the rules of the NYSE. We have adopted a written Nominating/Governance Committee Charter. A copy of our Nominating/Governance 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. 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. Our Chief Executive Officer submits his Annual CEO Certification to the NYSE each December. In December 2013,2015, our then Chief Executive Officer, Michael J. Dunn, Jr.,A. Stivala, submitted his Annual CEO Certification to the NYSE without qualification. 47
ITEM 11. | EXECUTIVEEXECUTIVE COMPENSATION |
Compensation Discussion and Analysis This Compensation Discussion and Analysis (“CD&A”) explains our executive compensation philosophy, policies and practices with respect to the followingthose executive officers of the Partnership toidentified below whom we collectively refer to as our “named executive officers”: Mr. Dunn, Name | | Position | Michael A. Stivala | | President and Chief Executive Officer | Michael A. Kuglin | | Chief Financial and Chief Accounting Officer | Steven C. Boyd | | Senior Vice President – Field Operations | Douglas T. Brinkworth | | Senior Vice President Product Supply, Purchasing and Logistics | Paul Abel | | Senior Vice President, General Counsel and Secretary | Mark Wienberg | | Former Chief Development Officer* |
* | Effective May 26, 2016, Mr. Wienberg is no longer employed by the Partnership. For details regarding Mr. Wienberg’s severance arrangement with the Partnership, please refer to the section below titled “Severance Benefits.” |
Key Topics Covered in our former Chief Executive Officer (who heldCD&A The following table summarizes the positionmain areas of President and Chief Executive Officer until March 31, 2014, andfocus in the positionCD&A: Compensation Governance | Participants in the Compensation Process | The Annual Compensation Decision Making Process | Risk Mitigation Policies | Executive Compensation Philosophy | Overview | Pay Mix | Components of Compensation | Base Salary | Annual Cash Bonus | Long-Term Incentive Plan | Restricted Unit Plan | Benefits and Perquisites |
Compensation Governance Participants in the Compensation Process Role of Chief Executive Officer through September 27, 2014); Mr. Stivala, our current President and Chief Executive Officer (who held the position of Chief Financial Officer until March 31, 2014, and the position of President from April 1, 2014 through September 27, 2014); Mr. Kuglin, our current Chief Financial Officer and Chief Accounting Officer (who held the position of Vice President and Chief Accounting Officer until March 31, 2014, and the position of Vice President—Finance and Chief Accounting Officer, a position that required him to act in a manner identical to that of a Chief Financial Officer, from April 1, 2014 through September 27, 2014); and our three other most highly compensated executive officers: Mr. Wienberg, our Chief Operating Officer; Mr. Boyd, our Senior Vice President—Field Operations; and Mr. Brinkworth, our Senior Vice President—Product Supply, Purchasing & Logistics.Compensation Committee In accordance with a management succession plan developed by theThe Compensation Committee of the Partnership’sour Board of Supervisors which we hereafter refer to as the “Committee,” in close collaboration with Mr. Dunn, Mr. Dunn retired at the conclusion of fiscal 2014.
Executive Compensation Philosophy and Components
The objectives of our executive compensation program are as follows:
The attraction and retention of talented executives who have the skills and experience required to achieve our goals; and
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:
Base salary;
Cash incentives paid under a performance-based annual bonus plan;
Long-Term Incentive Plan awards; and
Awards of restricted units under the Restricted Unit 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 our executive officers with an annual incentive target that encourages them to achieve or exceed targeted financial results and operating performance for the fiscal year;
Providing a long-term incentive plan that encourages our executive officers to implement activities and practices conducive to sustainable, profitable growth; and
Providing our executive officers with restricted units in order to encourage the retention of the participating executive officers, while simultaneously encouraging behaviors conducive to the long-term appreciation of our Common Units.
Establishing Executive Compensation
The Committee(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. The Committee establishes and enforces our general compensation philosophy in consultation with our President and Chief Executive Officer.
Among other duties, the Committee has overall responsibility for: Reviewing and approving the compensation of our President and Chief Executive Officer, our Chief Financial Officer, and our other executive officers; Reporting to the Board of Supervisors any and all decisions regarding compensation changes for our President and Chief Executive Officer and our other executive officers; Evaluating and approving our annual cash bonus plan, Long-Term Incentive Plan, and grants under our Restricted Unit Plan, as well as all other executive compensation policies and programs; 48
Administering and interpreting the compensation plans that constitute each component of our executive officers’ compensation packages; and Engaging consultants, when appropriate, to provide independent, third-party advice on executive officer-related compensation. Role of the 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, grants of restricted units under the Partnership’s Restricted Unit Plan and other adjustments to the compensation packages of the executive officers, other than himself, to the Committee based on market conditions, the Partnership’s performance, and individual performance. When recommending individual pay adjustments for the executive officers, Mr. Stivala, our President and Chief Executive Officer, presents the Committee with information comparing each executive officer’s current compensation to the mean compensation figures for comparable positions included in benchmarking data utilized by the Committee. Role of Outside Consultants Prior to each Committee meeting at which executive compensation packages are reviewed, members of the Committee are provided with benchmarking data from the Mercer Human Resource Consulting, Inc. (“Mercer”) database for comparison. The Committee’s sole use of the Mercer database is to compare and contrast our executives’ current base salaries and total direct compensation to the data provided in the Mercer benchmarking database. The information provided by Mercer was derived from a proprietary database maintained by Mercer and, as such, there was no formal consultancy role played by them. Therefore, prior to the Committee’s meetings, neither the Committee members nor our President and Chief Executive Officer met with representatives from Mercer. In addition to using the benchmark data from the Mercer benchmarking database, the Committee has utilized, since fiscal 2013, the services of Willis Towers Watson (“Towers Watson”), a human resources consulting firm, formerly known as Towers Watson & Co. During fiscal 2013, Towers Watson reviewed our Long-Term Incentive and Restricted Unit Plans, which resulted in revisions to our cash bonus plan and Long-term Incentive Plan, and an alteration of the vesting schedule of our Restricted Unit Plan. In fiscal 2014, Towers Watson provided the Committee with assistance in developing competitive compensation packages for those executive officers identified by the Committee as our senior level executive officers (including all of our present named executive officers). The recommendations that Towers Watson put forth to the Committee in 2014 were considered in the development of the respective fiscal 2015 compensation packages for each of our named executive officers. Similarly, in developing the fiscal 2016 compensation packages for each of our named executive officers, the Committee again retained the services of Towers Watson to benchmark the base salaries and total direct compensation of our executive officers compared to comparable positions, using market data for similarly-sized companies which was developed by Towers Watson from multiple survey sources across several industries, inclusive of other energy companies in the United States. Our Unitholders: Say-on-Pay At their 2015 Tri-Annual Meeting, our Unitholders overwhelmingly approved an advisory resolution approving executive compensation (commonly referred to as “Say-on-Pay”). As a result, the Committee has determined that no major revisions of its executive compensation practices are required. However, the Committee periodically evaluates its compensation practices for possible improvement. The following represents the 2015 Say-on-Pay voting results: For | | | Against | | | Abstain | | | Broker Non-Votes | | | 28,802,659 | | | | 1,712,622 | | | | 613,603 | | | | 22,303,948 | |
The Annual Compensation Decision Making Process Fiscal 2016 Committee Meetings The Committee holds three regularly-scheduled meetings during the fiscal year: one in November, 13, 2013 Compensation Committee Meetingone in January and one in July, and may meet at other times during the year as warranted. It finalized the fiscal year 2016 compensation packages for each of our named executive officers at its November 10, 2015 meeting. As in past fiscal years our Senior Vice President—Administration (now Senior Vice President) preparedand as referred to above, the Committee was provided with a comprehensive analysis of each executive officer’ssenior executive’s past and current compensation - including benchmarking data for comparison - to assist the Committee in the assessmentenable it to assess and determination of executivedetermine each executive’s compensation packagespackage for fiscal 2014.2016. The Committee considered a number of factors in establishing the fiscal 20142016 executive compensation packages, including, but not limited to, experience, scope of responsibility and individual performance. 49
The benchmarking data provided to the Committee for fiscal 2016 was derived from the Mercer database containing information obtained from surveys of over 3,000 organizations and approximately 1,400 positions which may or may not include similarly-sized national propane marketers for the reasons stated below. The use of the Mercer database provides a broad base of compensation benchmarking information for companies of similar size to the Partnership. Prior to making its decisions regarding each named executive officer’s fiscal 2016 compensation package, the Committee reviewed the total cash compensation opportunity that was provided to each named executive officer during the previously completed fiscal year. “Total cash compensation opportunity” consists of base salary, an annual cash bonus, and cash settled long-term incentives. The Committee then compared each named executive officer’s total cash compensation opportunity to the total mean cash compensation opportunity for the parallel position in the Mercer database. In addition, the Committee retained the services of Towers Watson to benchmark the base salaries and total direct compensation of our executive officers compared to comparable positions, using market data for similarly-sized companies which was developed by Towers Watson from multiple survey sources across several industries, inclusive of other energy companies in the United States. The Committee then based its final decisions on both the recommendations made by Towers Watson and on the information contained in the Mercer benchmarking database. Our Approach to Setting Compensation Packages In reviewing and determining the compensation packages of our named executive officers, the Committee considers a number of factors related to each executive, including, but not limited to, years of experience in current position, scope and level of responsibility, influence over the affairs of the Partnership and individual performance. The relative importance assigned to each of these factors by the Committee may differ from executive to executive and from year to year. In addition, as partAs a result, different weights may be given to different components of the Committee’s annual reviewcompensation among each of eachour named executive officer’s total compensation package,officers. As previously stated, the Committee wasis provided with benchmarking data for comparison. This benchmarking data is just one of a number of factors that was considered by the Committee, but wasis not necessarily the most persuasive factor. The benchmarking data provided to the Committee for fiscal 2014 was derived from the Mercer Human Resource Consulting, Inc. (“Mercer”) Benchmark Database containing information obtained from surveys of over 3,035 organizations and approximately 1,224 positions which may or may not include similarly-sized national propane marketers. The use of the Mercer database provides a broad base of compensation benchmarking information for companies of a size similar to the Partnership. In making their decisions regarding executive compensation packages for fiscal 2014, for executive officers currently below the level of senior vice president, the members of the Committee reviewed thecompares total cash compensation opportunities, that were provided to each member of this subset of our executive officers (none of whom are our named executive officers) during the previous completed fiscal year. “Total cash compensation opportunity” consists ofcomprising base salary anand annual cash bonus, andbonuses, as well as total direct compensation (which includes opportunities under our Long-Term Incentive Plan awards. The Committee then compared these officers’ total cash compensation opportunitiesand Restricted Unit Plan awards) to the total mean cash compensation opportunitiesopportunity and total direct compensation opportunity for the parallel positionsposition in the Mercer database. By focusingbenchmark information reviewed.
Compensation Peer Group The Committee bases its benchmarking on total cash compensation opportunity as a whole, insteadbroad base of on single componentscompanies of compensation such as base salary, when it met on November 13, 2013,similar size to the Committee created fiscal 2014 compensation packages for this subset of our executive officers that emphasized the performance-based components of compensation. As in prior years, the Committee didPartnership, and does not base its benchmarkingrely solely on a peer group of other propane marketers. The Committee adoptedtakes this approach because it believes that the proximity of our headquarters to New York City and the need to realistically compete for skilled executives in an environment shared by numerous other enterprises that seekseeking similarly skilled employees requires a broader review of the market. The Committee chooses not to base its benchmarking on the compensation practices of otherFurthermore, similarly-sized propane marketers due to the fact that the other, similarly-sized propane marketers(of which there are only two) compete for executives in vastly different economic environments.
In connection with succession planning, the Committee unanimously decided to engage the services of Towers Watson & Co. (“Towers Watson”), a human resources consulting firm, for assistance in developing competitive compensation packages for those executive officers identified by the Committee as our senior level executive officers (i.e., those executives who are currently at or above the level of senior vice president). The Committee agreed that it would defer making promotion-related decisions (with the notable exception of the promotion of Mr. Stivala discussed below) and compensation-related decisions relative to our senior core executive officers until its January 22, 2014 meeting, by which time it was contemplated that Towers Watson would have completed a study of the Partnership, the executive team, and our past compensation practices.
In response to Mr. Dunn’s having informed the committee that he intended to retire at the end of fiscal 2014, the Committee promoted Mr. Stivala to the position of President (effective April 1, 2014) at its November 13, 2013 meeting. For Mr. Stivala and for those whom the Committee identified as our senior level executive officers (currently our Chief Operating Officer, our Chief Financial Officer and Chief Accounting Officer, and our Senior Vice Presidents), the Committee decided to postpone establishing fiscal 2014 compensation-related adjustments until after the Committee was presented with recommendations from Towers Watson.
The January 22, 2014 Compensation Committee Meeting
After completing a study of the Partnership and the responsibilities that had already been and were to be assumed by our senior level executive officers, a principal of Towers Watson provided the Committee with a presentation that included compensation recommendations for this group of executives. In accordance with the recommendations of Towers Watson, the Committee established fiscal year 2014 compensation packages for our President (who is currently our President and Chief Executive Officer), our Chief Operating Officer, our Senior Vice Presidents, and our Vice President—Finance and Chief Accounting Officer (who is currently our Chief Financial Officer and Chief Accounting Officer). The compensation packages established at this meeting became effective on April 1, 2014, the effective date on which Mr. Stivala was promoted to the position of President, Mr. Kuglin was promoted to the position of Vice President—Finance and Chief Accounting Officer, Mr. Wienberg was promoted to Chief Operating Officer, Mr. Boyd was promoted to the position of Senior Vice President—Field Operations, and Mr. Brinkworth was promoted to the position of Senior Vice President—Product Supply, Purchasing & Logistics.
The July 22, 2014 Compensation Committee Meeting
Continuing its preparation for Mr. Dunn’s retirement at the conclusion of fiscal 2014, the Committee approved Mr. Stivala’s assumption of the role and title of Chief Executive Officer in addition to his role as President. Because of the April 1, 2014 adjustments to Mr. Stivala’s overall compensation, the Committee chose not to adjust Mr. Stivala’s compensation at this time. This promotion became effective on September 28, 2014.
In addition, the Committee approved the promotion of Mr. Kuglin to Chief Financial Officer and Chief Accounting Officer. This promotion became effective on September 28, 2014. In establishing Mr. Kuglin’s compensation for this position, the Committee relied on the same Towers Watson study discussed above.
***
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—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.
Among other duties, the Committee has overall responsibility for:
Reviewing and approving the compensation of our President and Chief Executive Officer, our Chief Operating Officer, our Chief Financial Officer, and our other executive officers;
Reporting to the Board of Supervisors any and all decisions regarding compensation changes for our President and Chief Executive Officer and our other executive officers;
Evaluating and approving our annual cash bonus plan, long-term incentive plan, and grants under our Restricted Unit Plans, as well as all other executive compensation policies and programs;
Administering and interpreting the compensation plans that constitute each component of our executive officers’ compensation packages; and
Engaging consultants, when appropriate, to provide independent, third-party advice on executive officer-related compensation.
Our sole use of the Mercer database was to provide the Committee with benchmarking data. Therefore, prior to the November 13, 2013 Committee meeting, neither our President and Chief Executive Officer nor our Senior Vice President— Administration met with representatives from Mercer. The information provided by Mercer was derived from a proprietary database maintained by Mercer and, as such, there was no formal consultancy role played by them.
In preparation for its January 22, 2014 Committee meeting, the Committee directed Mr. Dunn, Mr. Stivala, Mr. Kuglin, Mr. Wienberg, and our Senior Vice President—Administration to meet with principals of Towers Watson to discuss the then current responsibilities of our senior level executives and their thoughts on the future responsibilities of these executives in light of the Committee’s succession planning efforts. It was from these interviews with our senior executive officers that the principals of Towers Watson developed their recommendations regarding compensation of our senior level executive team.
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 for the first six months of fiscal 2014 (i.e., October 2013 through March 2014). For this period, the base salaries and cash bonus targets of our named executive officers remained identical to those in effect for fiscal 2013.
| | | | | | | | | | | | | | | | Base
Salary | | | Cash
Bonus
Target | | | Long-
Term
Incentive | | Michael J. Dunn, Jr. | | | 40 | % | | | 40 | % | | | 20 | % | Michael A. Stivala | | | 46 | % | | | 36 | % | | | 18 | % | Michael A. Kuglin | | | 51 | % | | | 33 | % | | | 16 | % | Mark Wienberg | | | 46 | % | | | 36 | % | | | 18 | % | Steven C. Boyd | | | 46 | % | | | 36 | % | | | 18 | % | Douglas T. Brinkworth | | | 46 | % | | | 36 | % | | | 18 | % |
The following table summarizes the components as percentages of each named executive officer’s total cash compensation opportunity for the second six months of fiscal 2014 (i.e., April 2014 through September 2014).
| | | | | | | | | | | | | | | | Base
Salary | | | Cash
Bonus
Target | | | Long-
Term
Incentive | | Michael J. Dunn, Jr. | | | 40 | % | | | 40 | % | | | 20 | % | Michael A. Stivala | | | 44 | % | | | 44 | % | | | 12 | % | Michael A. Kuglin | | | 50 | % | | | 35 | % | | | 15 | % | Mark Wienberg | | | 46 | % | | | 37 | % | | | 17 | % | Steven C. Boyd | | | 46 | % | | | 37 | % | | | 17 | % | Douglas T. Brinkworth | | | 46 | % | | | 37 | % | | | 17 | % |
In allocating compensation among these components, we believe that the compensation of our senior level executive officers—the executive officers having the greatest ability to influence our performance—should be approximately 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.
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 Suburban, individual performance and years of experience in his 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 Plan (see below for a description of this plan). 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 level executive officers 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.
Base Salary
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 has been 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. This year, in order to facilitate the succession planning process, the Committee engaged the services of Towers Watson to make recommendations regarding the compensation packages provided to the executive officers the Committee identified as the Partnership’s senior level executive officers. In accordance with a tentative plan of succession discussed by the Committee at its November 13, 2013 meeting, the Committee decided to postpone discussions of base salary adjustments for our senior level executive officers until its January 22, 2014 Committee meeting when the results of the Towers Watson study would be made available.
In accordance with the recommendations contained in the Towers Watson study, the Committee adjusted the base salaries of the named executive officers (withof Ferrellgas Partners, L.P. and AmeriGas Partners, L.P. were included in the exception of Mr. Dunn who retired at the conclusion of fiscal 2014). These adjustments became effective on April 1, 2014, the effective date of Mr. Stivala’s promotion to President; Mr. Kuglin’s promotion to Vice President—Finance and Chief Accounting Officer; Mr. Wienberg’s promotion to Chief Operating Officer; Mr. Boyd’s promotion to Senior Vice President—Field Operations; and Mr. Brinkworth’s promotion to Senior Vice President – Product Supply, Purchasing & Logistics.
| | | | | | | | | | | | | Name | | Fiscal 2014
Base Salary
(Second Six Months
of Fiscal Year) | | | Fiscal 2014
Base Salary
(First Six Months
of Fiscal Year) | | | Fiscal 2013
Base Salary | | Michael J. Dunn, Jr. | | $ | 495,000 | | | $ | 495,000 | | | $ | 495,000 | | Michael A. Stivala | | $ | 425,000 | | | $ | 300,000 | | | $ | 300,000 | | Michael A. Kuglin | | $ | 265,000 | | | $ | 240,000 | | | $ | 240,000 | | Mark Wienberg | | $ | 325,000 | | | $ | 280,000 | | | $ | 280,000 | | Steven C. Boyd | | $ | 315,000 | | | $ | 290,000 | | | $ | 290,000 | | Douglas T. Brinkworth | | $ | 300,000 | | | $ | 270,000 | | | $ | 270,000 | |
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.
At its meeting on July 22, 2014, effective September 28, 2014, the Committee increased Mr. Kuglin’s salary to $275,000, in recognition of his promotion to Chief Financial Officer and Chief Accounting Officer.
At its meeting on November 11, 2014, the Committee did not adjust the base salaries of our named executive officersbenchmarking study provided by Towers Watson for fiscal 2015 because their salaries were adjusted on April 1, 2014.
The base salaries paid to the named executive officers in fiscal 2014, fiscal 20132016 and fiscal 2012 are reported in the column titled “Salary” in the Summary Compensation Table below.
Annual Cash Bonus Plan
Annual cash bonuses (which fall within the Securities 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 of our named executive officers’ annual base salaries (“target cash bonus”) if, for the fiscal year, actual cash bonus plan EBITDA equals the Partnership’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; acquisition-related costs; integration-related costs; multiemployer pension plan withdrawal charges; pension settlement charges; and losses on debt extinguishment. Under the provisions of the annual cash bonus plan in effect for fiscal 2014, our executive officers had the opportunity to earn between 60% and 120% of their target cash bonuses, depending upon the Partnership’s EBITDA performance during the fiscal year. No bonuses would be earned during fiscal 2014 if actual cash bonus plan EBITDA were less than 90% of budgeted cash bonus plan EBITDA; additionally, for fiscal 2014, cash bonuses could not exceed 120% of the target cash bonus even if actual cash bonus plan EBITDA were more than 120% of budgeted cash bonus plan EBITDA.
Although our annual cash bonus plan is generally administered in accordance with the provisions of the plan, 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 to the executive officers as a group, when the Committee recognizes that an adjustment is warranted. During fiscal 2014, fiscal 2013 and fiscal 2012, no such discretionary adjustments were made to the annual cash bonuses earned by our executives.
For fiscal 2014, our budgeted cash bonus plan EBITDA was $360.0 million (“Budgeted EBITDA”). Our actual cash bonus plan EBITDA was such that each of our executive officers earned 68% of his or her target cash bonus. The following table provides the fiscal 2014 budgeted cash bonus plan EBITDA targets that were established at the November 13, 2013 Committee meeting:
| | | | | | | | | Hypothetical Fiscal 2014 Cash Bonus Plan EBITDA Results (in Millions) | | Hypothetical Fiscal
2014 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 | | $432.0 | | | 120 | % | | | 120 | % | $396.0 | | | 110 | % | | | 110 | % | $360.0(1) | | | 100 | % | | | 100 | % | $342.0 | | | 95 | % | | | 90 | % | $324.0 | | | 90 | % | | | 60 | % |
(1) | Budgeted cash bonus plan EBITDA for fiscal 2014. |
For those named executive officers who were promoted on April 1, 2014 (all of our named executive officers except Mr. Dunn), actual payments earned are equal to one half of what the payment would have been using each named executive officer’s base salary and bonus percentage in effect for the first half of fiscal 2014, plus one half of what the payment would have been using each named executive officer’s base pay and bonus percentage in effect for the second half of fiscal 2014. The fiscal 2014 target cash bonus percentages for both halves of the year and the blended target cash bonuses established for each named executive officer and the actual cash bonuses earned by each of them during fiscal 2014 are summarized as follows:
| | | | | | | | | | | | | | | | | Name | | 2014 Target Cash
Bonus as a % of
Base Salary
(for the First Half
of the Fiscal Year) | | | 2014 Target Cash
Bonus as a % of
Base Salary
(for the Second Half
of the Fiscal Year) | | | 2014 Target
Cash Bonus | | | 2014 Actual
Cash Bonus
Earned at 68% | | Michael J. Dunn, Jr. | | | 100 | % | | | 100 | % | | $ | 495,000 | | | $ | 336,600 | | Michael A. Stivala | | | 80 | % | | | 100 | % | | $ | 332,500 | | | $ | 226,100 | | Michael A. Kuglin | | | 65 | % | | | 70 | % | | $ | 170,750 | | | $ | 116,110 | | Mark Wienberg | | | 80 | % | | | 80 | % | | $ | 242,000 | | | $ | 164,560 | | Stephen C. Boyd | | | 80 | % | | | 80 | % | | $ | 242,000 | | | $ | 164,560 | | Douglas T. Brinkworth | | | 80 | % | | | 80 | % | | $ | 228,000 | | | $ | 155,040 | |
For purposes of establishing the cash bonus targets for fiscal 2014, the Committee reviewed and approved our fiscal 2014 budgeted cash bonus plan EBITDA at its November 13, 2013 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 balance between a target that is reasonably achievable, yet not assured. As described above, during fiscal 2014, our executive officers had 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 68%, 60% and 0% of their respective target cash bonus for fiscal 2014, fiscal 2013 and fiscal 2012, respectively.
With the exception of Mr. Kuglin (and Mr. Dunn who has retired), the named executive officers’ target cash bonus percentages and target cash bonuses for fiscal 2015 are the same as those for the second half of fiscal 2014. In recognition of his promotion to Chief Financial Officer and Chief Accounting Officer, Mr. Kuglin’s fiscal 2015 target cash bonus has been increased to 75% of his base salary. Actual payments for fiscal 2015 under the annual cash bonus plan will depend upon the percentage of the budgeted cash bonus plan EBITDA for fiscal 2015 that is eventually achieved.
In accordance with recommendations from Towers Watson, the Committee modified the terms of our annual cash bonus plan, beginning with fiscal 2015, to provide our executive officers with the opportunity to earn between 50% and 120% of their target cash bonuses, depending upon the Partnership’s EBITDA performance during the fiscal year. No bonuses will be earned during fiscal 2015 if actual cash bonus plan EBITDA is less than 85% of budgeted cash bonus plan EBITDA; additionally, for fiscal 2015, 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.
The bonuses earned by our named executive officers under the annual cash bonus plan for fiscal 2014 and 2013 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 Plan, which we hereafter refer to as the “LTIP,” is structured as a phantom unit 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 payments, if any, are earned and paid at the end of a three-year measurement period, depending on performance.
The LTIP is designed to:
Align a portion of our executive officers’ compensation opportunities with the long-term goals of our Unitholders;
Provide long-term compensation opportunities consistent with market practice;
Reward long-term value creation; and
Provide a retention incentive for our executive officers and other key employees.
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. In accordance with recommendations from Towers Watson, 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 Phantom 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 as part of each executive officer’s target cash bonus by the average of the closing prices of our Common Unitsits decision-making process. This benchmarking approach has been in place 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 2014 and fiscal 2013 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 2016 for the fiscal 2014 award and at the end of fiscal 2015 for the fiscal 2013 award):
| | | | | | | | | | | | Fiscal
2014
Award | | | Fiscal
2013
Award | | Michael J. Dunn, Jr. | | | 5,404 | | | | 6,559 | | Michael A. Stivala | | | 2,620 | | | | 3,180 | | Michael A. Kuglin | | | 1,703 | | | | 2,067 | | Mark Wienberg | | | 2,445 | | | | 2,968 | | Steven C. Boyd | | | 2,533 | | | | 3,074 | | Douglas T. Brinkworth | | | 2,358 | | | | 2,862 | |
At its meeting on November 11, 2014, the Committee approved the grant of the followinga number of unvested LTIP unit awards under the LTIP for the fiscal 2015 award cycle that commenced at the beginning of fiscal 2015 and will conclude at the end of fiscal 2017 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 2017).years.
| | | | | | | Fiscal
2015
Award | | Michael A. Stivala
| | | 4,770 | | Michael A. Kuglin
| | | 2,315 | | Mark Wienberg
| | | 2,918 | | Steven C. Boyd
| | | 2,828 | | Douglas T. Brinkworth
| | | 2,694 | |
Performance Metrics
The primary difference between the 2003/2013 LTIPs and the 2014 LTIP is the performance metric used to determine whether cash payments 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, 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 fiscal 2013 LTIP award is the only remaining award subject to this metric.
The following table lists, in alphabetical order, the names and ticker symbols of the peer group used to measure our performance during the three-year measurement period for the fiscal 2013 LTIP award:
| | | 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 2013 award, as a result of this event, we have reduced the peer group of this award by one member. |
(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 trades under ticker CMLP on the New York Stock Exchange. For purposes of measuring relative TRU for the fiscal 2013 award, as a result of this event, we have reduced the peer group of this award by one member. |
The three-year measurement period of the fiscal 2012 award ended simultaneously with the conclusion of fiscal 2014. The TRU for the fiscal 2012 award fell within the lowest quartile; therefore, the participants, including our named executive officers, did not earn cash payments 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 cash payments under the 2014 LTIP will be determined based on the level of our distribution coverage ratio over a three-year measurement period (“Distribution Coverage Ratio”). 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 LTIP 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, “LTIP 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 of the three years in an award’s three-year measurement period. Baseline cash flow is calculated by multiplying the total number of Common Units outstanding 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 2013 award), 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 payment equal to:
The quantity of the participant’s LTIP units multiplied by the average of the closing prices of our Common Units for the twenty days preceding the conclusion of the three-year measurement period;
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 within the second highest quartile; and 125% if our performance falls within the top quartile.
For awards granted under the 2014 plan document (the fiscal 2014 award payable, if earned, at the end of fiscal 2016 and the fiscal 2015 award, payable, if earned, at the end of fiscal 2017), at the end of the three-year measurement period, depending on the Distribution Coverage Ratio for that three-year measurement period, our executive officers, as well as the other participants, all of whom are key employees, will receive cash payments equal to:
The quantity of the participant’s LTIP units multiplied by the average of the closing prices of our Common Units for the twenty days preceding the conclusion of the three-year measurement period;
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 the applicable percentage corresponding to the Distribution Coverage Ratio illustrated in the following table:
| | | | | Distribution Coverage Ratio | | % of
Award
Earned | | 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 will remain subject to the same three-year measurement period for purposes of determining the eventual cash payment, if any, at the conclusion of the measurement period.
The grant date values based on the probable outcomes of the awards under the LTIP granted during fiscal 2014, fiscal 2013 and fiscal 2012 (although the final measurement of the fiscal 2012 award resulted in no actual payments to our executive officers) are reported in the column titled “Unit Awards” in the Summary Compensation Table below.
Restricted Unit Plan
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 (collectively and individual referred to as the “RUP”) are substantially identical. At the conclusion of fiscal 2014, there remained 417,758 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, in accordance with recommendations from Towers Watson, the Committee amended the Partnership’s 2009 Restricted Unit Plan to revise the normative vesting schedule of awards granted thereafter to one third 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 meets all three of the following conditions on his or her retirement date:
The unvested award has been held by the grantee for at least six months;
The grantee is age 55 or older; and
The grantee has worked for us or one of our predecessors for at least 10 years.
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 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;
To retain the services of an employee;
To provide an adequate compensation package to accompany an internal promotion; and
To reward outstanding performance.
In determining the quantity of restricted units to grant to executive officers and other key employees, the Committee considers, without limitation:
The executive officer’s or key employee’s scope of responsibility, performance and contribution to meeting our objectives;
The total cash compensation opportunity provided to the executive officer or key employee for whom the award is being considered;
The value of similar equity awards to executive officers of similarly sized enterprises; and
The current value of a similar quantity of outstanding Common Units.
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.
At its November 13, 2013 meeting, in order to further align the interests of management with the interests of our Unitholders the Committee approved the following grants to the following named executive officers:
| | | | | | | Grant Name
| | Grant Date
| | Quantity | | Michael A. Stivala
| | November 15, 2013 | | | 5,302 | | Michael A. Kuglin
| | November 15, 2013 | | | 4,242 | | Mark Wienberg
| | November 15, 2013 | | | 5,302 | | Steven C. Boyd
| | November 15, 2013 | | | 5,302 | | Douglas T. Brinkworth
| | November 15, 2013 | | | 5,302 | |
In determining these fiscal 2014 awards for Mr. Stivala, Mr. Kuglin, Mr. Wienberg, Mr. Boyd 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 throughout fiscal 2013. No award was granted to our Chief Executive Officer at the Committee’s November 13, 2013 meeting.
At its January 22, 2014 meeting, in accordance with the recommendations of Towers Watson, in recognition of Mr. Dunn’s years of service to the Partnership and in recognition of the promotions of the senior level executive officers, the Committee approved the following grants to the named executive officers:
| | | | | | | Grant Name
| | Grant Date
| | Quantity | | Michael J. Dunn, Jr.
| | March 1, 2014 | | | 17,009 | | Michael A. Stivala
| | April 1, 2014 | | | 23,885 | | Michael A. Kuglin
| | April 1, 2014 | | | 11,943 | | Mark Wienberg
| | April 1, 2014 | | | 11,943 | | Steven C. Boyd
| | April 1, 2014 | | | 11,943 | | Douglas T. Brinkworth
| | April 1, 2014 | | | 11,943 | |
The aggregate grant date fair values of RUP awards made during fiscal 2014, fiscal 2013 and fiscal 2012, computed in accordance with accounting principles generally accepted in the United States of America are reported in the column titled “Unit Awards” in the Summary Compensation Table below.
At its November 11, 2014 meeting, the Committee did not grant any additional RUP awards to our named executive officers because each of these individuals was granted an award on April 1, 2014.Risk Mitigation Policies
Equity Holding Policy 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 executive officers are expected to maintain. Effective November 11, 2015, the Committee approved an amendment to the Equity Holding Policy to increase the equity holding requirement for members of our Board of Supervisors from two times their annual fees to three times their annual fees. The Partnership’s equity holding requirements for the specified positions are currently as follows: Position | | Amount | Member of the Board of Supervisors | | 3 x Annual Fee | President and Chief Executive Officer | | 5 x Base Salary | Chief Financial Officer | | 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 |
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As of the January 2, 2016 measurement date, the amounts of units held by Mr. Stivala and by Mr. Kuglin were less than the amount noted above for their respective positions. This was the first time since adoption of the Equity Holding Policy that any of our executives held less than the applicable amount outlined in the policy. After a careful review of the circumstances, the Committee concluded that these shortfalls were attributable to the precipitous decline in the trading price of our Common Units leading up to the measurement date, similar to the trading performance of other master limited partnerships during that time. Later in 2016, the trading price of our Common Units increased and these named executive officers returned to compliance with the Equity Holding Policy. The Equity Holding Policy can be accessed through a link on our website atwww.suburbanpropane.com under the “Investors” tab. The Partnership’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 2, 2014 measurement date, all of our executive officers, including our named executive officers, as well as the members of our Board of Supervisors, were in compliance with our Equity Holding Policy.
Incentive Compensation Recoupment Policy Upon recommendation by the Committee, on April 25, 2007, the Board of Supervisors has adopted an Incentive Compensation Recoupment Policy whichthat permits the Committee to seek the reimbursement from certain executives of the Partnership and the Operating Partnership of incentive compensation (i.e., payments/awardspayments made pursuant to the annual cash bonus plan and the LTIP and RUP)Long-Term Incentive Plan) paid to those executives in connection with any fiscal year for which there is a significant restatement of the published financial statements of the Partnership triggered by a material accounting error, which results in less favorable results than those originally reported. Such reimbursement can be sought from executives even if they had no responsibilitywere not personally responsible 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 Partnership 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. Executive Compensation Philosophy Overview Our executive compensation program is underpinned by two core objectives: To attract and retain talented executives who have the skills and experience required to achieve our goals; and To align the short-term and long-term interests of our executive officers with those of our Unitholders. We accomplish these objectives by providing our executives with compensation packages that combine various components, specifically linked to either short-term or long-term performance measures, and that encourage equity ownership in the Partnership. 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. 51
The principal components of the compensation we provide to our named executive officers are as follows: Component | | Purpose | | Features | Base Salary | | • To reward individual performance, experience and scope of responsibility • To be competitive with market pay practices | | • Reviewed and approved annually • Market benchmarked • Mean market salary data is considered in determining levels | Annual cash incentive | | • Drive and reward the delivery of financial and operating performance during a particular fiscal year | | • Paid in cash • Based solely on annual EBITDA performance compared to budgeted EBITDA | Long-term incentives | | • To ensure alignment of interests with the long-term goals of Unitholders • To reward activities and practices that are conducive to sustainable, profitable growth and long-term value creation • To attract and retain skilled individuals | | • Annual awards of phantom units settled in cash • Measured over a three-year period based on the level of our average distributable cash flow over such three-year measurement period | Restricted units | | • Retain the services of the recipient over the vesting period • Further align the long-term interests of the recipient with the long-term interests of our Unitholders through encouragement of equity ownership • To help make up for potential shortfalls in total cash compensation of our executive officers when compared to benchmarked total cash compensation • To provide an adequate compensation package in connection with an internal promotion • To reward outstanding performance | | • No pre-determined frequency or amounts of awards • Plan provides the Committee flexibility to respond to different facts and circumstances • Awards normally vest in equal thirds on the first three anniversaries of the date of grant • Awards are settled in Common Units |
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 our executive officers with an annual incentive target that encourages them to achieve or exceed targeted financial results and operating performance for a particular fiscal year; Providing a long-term incentive plan that encourages our executive officers to implement activities and practices conducive to sustainable, profitable growth; and Providing our executive officers with restricted units in order to encourage the retention of the participating executive officers, while simultaneously encouraging behaviors conducive to the long-term appreciation of our Common Units. Pay Mix Under our compensation structure, each executive officer’s “total cash compensation opportunity” consists of a mix of base salary, cash bonus and cash-settled long-term incentives. This “mix” 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. In allocating among these components, in order to align the interests of our senior executive officers - the executive officers having the greatest ability to influence our performance - with the interests of our Unitholders, we consider it crucial to emphasize the performance-based elements of the total compensation opportunities that we provide to them. Therefore, during fiscal 2016, the total cash compensation opportunity for our senior executive officers, including our named executive officers, was at least 50% performance-based under our annual cash bonus and long-term incentive plans, neither of which provide for minimum payments. 52
The following table summarizes each of these components as a percentage of each named executive officer’s total cash compensation opportunity for fiscal 2016: | | Base Salary | | | Cash Bonus Target | | | Long-Term Incentive | | Michael A. Stivala | | | 40% | | | | 40% | | | | 20% | | Michael A. Kuglin | | | 45% | | | | 36% | | | | 19% | | Steven C. Boyd | | | 45% | | | | 36% | | | | 19% | | Douglas T. Brinkworth | | | 45% | | | | 36% | | | | 19% | | Paul Abel | | | 47% | | | | 35% | | | | 18% | | Mark Wienberg | | | 45% | | | | 36% | | | | 19% | |
Components of Compensation Base Salary The fiscal 2016 base salary adjustments for the named executive officers and all of our other executive officers were reviewed and approved by the Committee. As was explained in the section above titled “The Annual Compensation Decision Making Process,” the Committee compared each named executive officer’s total cash compensation opportunity to the total mean cash compensation opportunity for the parallel position in the Mercer benchmarking database. In addition, the Committee retained the services of Towers Watson to benchmark the base salaries and total direct compensation of our executive officers compared to comparable positions, using market data for similarly-sized companies which was developed by Towers Watson from multiple survey sources across several industries, inclusive of other energy companies in the United States. The Committee then based its final decisions on both the recommendations made by Towers Watson and on the information contained in the Mercer benchmarking database. The following base salaries were in effect during fiscal 2016 and fiscal 2015 for our named executive officers: | | Fiscal 2016 Base Salary | | | Fiscal 2015 Base Salary | | Michael A. Stivala | | $ | 500,000 | | | $ | 425,000 | | Michael A. Kuglin | | $ | 310,000 | | | $ | 275,000 | | Steven C. Boyd | | $ | 330,000 | | | $ | 315,000 | | Douglas T. Brinkworth | | $ | 310,000 | | | $ | 300,000 | | Paul Abel | | $ | 300,000 | | | $ | 290,000 | | Mark Wienberg | | $ | 335,000 | | | $ | 325,000 | |
At its November 14, 2016 meeting, the Committee increased Mr. Kuglin’s base salary to $330,000, in recognition of his performance throughout the year and to bridge a perceived shortfall between his former base salary and the benchmark salaries for similar positions. The Committee did not make any other adjustments to the base salaries of our named executive officers. The base salaries paid to our named executive officers in fiscal 2016, fiscal 2015 and fiscal 2014 are reported in the column titled “Salary” in the Summary Compensation Table below. Annual Cash Bonus Plan The Committee uses the Annual Cash Bonus Plan (which falls within the Securities and Exchange Commission’s definition of a “Non-Equity Incentive Plan” for the purposes of the Summary Compensation Table and otherwise) to provide a cash incentive award to our executive officers for the attainment of EBITDA targets for the particular fiscal year, in accordance with the annual budget approved by our Board of Supervisors at the beginning of the fiscal year. Performance Condition The sole metric measures Actual Plan EBITDA relative to Budgeted EBITDA. Definitions Actual EBITDA: represents net income before deducting interest expense, income taxes, depreciation and amortization. 53
Actual Plan EBITDA: represents Actual EBITDA adjusted 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; gains or losses on sale of business; acquisition and integration-related costs; multi-employer pension plan withdrawal charges; pension settlement charges; and losses on debt extinguishment. Budgeted EBITDA: represents our target budgeted EBITDA developed 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 balance between a target that is reasonably achievable, yet not assured. The performance targets for our Annual Cash Bonus Plan for fiscal years subsequent to fiscal 2014 were established by the Committee at its January 22, 2014 meeting, following a review of recommendations made by Towers Watson, which had been engaged by the Committee for that purpose. For fiscal 2016 and fiscal 2015, our named executive officers had the opportunity to earn between 50% and 120% of their target cash bonuses, and for fiscal years prior to fiscal 2015, our named executive officers had the opportunity to earn between 60% and 120% of their target cash bonuses, depending upon the relationship of our Actual Plan EBITDA compared to Budgeted EBITDA in accordance with the following tables: | | Fiscal 2016 and Fiscal 2015 | | | Fiscal 2014 | | | Actual EBITDA as a % of budgeted EBITDA | | % of Target Cash Bonus Earned | | | Actual EBITDA as a % of budgeted EBITDA | | % of Target Cash Bonus Earned | Maximum | | 120% and above | | 120% | Maximum | | 120% and above | | 120% | | | 119% | | 119% | | | 119% | | 119% | | | 118% | | 118% | | | 118% | | 118% | | | 117% | | 117% | | | 117% | | 117% | | | 116% | | 116% | | | 116% | | 116% | | | 115% | | 115% | | | 115% | | 115% | | | 114% | | 114% | | | 114% | | 114% | | | 113% | | 113% | | | 113% | | 113% | | | 112% | | 112% | | | 112% | | 112% | | | 111% | | 111% | | | 111% | | 111% | | | 110% | | 110% | | | 110% | | 110% | | | 109% | | 109% | | | 109% | | 109% | | | 108% | | 108% | | | 108% | | 108% | | | 107% | | 107% | | | 107% | | 107% | | | 106% | | 106% | | | 106% | | 106% | | | 105% | | 105% | | | 105% | | 105% | | | 104% | | 104% | | | 104% | | 104% | | | 103% | | 103% | | | 103% | | 103% | | | 102% | | 102% | | | 102% | | 102% | | | 101% | | 101% | | | 101% | | 101% | Target | | 100% | | 100% | Target | | 100% | | 100% | | | 99% | | 98% | | | 99% | | 98% | | | 98% | | 96% | | | 98% | | 96% | | | 97% | | 94% | | | 97% | | 94% | | | 96% | | 92% | | | 96% | | 92% | | | 95% | | 90% | | | 95% | | 90% | | | 94% | | 85% | | | 94% | | 68% | | | 93% | | 82.5% | | | 93% | | 66% | | | 92% | | 80% | | | 92% | | 64% | | | 91% | | 77.5% | | | 91% | | 62% | | | 90% | | 75% | Entry | | 90% | | 60% | | | 89% | | 70% | | | Below 90% | | 0% | | | 88% | | 65% | | | | | | | | 87% | | 60% | | | | | | | | 86% | | 55% | | | | | | Entry | | 85% | | 50% | | | | | | | | Below 85% | | 0% | | | | | |
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The Committee made this change to the performance targets of our Annual Cash Bonus Plan based upon Towers Watson’s benchmark study performed in fiscal 2016, which indicated that the entry point utilized in our plan was higher than those of similar plans utilized by comparable companies. Fiscal 2016 Annual Cash Bonus For fiscal 2016, our Budgeted EBITDA was $350.0 million. Our Actual Plan EBITDA was such that each of our executive officers earned 0% of his or her target cash bonus. During the previous two fiscal years, our Actual Plan EBITDA was such that each of our named executive officers earned 90% and 68% of their target cash bonus for fiscal 2015 and fiscal 2014, respectively. The fiscal 2016 target cash bonuses established for each named executive officer and the actual cash bonuses earned by each of them during fiscal 2016 are summarized as follows: Name | | Fiscal 2016 Target Cash Bonus as a Percentage of Base Salary | | | Fiscal 2016 Target Cash Bonus | | | Fiscal 2016 Actual Cash Bonus Earned at 0% | | Michael A. Stivala | | | 100% | | | $ | 500,000 | | | $ | — | | Michael A. Kuglin | | | 80% | | | $ | 248,000 | | | $ | — | | Steven C. Boyd | | | 80% | | | $ | 264,000 | | | $ | — | | Douglas T. Brinkworth | | | 80% | | | $ | 248,000 | | | $ | — | | Paul Abel | | | 75% | | | $ | 225,000 | | | $ | — | | Mark Wienberg | | | 80% | | | $ | 268,000 | | | $ | — | |
The Use of Discretion Although our Annual Cash Bonus Plan is generally administered in accordance with the provisions of the plan, the Committee may exercise its broad discretionary powers, expressly provided for in the plan, 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 to the executive officers as a group, when the Committee determines that an adjustment is warranted. In each of fiscal 2016, fiscal 2015 and fiscal 2014, no such discretionary adjustments were made to the annual cash bonuses earned by our named executive officers. At its meeting of November 14, 2016, the Committee approved the following fiscal 2017 target cash bonuses: Name | | Fiscal 2017 Target Cash Bonus as a Percentage of Base Salary | | | Fiscal 2017 Target Cash Bonus | | Michael A. Stivala | | | 100% | | | $ | 500,000 | | Michael A. Kuglin | | | 80% | | | $ | 264,000 | | Steven C. Boyd | | | 80% | | | $ | 264,000 | | Douglas T. Brinkworth | | | 80% | | | $ | 248,000 | | Paul Abel | | | 75% | | | $ | 225,000 | |
The bonuses earned by our named executive officers under the annual cash bonus plan for fiscal 2016, fiscal 2015 and fiscal 2014 are reported in the column titled “Non-Equity Incentive Plan Compensation” in the Summary Compensation Table below. Long-Term Incentive Plan To complement the Annual Cash Bonus Plan, which focuses on our short-term financial goals, the Long-Term Incentive Plan, which we hereafter refer to as the “LTIP,” is a phantom unit plan that is designed to motivate our executive officers to focus on our long-term financial goals. Performance Condition Under the LTIP, performance is assessed based on the level of our distribution coverage ratio over a three-year measurement period (“Distribution Coverage Ratio”). This ratio will be calculated (as shown below) 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 Committee adopted this measure for LTIP awards because the Partnership’s ability to support future cash 55
distributions, and demonstrate distribution growth, is essential to successfully attracting and retaining investors, making it an important long-term performance metric. Average Distributable Cash Flow (Average Actual Plan EBITDA less capital expenditures, cash interest expense and other adjustments) Baseline Cash Flow (Total # of Common Units outstanding at beginning of the three-year measurement period times the then annualized
distribution rate) Definitions Distributable Cash Flow: represents Actual Plan EBITDA for a particular fiscal year less capital expenditures, cash interest expense, and the provision for income taxes for the same fiscal year. Actual Plan EBITDA: represents the same definition as Actual Plan EBITDA under the Annual Cash Bonus Plan. Actual EBITDA is adjusted 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; gains or losses on sale of business; acquisition and integration-related costs; multi-employer pension plan withdrawal charges; pension settlement charges; and losses on debt extinguishment. Average Distributable Cash Flow: represents average distributable cash flow for each of the three years in a particular award’s three-year measurement period, plus the product of the number of Common Units outstanding at the beginning of the three-year measurement period and 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 of those three years. Baseline Cash Flow: represents the total number of Common Units outstanding at the beginning of the three-year measurement period multiplied by the then per Common Unit annualized distribution rate. The following table summarizes the performance targets and associated level of vesting that applies to awards made under the LTIP prior to November 14, 2016 based on the achievement level of the Distribution Coverage Ratio: Distribution Coverage Ratio | | % of Award Earned | | 1.50 or higher (Maximum) | | | 150% | | 1.20 (Target) | | | 100% | | 1.00 (Entry) | | | 50% | | Less than 1.00 | | | 0% | |
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Between entry and target performance, for every additional 0.01 increase in the Distribution Coverage Ratio, an additional 2.5% of the award is earned. Between target and maximum performance, awards are earned according to the following schedule: Distribution Coverage Ratio | | % of Award Earned | | | Distribution Coverage Ratio | | % of Award Earned | | 1.50 or higher | | | 150.0% | | | 1.34 | | | 123.4% | | 1.49 | | | 148.4% | | | 1.33 | | | 121.7% | | 1.48 | | | 146.8% | | | 1.32 | | | 120.0% | | 1.47 | | | 145.1% | | | 1.31 | | | 118.4% | | 1.46 | | | 143.4% | | | 1.30 | | | 116.7% | | 1.45 | | | 141.8% | | | 1.29 | | | 115.0% | | 1.44 | | | 140.1% | | | 1.28 | | | 113.4% | | 1.43 | | | 138.4% | | | 1.27 | | | 111.7% | | 1.42 | | | 136.7% | | | 1.26 | | | 110.0% | | 1.41 | | | 135.1% | | | 1.25 | | | 108.4% | | 1.40 | | | 133.4% | | | 1.24 | | | 106.7% | | 1.39 | | | 131.7% | | | 1.23 | | | 105.0% | | 1.38 | | | 130.1% | | | 1.22 | | | 103.3% | | 1.37 | | | 128.4% | | | 1.21 | | | 101.7% | | 1.36 | | | 126.7% | | | 1.20 | | | 100.0% | | 1.35 | | | 125.1% | | | | | | | |
At its meeting on November 14, 2016, the Committee amended the LTIP to revise the performance targets and associated level of vesting that applies to awards made under the LTIP on or after September 25, 2016. The following table summarizes the performance targets and associated level of vesting, based on the achievement level of the Distribution Coverage Ratio: Distribution Coverage Ratio | | % of Award Earned | | 1.25 or higher (Maximum) | | | 150% | | 1.10 (Target) | | | 100% | | 1.00 (Entry) | | | 50% | | Less than 1.00 | | | 0% | |
As a result of this amendment, between entry and target performance, for every additional 0.01 increase in the Distribution Coverage Ratio, an additional 5% of the award will be earned. Between target and maximum performance, awards will be earned according to the following schedule: Distribution Coverage Ratio | | % of Award Earned | | 1.25 or higher | | | 150.0% | | 1.24 | | | 146.7% | | 1.23 | | | 143.3% | | 1.22 | | | 140.0% | | 1.21 | | | 136.7% | | 1.20 | | | 133.3% | | 1.19 | | | 130.0% | | 1.18 | | | 126.7% | | 1.17 | | | 123.3% | | 1.16 | | | 120.0% | | 1.15 | | | 116.7% | | 1.14 | | | 113.3% | | 1.13 | | | 110.0% | | 1.12 | | | 106.7% | | 1.11 | | | 103.3% | | 1.10 | | | 100.0% | |
This amendment to the LTIP did not lower the minimum required Distribution Coverage Ratio for participants to earn an entry-level award. The Committee’s decision to reduce the target-level and maximum-level award thresholds was intended to strike a better balance between an award that is reasonably achievable, yet not assured. 57
In addition, an amendment to the existing LTIP document was approved in order to properly reflect the original intent of the change of control language contained in the Partnership’s successive long term incentive plans to provide for a payout of the maximum threshold amount upon a change of control. When the current LTIP was adopted effective 2014, the maximum payout opportunity for participants under the LTIP was increased from 125% to 150%, but this increase was inadvertently not reflected in the change of control provision of the LTIP. This amendment aligns the change of control language to coincide with the current maximum threshold. Grant Process At the beginning of each fiscal year, LTIP unit awards are granted as a Committee-approved percentage of each executive officer’s salary. In accordance with the terms of the LTIP, at the beginning of each three-year measurement period, the number of each executive officer’s unvested LTIP phantom unit awards is calculated by dividing his target LTIP amount (representing 50% of that executive officer’s target cash bonus under the Annual Cash Bonus Plan) by the average of the closing prices of our Common Units for the twenty days preceding the beginning of the three-year measurement period. Cash Payments For awards granted under the LTIP, our executive officers, as well as the other LTIP participants (all of whom are key employees), will, at the end of the three-year measurement period, receive cash payments equal to: The quantity of the participant’s phantom units multiplied by the average of the closing prices of our Common Units for the twenty days preceding the conclusion of the three-year measurement period; The quantity of the participant’s phantom 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 the applicable percentage corresponding to the Distribution Coverage Ratio illustrated in the applicable preceding table (based on the fiscal year for which the award was granted). The grant date values based on the target outcomes of the awards under the LTIP granted during fiscal 2016, fiscal 2015 and fiscal 2014 are reported in the column titled “Unit Awards” in the Summary Compensation Table below. Outstanding Awards under the LTIP The following are the quantities of unvested LTIP phantom units granted to our named executive officers during fiscal 2016 and fiscal 2015 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 2018 for the fiscal 2016 awards and at the end of fiscal 2017 for the fiscal 2015 awards): | | Fiscal 2016 Award | | | Fiscal 2015 Award | | Michael A. Stivala | | | 7,095 | | | | 4,770 | | Michael A. Kuglin | | | 3,519 | | | | 2,315 | | Steven C. Boyd | | | 3,746 | | | | 2,828 | | Douglas T. Brinkworth | | | 3,519 | | | | 2,694 | | Paul Abel | | | 3,193 | | | | 2,441 | | Mark Wienberg | | | 3,803 | | | | 2,918 | |
At its meeting on November 14, 2016, the Committee granted the following quantities of unvested LTIP phantom units to our named executive officers for fiscal 2017. These quantities will be used to calculate cash payments, if earned, at the end of this award’s three-year measurement period (i.e., at the end of fiscal 2019). | | Fiscal 2017 Award | | Michael A. Stivala | | | 7,559 | | Michael A. Kuglin | | | 3,991 | | Steven C. Boyd | | | 3,991 | | Douglas T. Brinkworth | | | 3,749 | | Paul Abel | | | 3,402 | |
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Vesting of the LTIP Awards The three-year measurement period of the fiscal 2014 award ended simultaneously with the conclusion of fiscal 2016. The Partnership’s Distribution Coverage Ratio was below the entry threshold for the three-year measurement period. As such, no payments were earned relative to the fiscal 2014 awards. Retirement Provision The retirement provision applies to all LTIP participants who have been employed by the Partnership for ten years and have attained age 55. A retirement-eligible participant’s outstanding awards under the LTIP will vest as of the retirement-eligible date, but will remain subject to the same three-year measurement period for purposes of determining the eventual cash payment, if any, at the conclusion of the remaining measurement period. Mr. Abel is our only named executive officer to whom this retirement provision applied at the end of fiscal 2016. As of the date of this filing, the retirement provision also applies to Mr. Brinkworth. Restricted Unit Plan At our July 22, 2009 Tri-Annual Meeting, our Unitholders approved our adoption of the 2009 Restricted Unit Plan (“RUP”) effective August 1, 2009. Upon adoption, this plan authorized the issuance of 1,200,000 Common Units to our executive officers, managers, other employees and to the members of our Board of Supervisors. On May 13, 2015, following approval by our Unitholders at their 2015 Tri-Annual Meeting, we adopted an amendment to this plan which increased the number of Common Units authorized for issuance under this plan by 1,200,000 for a total of 2,400,000. At the conclusion of fiscal 2016, there remained 1,177,401 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. Grant Process 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 general objective of granting an award to a recipient is to retain the services of the recipient over the 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; To retain the services of an employee; To provide an adequate compensation package to accompany an internal promotion; and To reward outstanding performance. In determining the quantity of restricted units to grant to executive officers and other key employees, the Committee considers, without limitation: The executive officer’s or key employee’s scope of responsibility, performance and contribution to meeting our objectives; The total cash compensation opportunity provided to the executive officer or key employee for whom the award is being considered; The value of similar equity awards to executive officers of similarly sized companies; and The current value of an equivalent quantity of outstanding Common Units. 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. 59
Upon vesting, restricted units are automatically converted into our Common Units, with full voting rights and rights to receive distributions. Vesting Schedule Restricted unit awards granted prior to August 6, 2013 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, after its review of recommendations made by Towers Watson, the Committee amended the RUP to revise the standard vesting schedule of awards granted thereafter to one third on each of the first three anniversaries of the award grant date. The Committee retains the ability to deviate, at its discretion, from the normal vesting schedule with respect to particular restricted unit awards. The Committee amended the plan in order 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 RUP. Outstanding Awards under the RUP At its November 10, 2015 meeting, in order to continue to further align the interests of our named executive officers with those of our Unitholders, the Committee approved a grant of 18,277 restricted units to Mr. Stivala and grants of 8,773 restricted units to each of the other named executive officers. In determining these fiscal 2016 awards for our named executive officers, 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 provided by the Partnership to these executives, as well as in recognition of their individual achievements throughout fiscal 2015. The Committee uses RUP awards to satisfy a perceived need to balance cash compensation with equity (or non-cash) compensation, and to encourage our named executive officers, and other key employees, to have a stake in the Partnership, thereby further aligning the economic interests of our named executive officers with the economic interests of our Common Unitholders. The following table summarizes the RUP awards granted to our named executive officers at the Committee’s November 10, 2015 meeting: Name | | Grant Date | | Quantity | | Michael A. Stivala | | November 15, 2015 | | | 18,277 | | Michael A. Kuglin | | November 15, 2015 | | | 8,773 | | Steven C. Boyd | | November 15, 2015 | | | 8,773 | | Douglas T. Brinkworth | | November 15, 2015 | | | 8,773 | | Paul Abel | | November 15, 2015 | | | 8,773 | | Mark Wienberg | | November 15, 2015 | | | 8,773* | |
| * | Mr. Wienberg was granted 8,773 units at this meeting; however, as a result of his departure from the Partnership, 2,669 units of this award were forfeited. |
The aggregate grant date fair values of RUP awards made during fiscal 2016, fiscal 2015 and fiscal 2014, computed in accordance with accounting principles generally accepted in the United States of America, are reported in the column titled “Unit Awards” in the Summary Compensation Table below. Retirement Provision 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 meets all three of the following conditions on his or her retirement date: The unvested award has been held by the grantee for at least six months; The grantee is age 55 or older; and The grantee has worked for us or one of our predecessors for at least 10 years.
Mr. Abel is our only named executive officer to whom this retirement provision applied at the end of fiscal 2016. As of the date of this filing, this retirement provision also applies to Mr. Brinkworth. As a result of the severance agreement between Mr. Wienberg and the Partnership, we agreed to treat Mr. Wienberg as if on May 26, 2016, he met the criteria of the retirement provision for 16,721 of his 24,032 then outstanding unvested restricted units. *** At its November 14, 2016 meeting, the Committee granted the following RUP awards to our named executive officers: Name | | Grant Date | | Quantity | | Michael A. Stivala | | November 15, 2016 | | | 31,864 | | Michael A. Kuglin | | November 15, 2016 | | | 20,075 | | Steven C. Boyd | | November 15, 2016 | | | 15,932 | | Douglas T. Brinkworth | | November 15, 2016 | | | 15,932 | | Paul Abel | | November 15, 2016 | | | 15,932 | |
The Committee granted these awards in order to further align the economic interests of named executive officers with the economic interests our Common Unitholders. Benefits and Perquisites 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, 1998.1998 (the “Cash Balance Plan”). 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 tobecause of interest credits. Of our named executive officers, only Mr. Dunn, Mr. Boyd and Mr. Brinkworth participate in the plan. The changes in the actuarial value relative to theirMr. Boyd’s and Mr. Brinkworth’s participation in the plan during fiscal 2014,2016, fiscal 20132015 and fiscal 20122014 are reported in the column titled “Change in Pension Value and Nonqualified Deferred Compensation Earnings” in the Summary Compensation Table below. Deferred Compensation All employees, including the named executive officers, who satisfy certain service requirements, are entitledeligible to participate in our IRC Section 401(k) Plan, which we refer to as the “401(k) 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. 61
For fiscal 2014,2016, 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.employees of the Partnership. Amounts deferred by our named executive officers under the 401(k) Plan during fiscal 2014,2016, fiscal 20132015 and fiscal 20122014 are included in the column titled “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 $260,000,$265,000, 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)… (a) | | The Participating
Employee
Will Receive this Matching
Contribution for the Year…Year | | 115% or higher | | | 100100% | % | 100% to 114% | | | 5050% | % | 90% to 99% | | | 2525% | % | Less than 90% | | | 00% | % |
(1) | (a) | For purposes of the 401(k) Plan, the definition of the term “budgeted“Budgeted EBITDA” is identical to that of “budgeted cash bonus plan“Budgeted EBITDA” discussed under the heading titledtitle “Annual Cash Bonus Plan” above. |
Actual cash bonus planPlan EBITDA, when applied to the 401(k) Plan, was such that we willmatching contributions were not earned for calendar year 2016; however, the Committee exercised its discretionary authority to provide participants, in the 401(k) Planincluding our named executive officers, with a matching contributioncontributions equal to 25% of their calendar year 20142016 contributions that do not exceed 6% of their total base pay, up to a maximum annual compensation limit of $260,000. $265,000. The matching contributions made on behalf of our named executive officers for 20142016 are reported in the column titled “All Other Compensation” in the Summary Compensation Table below. Other Benefits As part of his total compensation package, eachEach 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”), thereThere 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 2014,2016, fiscal 20132015 and fiscal 20122014 are reported in the column titled “All Other 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 2014.2016. | Name | | Tax
Preparation
Services | | | Employer-
Provided
Vehicle | | | Physical | | | Tax Preparation Services | | | Employer Provided Vehicle | | | Physical | | Michael J. Dunn, Jr. | | $ | 9,150 | | | $ | 16,549 | | | $ | 1,600 | | | Michael A. Stivala | | $ | -0- | | | $ | 18,153 | | | $ | -0- | | | $ | — | | | $ | 15,234 | | | $ | 2,950 | | Michael A. Kuglin | | $ | -0- | | | $ | 12,725 | | | $ | -0- | | | $ | — | | | $ | 12,046 | | | $ | 2,950 | | Mark Wienberg | | $ | -0- | | | $ | 13,142 | | | $ | 1,750 | | | Steven C. Boyd | | $ | 4,450 | | | $ | 6,837 | | | $ | -0- | | | $ | 3,500 | | | $ | 7,609 | | | $ | — | | Douglas T. Brinkworth | | $ | 4,400 | | | $ | 11,410 | | | $ | 1,500 | | | $ | 3,500 | | | $ | 11,157 | | | $ | 1,600 | | Paul Abel | | | $ | — | | | $ | 15,640 | | | $ | 1,600 | | Mark Wienberg | | | $ | — | | | $ | 11,072 | | | $ | 2,950 | |
Perquisite-related costs for fiscal 2014,2016, fiscal 20132015 and fiscal 20122014 are reported in the column titled “All Other 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 our practice to comply with the statutory and regulatory provisions of IRC Section 409A, the Suburban Propane, L.P. Severance Protection Plan for Key Employees, which we refer to as the “Severance Plan,” provides that if any payment under the Severance Plan subjects a participant to the 20% additional 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.
Letter Agreement of Mr. Dunn
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:
Mr. Dunn will participate in our Severance Protection Plan (see below) at the 78-week participation level.
If on or after the last day of fiscal 2012, Mr. Dunn retires or leaves as a result of an agreed-upon succession plan, he will receive the following if he timely provides us with a release of all claims he might have against us at the time of his departure:
A payment equal to two years of base salary paid over a two year period.
Continuation of medical and dental benefits at no premium cost to him until attainment of age 65 (Mr. Dunn had attained age 65 prior to the conclusion of fiscal 2014).
We 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 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 would not be deemed to have retired or terminated his employment if he simply relinquished the title and responsibilities of President but remained 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 would relinquish the role of President on March 31, 2014, and retire as our Chief Executive Officer on September 27, 2014. Accordingly, the retirement provisions of our letter agreement with Mr. Dunn became effective on September 28, 2014, at which time Mr. Dunn was age 65.
The total payments that will be made under this agreement as a result of Mr. Dunn’s retirement are reported in the column titled “All Other Compensation” in the Summary Compensation Table below.
Severance Benefits We believe that, in most cases, employees should be paid reasonable severance benefits. Therefore, it is the general policy of the CommitteePartnership to provide named 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 named 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 and the Committeeemployee’s level, the Partnership may make exceptions to this general policy. A “key employee”Mr. Wienberg is an employeeour only named executive officer who has attainedentered into a director level pay-gradeseverance agreement with us during fiscal 2016. This severance agreement provides for the following severance benefits in exchange for, among other things, Mr. Wienberg’s release of all claims against the Partnership, Mr. Wienberg’s agreement not to disclose Partnership confidential information in his possession and, through November 24, 2017, Mr. Wienberg’s agreements not to compete with the Partnership, solicit any Partnership customer nor solicit the employment of any Partnership employee:
In periodic payments to be made through November 24, 2017, Mr. Wienberg will receive severance aggregating $502,500 (equal to eighteen (18) months’ base salary), less applicable withholdings; On or higher. “Cause”about November 27, 2016, 16,721 unvested restricted units issued to Mr. Wienberg under the Partnership’s 2009 RUP prior to his departure will vest; If and only if at the conclusion of each of the Partnership’s 2016, 2017 and 2018 fiscal years, participants in the Partnership’s LTIP qualify under the terms of that plan for a cash payment with respect to the award made under that plan in the Partnership’s 2014, 2015 and 2016 fiscal year, respectively, then the Partnership will make a cash payment to Mr. Wienberg in the full, non-pro-rated amount (less applicable withholdings) with respect to each such award that he would have been entitled to had he remained employed with the Partnership at those times (no such payment was due to Mr. Wienberg at the end of the Partnership’s 2016 fiscal year); If and only if at the conclusion of the Partnership’s 2016 fiscal year, participants in the Partnership’s Annual Cash Bonus Plan qualify under the terms of that plan for a cash payment with respect to that fiscal year, then the Partnership will make a cash payment to Mr. Wienberg in the full, non-pro-rated amount (less applicable withholdings) that he would have been entitled to had he remained employed with the Partnership at the end of that fiscal year (no payment was due to Mr. Wienberg under this provision); If and only if there is a change of control of the Partnership within the six-month period immediately following May 25, 2016, then the 7,311 restricted units otherwise forfeited by Mr. Wienberg under the Partnership’s RUP will immediately vest and be deemeddelivered to exist whereMr. Wienberg, pursuant to the individual has been convictedprovisions of the plan (no such change of control occurred during that six-month period); The Partnership will continue to pay, under COBRA, applicable premiums for health insurance benefits for Mr. Wienberg for 18 months following May 25, 2016, or until Mr. Wienberg earlier obtains health insurance benefits under another plan; The Partnership will pay for executive outplacement services for Mr. Wienberg (value: $20,000); The Partnership transferred to Mr. Wienberg his company car (value: $37,000); and At Mr. Wienberg’s request, the Partnership’s operating subsidiary entered into 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 requiredcontract with Mr. Wienberg allowing him to relocate.purchase propane at a discounted price (the value thereof cannot be calculated). Change of Control Our executive officers and other key employees have built the Partnership 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 both 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 employmentseverance protection following a change of control, which we refer to as the “Severance Protection Plan”.Plan.” During fiscal 2014,2016, our Severance Protection Plan covered all of our executive officers, including theour named executive officers. 63
The Severance Protection Plan provides for severance payments of either 65 or 78 weeks of base salary and target cash bonuses for such officers and key employees if within one year following a change of control their employment is terminated by us or our successor or they resign for Good Reason (as defined in the Severance Protection Plan). All of our named executive officers who participate in the Severance Protection Plan are eligible for 78 weeks of base salary and target bonuses. The cash components of any change of control benefits are paid in a lump sum. 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. 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. Under the provisions of the LTIP document operative at the conclusion of fiscal 2016, an amount equal to the cash 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 cumulative, per-Common Unit distribution from the beginning of an unvested award’s three-year measurement period through the date on which a change of control occurred, would become payable to the participants. As a result of an amendment approved at the November 14, 2016 Compensation Committee meeting, this percentage was changed to 150%. For purposes of these benefits, a change of control is deemed to occur, in general, if: An acquisition of our Common Units or voting equity interests by any person immediately after which such person beneficially owns more than 30% of the combined voting power of our then outstanding Common Units, unless such acquisition was made by (a) us or our subsidiaries, or any employee benefit plan maintained by us, the Operating Partnership or any of our subsidiaries, or (b) any person in a transaction where (A) the existing holders prior to the transaction own at least 50% of the voting power of the entity surviving the transaction and (B) none of the Unitholders other than the Partnership, our subsidiaries, any employee benefit plan maintained by us, the Operating Partnership, or the surviving entity, or the existing beneficial owner of more than 25% of the outstanding Common Units owns more than 25% of the combined voting power of the surviving entity, which transaction we refer to as a “Non-Control Transaction”; or or The consummation of (a) a merger, consolidation or reorganization involving the Partnership other than a Non-Control Transaction; (b) a complete liquidation or dissolution of the Partnership; or (c) the sale or other disposition of 40% or more of the gross fair market value of all the assets of the Partnership to any person (other than a transfer to a subsidiary). 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. Additional Information 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 our practice to comply with the statutory and regulatory provisions of IRC Section 409A, the Suburban Propane, L.P. Severance Protection Plan for Key Employees, which we refer to as the “Severance Protection Plan,” provides that if any payment under the Severance Protection Plan subjects a participant to the 20% additional 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 additional tax not been payable. 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 2014.2016. 64
The Compensation Committee: John Hoyt Stookey, Chairman
Matthew J. Chanin, Chair Harold R. Logan, Jr. John Hoyt Stookey ADDITIONAL INFORMATION REGARDING EXECUTIVE COMPENSATION Summary Compensation Table The following table sets forth certain information concerning the compensation of each named executive officer during the fiscal years ended September 27, 2014,24, 2016, September 28, 201326, 2015 and September 29, 2012:27, 2014: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Name and Principal Position | | Year | | | Salary
($)(1) | | | Bonus
($)(2) | | | Unit Awards
($)(3) | | | Non-Equity
Incentive Plan
Compensation
($)(4) | | | Change in
Pension Value
and
Nonqualified
Deferred
Compensation
Earnings
($)(5) | | | All Other
Compensation
($)(6) | | | Total
($) | | | (a) | | (b) | | | (c ) | | | (d) | | | (e) | | | (g) | | | (h) | | | (i) | | | (j) | | Michael J. Dunn, Jr. Former Chief Executive Officer (Retired at the Conclusion of Fiscal 2014) | | | 2014 | | | $ | 495,000 | | | | — | | | $ | 981,921 | | | $ | 336,600 | | | $ | 9,102 | | | $ | 48,352 | | | $ | 1,870,975 | | | | | 2013 | | | $ | 495,000 | | | | — | | | $ | 369,124 | | | $ | 297,000 | | | | — | | | $ | 54,619 | | | $ | 1,215,743 | | | | | 2012 | | | $ | 475,000 | | | | — | | | $ | 521,058 | | | | — | | | $ | 22,308 | | | $ | 49,280 | | | $ | 1,067,646 | | Michael A. Stivala President and Chief Executive Officer | | | 2014 | | | $ | 362,500 | | | | — | | | $ | 1,182,776 | | | $ | 226,100 | | | | — | | | $ | 40,906 | | | $ | 1,812,282 | | | | | 2013 | | | $ | 300,000 | | | | — | | | $ | 376,313 | | | $ | 144,000 | | | | — | | | $ | 42,073 | | | $ | 862,386 | | | | | 2012 | | | $ | 275,000 | | | | — | | | $ | 328,487 | | | | — | | | | — | | | $ | 36,557 | | | $ | 640,044 | | Michael A. Kuglin Chief Financial Officer and Chief Accounting Officer | | | 2014 | | | $ | 252,500 | | | | — | | | $ | 675,618 | | | $ | 116,110 | | | | — | | | $ | 33,430 | | | $ | 1,077,658 | | | | | 2013 | | | $ | 240,000 | | | | — | | | $ | 257,297 | | | $ | 93,600 | | | | — | | | $ | 35,161 | | | $ | 626,058 | | | | | 2012 | | | $ | 215,000 | | | | — | | | $ | 215,211 | | | | — | | | | — | | | $ | 28,715 | | | $ | 458,926 | | Mark Wienberg Chief Operating Officer | | | 2014 | | | $ | 302,500 | | | | — | | | $ | 758,784 | | | $ | 164,560 | | | | — | | | $ | 37,800 | | | $ | 1,263,644 | | | | | 2013 | | | $ | 280,000 | | | | — | | | $ | 364,382 | | | $ | 134,400 | | | | — | | | $ | 36,055 | | | $ | 814,837 | | | | | 2012 | | | $ | 250,000 | | | | — | | | $ | 317,553 | | | | — | | | | — | | | $ | 32,854 | | | $ | 600,407 | | Steven C. Boyd Senior Vice President—Field Operations | | | 2014 | | | $ | 302,500 | | | | — | | | $ | 763,708 | | | $ | 164,560 | | | $ | 28,917 | | | $ | 35,341 | | | $ | 1,295,026 | | | | | 2013 | | | $ | 290,000 | | | | — | | | $ | 370,348 | | | $ | 139,200 | | | | — | | | $ | 33,416 | | | $ | 832,964 | | | | | 2012 | | | $ | 270,000 | | | | — | | | $ | 326,310 | | | | — | | | $ | 41,823 | | | $ | 32,763 | | | $ | 670,896 | | Douglas T. Brinkworth Senior Vice President—Product Supply, Purchasing & Logistics | | | 2014 | | | $ | 285,000 | | | | — | | | $ | 753,870 | | | $ | 155,040 | | | $ | 16,037 | | | $ | 41,416 | | | $ | 1,251,363 | | | | | 2013 | | | $ | 270,000 | | | | — | | | $ | 358,418 | | | $ | 129,600 | | | | — | | | $ | 40,772 | | | $ | 798,790 | | | | | 2012 | | | $ | 245,000 | | | | — | | | $ | 315,326 | | | | — | | | $ | 24,327 | | | $ | 35,786 | | | $ | 620,439 | |
Name | | Year | | Salary (1) | | | Bonus (2) | | | Unit Awards (3) | | | Non-Equity Incentive Plan Compensation (4) | | | Change in Pension Value and Nonqualified Deferred Compensation Earnings (5) | | | All Other Compensation (6) | | | Total | | (a) | | (b) | | (c) | | | (d) | | | (e) | | | (g) | | | (h) | | | (i) | | | (j) | | Michael A. Stivala | | 2016 | | $ | 500,000 | | | $ | — | | | $ | 756,967 | | | $ | — | | | $ | — | | | $ | 45,917 | | | $ | 1,302,884 | | President and Chief Executive | | 2015 | | $ | 425,000 | | | $ | — | | | $ | 263,241 | | | $ | 382,500 | | | $ | — | | | $ | 43,527 | | | $ | 1,114,268 | | Officer | | 2014 | | $ | 362,500 | | | $ | — | | | $ | 1,182,776 | | | $ | 226,100 | | | $ | — | | | $ | 41,381 | | | $ | 1,812,757 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Michael A. Kuglin | | 2016 | | $ | 310,000 | | | $ | — | | | $ | 368,556 | | | $ | — | | | $ | — | | | $ | 40,282 | | | $ | 718,838 | | Chief Financial Officer and | | 2015 | | $ | 275,000 | | | $ | — | | | $ | 127,751 | | | $ | 185,625 | | | $ | — | | | $ | 36,841 | | | $ | 625,217 | | Chief Accounting Officer | | 2014 | | $ | 252,500 | | | $ | — | | | $ | 675,618 | | | $ | 116,100 | | | $ | — | | | $ | 33,430 | | | $ | 1,077,648 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Steven C. Boyd | | 2016 | | $ | 330,000 | | | $ | — | | | $ | 378,974 | | | $ | — | | | $ | 39,339 | | | $ | 38,471 | | | $ | 786,784 | | Senior Vice President - | | 2015 | | $ | 315,000 | | | $ | — | | | $ | 156,083 | | | $ | 226,800 | | | $ | 5,787 | | | $ | 36,437 | | | $ | 740,107 | | Operations | | 2014 | | $ | 302,500 | | | $ | — | | | $ | 763,708 | | | $ | 164,560 | | | $ | 28,917 | | | $ | 35,816 | | | $ | 1,295,501 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Douglas T. Brinkworth | | 2016 | | $ | 310,000 | | | $ | — | | | $ | 368,556 | | | $ | — | | | $ | 22,394 | | | $ | 43,349 | | | $ | 744,299 | | Senior Vice President - | | 2015 | | $ | 300,000 | | | $ | — | | | $ | 148,622 | | | $ | 216,000 | | | $ | 3,643 | | | $ | 42,215 | | | $ | 710,480 | | Product Supply, Purchasing and Logistics | | 2014 | | $ | 285,000 | | | $ | — | | | $ | 753,870 | | | $ | 155,040 | | | $ | 16,037 | | | $ | 41,791 | | | $ | 1,251,738 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Paul Abel | | 2016 | | $ | 300,000 | | | $ | — | | | $ | 353,584 | | | $ | — | | | $ | — | | | $ | 31,934 | | | $ | 685,518 | | Senior Vice President, General | | 2015 | | $ | 290,000 | | | $ | — | | | $ | 134,684 | | | $ | 195,750 | | | $ | — | | | $ | 29,518 | | | $ | 649,952 | | Counsel and Secretary | | 2014 | | $ | 273,334 | | | $ | — | | | $ | 735,124 | | | $ | 137,020 | | | $ | — | | | $ | 27,780 | | | $ | 1,173,258 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Mark Wienberg | | 2016 | | $ | 223,333 | | | $ | — | | | $ | 381,581 | | | $ | — | | | $ | — | | | $ | 196,773 | | | $ | 801,687 | | Former Chief Development | | 2015 | | $ | 325,000 | | | $ | — | | | $ | 161,040 | | | $ | 234,000 | | | $ | — | | | $ | 42,201 | | | $ | 762,241 | | Officer | | 2014 | | $ | 302,500 | | | $ | — | | | $ | 758,784 | | | $ | 164,560 | | | $ | — | | | $ | 38,275 | | | $ | 1,264,119 | |
(1) | Includes amounts deferred by named executive officers as contributions to the 401(k) Plan. For more information on the relationship between salaries and other cash compensation (i.e., annual cash bonuses and Long-Term Incentive PlanLTIP awards), refer to the subheading titled “Allocation Among Components”“Components of Compensation” in the “Compensation Discussion and Analysis” above. |
(2) | This column is reserved for discretionary cash bonuses that are not based on any performance criteria. During fiscal years 2014, 2013,2016, 2015 and 2012,2014, we did not provide our named executive officers with non-performance related bonus payments. |
65
(3) | The amounts reported in this column represent the aggregate grant date fair value of RUP awards made during fiscal years 2014, 20132016, 2015 and 2012,2014, as well as the value at the grant date of awards made in fiscal years 2014, 2013,2016, 2015, and 20122014 under the LTIP, based on the probabletarget outcome with respect to satisfaction of the performance conditions. The grant date fair value of Mr. Wienberg’s 2016 RUP award includes 2,669 of the 7,311 unvested restricted units that were forfeited by him on his departure date. Additionally, the grant date fair value of Mr. Wienberg’s 2014 awards includes 1,748 unvested restricted units that were forfeited by him on his departure date. The specific details regarding these plans are provided in the preceding “Compensation Discussion and Analysis” under the subheadings “Restricted Unit Plan” and “Long-Term Incentive Plan.” The breakdown for each plan with respect to each named executive officer is as follows: |
| Plan Name | | Mr. Dunn | | | Mr. Stivala | | | Mr. Kuglin | | | Mr. Wienberg | | | Mr. Boyd | | | Mr. Brinkworth | | | Mr. Stivala | | | Mr. Kuglin | | | Mr. Boyd | | | Mr. Brinkworth | | | Mr. Abel | | | Mr. Wienberg | | 2016 | | | | | | | | | | | | | | | | | | | | | | | | | | RUP | | | $ | 431,405 | | | $ | 207,079 | | | $ | 207,079 | | | $ | 207,079 | | | $ | 207,079 | | | $ | 207,079 | | LTIP | | | | 325,562 | | | | 161,477 | | | | 171,895 | | | | 161,477 | | | | 146,505 | | | | 174,502 | | Total | | | $ | 756,967 | | | $ | 368,556 | | | $ | 378,974 | | | $ | 368,556 | | | $ | 353,584 | | | $ | 381,581 | | 2015 | | | | | | | | | | | | | | | | | | | | | | | | | | RUP | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | LTIP | | | | 263,241 | | | | 127,751 | | | | 156,083 | | | | 148,622 | | | | 134,684 | | | | 161,040 | | Total | | | $ | 263,241 | | | $ | 127,751 | | | $ | 156,083 | | | $ | 148,622 | | | $ | 134,684 | | | $ | 161,040 | | 2014 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | RUP | | $ | 677,679 | | | $ | 1,035,266 | | | $ | 579,736 | | | $ | 621,111 | | | $ | 621,111 | | | $ | 621,111 | | | $ | 1,035,266 | | | $ | 579,736 | | | $ | 621,111 | | | $ | 621,111 | | | $ | 621,111 | | | $ | 621,111 | | LTIP | | | 304,242 | | | | 147,510 | | | | 95,882 | | | | 137,673 | | | | 142,597 | | | | 132,759 | | | | 147,510 | | | | 95,882 | | | | 142,597 | | | | 132,759 | | | | 114,013 | | | | 137,673 | | Total | | $ | 981,921 | | | $ | 1,182,776 | | | $ | 675,618 | | | $ | 758,784 | | | $ | 763,708 | | | $ | 753,870 | | | $ | 1,182,776 | | | $ | 675,618 | | | $ | 763,708 | | | $ | 753,870 | | | $ | 735,124 | | | $ | 758,784 | | | 2013 | | | | | | | | | | | | | | RUP | | | N/A | | | $ | 197,351 | | | $ | 140,971 | | | $ | 197,351 | | | $ | 197,351 | | | $ | 197,351 | | | LTIP | | | 369,124 | | | | 178,962 | | | | 116,326 | | | | 167,031 | | | | 172,997 | | | | 161,067 | | | Total | | $ | 369,124 | | | $ | 376,313 | | | $ | 257,297 | | | $ | 364,382 | | | $ | 370,348 | | | $ | 358,418 | | | | 2012 | | | | | | | | | | | | | | RUP | | $ | 260,900 | | | $ | 208,007 | | | $ | 138,668 | | | $ | 208,007 | | | $ | 208,007 | | | $ | 208,007 | | | LTIP | | | 260,158 | | | | 120,480 | | | | 76,543 | | | | 109,546 | | | | 118,303 | | | | 107,319 | | | Total | | $ | 521,058 | | | $ | 328,487 | | | $ | 215,211 | | | $ | 317,553 | | | $ | 326,310 | | | $ | 315,326 | | |
(4) | The amounts reported in this column represent each named executive officer’sofficer'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.” |
(5) | Nothing was reported in this column for fiscal 2013 because there was a decline in value of the participating named executive officers’ Cash Balance Plan holdings. The declines in pension values for fiscal 2013 were as follows: ($24,140), ($28,591), and ($14,743) for Messrs. Dunn, Boyd, and Brinkworth, respectively. Mr. Stivala, Mr. Kuglin, Mr. Abel and Mr. Wienberg do not participate in the Cash Balance Plan. |
(6) | The amounts reported in this column consist of the following: |
| | | | 2014 | | | Fiscal 2016 | | Fiscal 2016 | | Type of Compensation | | Mr. Dunn | | | Mr. Stivala | | | Mr. Kuglin | | | Mr. Wienberg | | | Mr. Boyd | | | Mr. Brinkworth | | | Mr. Stivala | | | Mr. Kuglin | | | Mr. Boyd | | | Mr. Brinkworth | | | Mr. Abel | | | Mr. Wienberg | | 401(k) Match | | $ | 3,900 | | | $ | 3,900 | | | $ | 3,788 | | | $ | 3,900 | | | $ | 3,900 | | | $ | 3,900 | | | $ | 4,500 | | | $ | 4,500 | | | $ | 4,500 | | | $ | 4,500 | | | $ | 4,500 | | | $ | — | | Value of Annual Physical Examination | | | 1,600 | | | | N/A | | | | N/A | | | | 1,750 | | | | N/A | | | | 1,500 | | | | 2,950 | | | | 2,950 | | | | — | | | | 1,600 | | | | 1,600 | | | | 2,950 | | Value of Partnership Provided Vehicle | | | 16,549 | | | | 18,153 | | | | 12,725 | | | | 13,142 | | | | 6,837 | | | | 11,410 | | | Value of Partnership Provided Vehicles | | | | 15,234 | | | | 12,046 | | | | 7,609 | | | | 11,157 | | | | 15,640 | | | | 11,072 | | Tax Preparation Services | | | 9,150 | | | | N/A | | | | N/A | | | | N/A | | | | 4,450 | | | | 4,400 | | | | — | | | | — | | | | 3,500 | | | | 3,500 | | | | — | | | | — | | Cash Balance Plan Administrative Fees | | | 1,500 | | | | N/A | | | | N/A | | | | N/A | | | | 1,500 | | | | 1,500 | | | | — | | | | — | | | | 1,500 | | | | 1,500 | | | | — | | | | — | | Severance Paid | | | | — | | | | — | | | | — | | | | — | | | | — | | | | 111,667 | | Post-severance Outplacement Services | | | | — | | | | — | | | | — | | | | — | | | | — | | | | 20,000 | | Title to Vehicle per Severance Agreement | | | | — | | | | — | | | | — | | | | — | | | | — | | | | 37,800 | | Insurance Premiums | | | 15,653 | | | | 18,853 | | | | 16,917 | | | | 19,008 | | | | 18,654 | | | | 18,706 | | | | 23,233 | | | | 20,786 | | | | 21,362 | | | | 21,092 | | | | 10,194 | | | | 13,284 | | Totals | | $ | 48,352 | | | $ | 40,906 | | | $ | 33,430 | | | $ | 37,800 | | | $ | 35,341 | | | $ | 41,416 | | | Total | | | $ | 45,917 | | | $ | 40,282 | | | $ | 38,471 | | | $ | 43,349 | | | $ | 31,934 | | | $ | 196,773 | |
| | | | 2013 | | | Fiscal 2015 | | Fiscal 2015 | | Type of Compensation | | Mr. Dunn | | | Mr. Stivala | | | Mr. Kuglin | | | Mr. Wienberg | | | Mr. Boyd | | | Mr. Brinkworth | | | Mr. Stivala | | | Mr. Kuglin | | | Mr. Boyd | | | Mr. Brinkworth | | | Mr. Abel | | | Mr. Wienberg | | 401(k) Match | | $ | 3,825 | | | $ | 3,825 | | | $ | 3,600 | | | $ | 3,825 | | | $ | 3,825 | | | $ | 3,825 | | | $ | 4,500 | | | $ | 4,125 | | | $ | 4,500 | | | $ | 4,500 | | | $ | 4,350 | | | $ | 4,500 | | Value of Annual Physical Examination | | | 1,750 | | | | 1,750 | | | | 1,750 | | | | 1,500 | | | | N/A | | | | 1,750 | | | | 1,600 | | | | 1,600 | | | | — | | | | 1,600 | | | | 1,600 | | | | 1,600 | | Value of Partnership Provided Vehicle | | | 18,897 | | | | 19,319 | | | | 12,882 | | | | 13,570 | | | | 7,705 | | | | 11,521 | | | Value of Partnership Provided Vehicles | | | | 17,516 | | | | 13,033 | | | | 8,004 | | | | 11,305 | | | | 14,504 | | | | 16,986 | | Tax Preparation Services | | | 8,950 | | | | N/A | | | | N/A | | | | N/A | | | | 2,650 | | | | 4,050 | | | | — | | | | — | | | | 3,500 | | | | 4,500 | | | | — | | | | — | | Cash Balance Plan Administrative Fees | | | 1,500 | | | | N/A | | | | N/A | | | | N/A | | | | 1,500 | | | | 1,500 | | | | — | | | | — | | | | 1,500 | | | | 1,500 | | | | — | | | | — | | Insurance Premiums | | | 19,697 | | | | 17,179 | | | | 16,929 | | | | 17,160 | | | | 17,736 | | | | 18,126 | | | | 19,911 | | | | 18,083 | | | | 18,933 | | | | 18,810 | | | | 9,064 | | | | 19,115 | | Totals | | $ | 54,619 | | | $ | 42,073 | | | $ | 35,161 | | | $ | 36,055 | | | $ | 33,416 | | | $ | 40,772 | | | Total | | | $ | 43,527 | | | $ | 36,841 | | | $ | 36,437 | | | $ | 42,215 | | | $ | 29,518 | | | $ | 42,201 | |
| | | | 2012 | | | Fiscal 2014 | | Fiscal 2014 | | Type of Compensation | | Mr. Dunn | | | Mr. Stivala | | | Mr. Kuglin | | | Mr. Wienberg | | | Mr. Boyd | | | Mr. Brinkworth | | | Mr. Stivala | | | Mr. Kuglin | | | Mr. Boyd | | | Mr. Brinkworth | | | Mr. Abel | | | Mr. Wienberg | | 401(k) Match | | $ | 3,000 | | | $ | 3,000 | | | $ | 2,580 | | | $ | 3,000 | | | $ | 3,000 | | | $ | 2,940 | | | $ | 4,375 | | | $ | 3,788 | | | $ | 4,375 | | | $ | 4,275 | | | $ | 4,100 | | | $ | 4,375 | | Value of Annual Physical Examination | | | N/A | | | | 1,500 | | | | N/A | | | | 1,500 | | | | N/A | | | | N/A | | | | — | | | | — | | | | — | | | | 1,500 | | | | — | | | | 1,750 | | Value of Partnership Provided Vehicle | | | 17,047 | | | | 15,480 | | | | 9,810 | | | | 11,676 | | | | 7,743 | | | | 10,677 | | | Value of Partnership Provided Vehicles | | | | 18,153 | | | | 12,725 | | | | 6,837 | | | | 11,410 | | | | 15,061 | | | | 13,142 | | Tax Preparation Services | | | 8,400 | | | | N/A | | | | N/A | | | | N/A | | | | 3,150 | | | | 4,050 | | | | — | | | | — | | | | 4,450 | | | | 4,400 | | | | — | | | | — | | Cash Balance Plan Administrative Fees | | | 1,500 | | | | N/A | | | | N/A | | | | N/A | | | | 1,500 | | | | 1,500 | | | | — | | | | — | | | | 1,500 | | | | 1,500 | | | | — | | | | — | | Insurance Premiums | | | 19,333 | | | | 16,577 | | | | 16,325 | | | | 16,678 | | | | 17,370 | | | | 16,619 | | | | 18,853 | | | | 16,917 | | | | 18,654 | | | | 18,706 | | | | 8,619 | | | | 19,008 | | Totals | | $ | 49,280 | | | $ | 36,557 | | | $ | 28,715 | | | $ | 32,854 | | | $ | 32,763 | | | $ | 35,786 | | | Total | | | $ | 41,381 | | | $ | 33,430 | | | $ | 35,816 | | | $ | 41,791 | | | $ | 27,780 | | | $ | 38,275 | |
Note: Column (f) was omitted from the Summary Compensation Table because we do not grant options to our employees. 66
Grants of Plan Based Awards Table for Fiscal 20142016 The following table sets forth certain information concerning grants of awards made to each named executive officer during the fiscal year ended September 27, 2014:24, 2016: | | | | | | | | | | | | Estimated Future
Payments Under Non-
Equity Incentive Plan
Awards | | | Estimated Future
Payments Under
Equity Incentive Plan
Awards | | | | | | | | | Plan | | Grant | | Approval | | LTIP Units Underlying Equity Incentive Plan Awards | | | Estimated Future Payments Under Non-Equity Incentive Plan Awards | | | Estimated Future Payments Under Equity Incentive Plan Awards | | | All Other stock Awards: Number of Shares of Stock | | | Grant Date Fair Value of Stock and Option | | 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) | | | Name | | Date | | Date | | (LTIP) (4) | | | Target | | | Maximum | | | Target | | | Maximum | | | or Units | | | Awards (5) | | | (a) | | | | (b) | | | | | | (d) | | | (e) | | | (g) | | | (h) | | | (i) | | | (l) | | | | | (b) | | | | | | | | (d) | | | (e) | | | (g) | | | (h) | | | (i) | | | (l) | | Michael J. Dunn, Jr. | | RUP (1) | | 1 Mar 14 | | 22 Jan 14 | | | | | | | | | | | | | 17,009 | | | $ | 677,679 | | | Michael A. Stivala | | | RUP (1) | | 15 Nov 15 | | 10 Nov 15 | | | | | | $ | 500,000 | | | $ | 600,000 | | | | | | | | | | | | 18,277 | | | $ | 431,405 | | | | Bonus (2) | | 29 Sep 13 | | 13 Nov 13 | | | | $ | 495,000 | | | $ | 594,000 | | | | | | | | | | | Bonus (2) | | 27 Sep 15 | | 10 Nov 15 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | LTIP (3) | | 29 Sep 13 | | 13 Nov 13 | | 5,404 | | | | | | $ | 304,242 | | | $ | 456,363 | | | | | | | LTIP (3) | | 27 Sep 15 | | 10 Nov 15 | | | 7,095 | | | | | | | | | | | $ | 325,562 | | | $ | 488,343 | | | | | | | | | | Michael A. Stivala | | RUP (1) | | 15 Nov 13 | | 13 Nov 13 | | | | | | | | | | | | | 5,302 | | | $ | 206,924 | | | | | RUP (1) | | 1 Apr 14 | | 22 Jan 14 | | | | | | | | | | | | | 23,885 | | | $ | 828,342 | | | | | Bonus (2) | | 29 Sep 13 | | 13 Nov 13 | | | | $ | 332,500 | | | $ | 399,000 | | | | | | | | | | | | | LTIP (3) | | 29 Sep 13 | | 13 Nov 13 | | 2,620 | | | | | | $ | 147,510 | | | $ | 221,265 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Michael A. Kuglin | | RUP (1) | | 15 Nov 13 | | 13 Nov 13 | | | | | | | | | | | | | 4,242 | | | $ | 165,549 | | | RUP (1) | | 15 Nov 15 | | 10 Nov 15 | | | | | | | | | | | | | | | | | | | | | | | 8,773 | | | $ | 207,079 | | | | RUP (1) | | 1 Apr 14 | | 22 Jan 14 | | | | | | | | | | | | | 11,943 | | | $ | 414,187 | | | | | Bonus (2) | | 29 Sep 13 | | 13 Nov 13 | | | | $ | 170,750 | | | $ | 204,900 | | | | | | | | | | | | | LTIP (3) | | 29 Sep 13 | | 13 Nov 13 | | 1,703 | | | | | | $ | 95,882 | | | $ | 143,823 | | | | | | | | | | Bonus (2) | | 27 Sep 15 | | 10 Nov 15 | | | | | | $ | 248,000 | | | $ | 297,600 | | | | | | | | | | | | | | | | | | | | | LTIP (3) | | 27 Sep 15 | | 10 Nov 15 | | | 3,519 | | | | | | | | | | | $ | 161,477 | | | $ | 242,216 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Steven C. Boyd | | | RUP (1) | | 15 Nov 15 | | 10 Nov 15 | | | | | | | | | | | | | | | | | | | | | | | 8,773 | | | $ | 207,079 | | | | | Bonus (2) | | 27 Sep 15 | | 10 Nov 15 | | | | | | $ | 264,000 | | | $ | 316,800 | | | | | | | | | | | | | | | | | | | | | LTIP (3) | | 27 Sep 15 | | 10 Nov 15 | | | 3,746 | | | | | | | | | | | $ | 171,895 | | | $ | 257,843 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Douglas T. Brinkworth | | | RUP (1) | | 15 Nov 15 | | 10 Nov 15 | | | | | | | | | | | | | | | | | | | | | | | 8,773 | | | $ | 207,079 | | | | | Bonus (2) | | 27 Sep 15 | | 10 Nov 15 | | | | | | $ | 248,000 | | | $ | 297,600 | | | | | | | | | | | | | | | | | | | | | LTIP (3) | | 27 Sep 15 | | 10 Nov 15 | | | 3,519 | | | | | | | | | | | $ | 161,477 | | | $ | 242,216 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Paul Abel | | | RUP (1) | | 15 Nov 15 | | 10 Nov 15 | | | | | | | | | | | | | | | | | | | | | | | 8,773 | | | $ | 207,079 | | | | | Bonus (2) | | 27 Sep 15 | | 10 Nov 15 | | | | | | $ | 225,000 | | | $ | 270,000 | | | | | | | | | | | | | | | | | | | | | LTIP (3) | | 27 Sep 15 | | 10 Nov 15 | | | 3,193 | | | | | | | | | | | $ | 146,505 | | | $ | 219,758 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Mark Wienberg | | RUP (1) | | 15 Nov 13 | | 13 Nov 13 | | | | | | | | | | | | | 5,302 | | | $ | 206,924 | | | RUP (1) | | 15 Nov 15 | | 10 Nov 15 | | | | | | | | | | | | | | | | | | | | | | | 8,773 | | | $ | 207,079 | | | | RUP (1) | | 1 Apr 14 | | 22 Jan 14 | | | | | | | | | | | | | 11,943 | | | $ | 414,187 | | | | | Bonus (2) | | 29 Sep 13 | | 13 Nov 13 | | | | $ | 242,000 | | | $ | 290,400 | | | | | | | | | | | | | LTIP (3) | | 29 Sep 13 | | 13 Nov 13 | | 2,445 | | | | | | $ | 137,673 | | | $ | 206,510 | | | | | | | Steven C. Boyd | | RUP (1) | | 15 Nov 13 | | 13 Nov 13 | | | | | | | | | | | | | 5,302 | | | $ | 206,924 | | | | | RUP (1) | | 1 Apr 14 | | 22 Jan 14 | | | | | | | | | | | | | 11,943 | | | $ | 414,187 | | | | | Bonus (2) | | 29 Sep 13 | | 13 Nov 13 | | | | $ | 242,000 | | | $ | 290,400 | | | | | | | | | | | | | LTIP (3) | | 29 Sep 13 | | 13 Nov 13 | | 2,533 | | | | | | $ | 142,597 | | | $ | 213,896 | | | | | | | Douglas T. Brinkworth | | RUP (1) | | 15 Nov 13 | | 13 Nov 13 | | | | | | | | | | | | | 5,302 | | | $ | 206,924 | | | | | RUP (1) | | 1 Apr 14 | | 22 Jan 14 | | | | | | | | | | | | | 11,943 | | | $ | 414,187 | | | | | Bonus (2) | | 29 Sep 13 | | 13 Nov 13 | | | | $ | 228,000 | | | $ | 273,600 | | | | | | | | | | | | | LTIP (3) | | 29 Sep 13 | | 13 Nov 13 | | 2,358 | | | | | | $ | 132,759 | | | $ | 199,139 | | | | | | | | | | Bonus (2) | | 27 Sep 15 | | 10 Nov 15 | | | | | | $ | 268,000 | | | $ | 321,600 | | | | | | | | | | | | | | | | | | | | | LTIP (3) | | 27 Sep 15 | | 10 Nov 15 | | | 3,803 | | | | | | | | | | | $ | 174,502 | | | $ | 261,753 | | | | | | | | | |
(1) | The quantitiesquantity reported on these lines represent awardsthis line represents an award granted under the Restricted Unit Plans.RUP. RUP awards granted subsequent to fiscal 2013 vest as follows: one third of the award on the first anniversary of the grant date;date, one third of the award on the second anniversary of the grant date;date, and one third of the award on the third anniversary of the grant date subject(subject in each case to continued service through each such date.date). If a recipient has held an unvested award for at least six months;months, is 55 years or older;older, and has worked for the Partnership for at least ten years, an award held by such participant will vest six months and one day following such participant’s retirement if the participant retires prior to the conclusion of the normal vesting schedule, unless the Committee exercises its authority to alter the applicability of the plan’s retirement provisions in regard to a particular award. On September 27, 2014, Mr. Dunn wasBrinkworth and Mr. Abel are the only named executive officerofficers who, held RUP awards and, at the same time satisfied all threeof this filing, satisfy the retirement eligibility criteria.criteria of the RUP. A discussion of the general terms of the RUP, and the facts and circumstances considered by the Committee in authorizing thethese fiscal 20142016 awards to theour named executive officers, is included in the “Compensation Discussion and Analysis” under the subheading “Restricted Unit Plan.” The quantity and grant date fair value of Mr. Wienberg’s 2016 RUP award includes 2,669 of the 7,311 unvested restricted units that were forfeited by him on his departure date. For a complete discussion of the disposition of Mr. Wienberg’s unvested RUP awards, please refer to the subheading above titled “Severance Benefits.” |
(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 20142016 were equal to 68%0% of the “Target” amounts reported on this line. Column (c) (“Threshold $”) was omitted because the annual cash bonus plan does not provide for a guaranteed minimum cash payment. Because these plan awards were granted to, and 68%0% of the “Target” awards were earned by our named executive officers during fiscal 2014, 68%2016, 0% of the “Target” amounts reported under column (d) have been reported in the Summary Compensation Table above. |
(3) | The LTIP is a phantom unit plan. Payments, if earned, are based on a combination of (1)(i) the fair market value of our Common Units at the end of a three-year measurement period, which, for purposes of the plan,LTIP, is the average of the closing prices for the twenty business days preceding the conclusion of the three-year measurement period, and (2)(ii) 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 20142016 award “Target” and “Maximum” amounts are estimates based upon (1)(i) the fair market value (the average of the closing prices of our Common Units for the twenty business days preceding September 28, 2013)26, 2015) of our Common Units at the beginning of fiscal 2014,2016, and (2)(ii) the estimated distributions over the course of the award’s three-year measurement period.period at the current annualized distribution rate of $3.55 per Common Unit. Column (f) (“Threshold”) was omitted because the LTIP does not provide for a guaranteed minimum cash payment. The “Target” amount represents a hypothetical payment at 100% of target and the “Maximum” amount represents a hypothetical payment at 150% of target. Detailed descriptions of the plan and the calculation of awards are included in the “Compensation Discussion and Analysis” under the subheading “Long-Term Incentive Plan.” |
(4) | This column is frequently used when non-equity incentive plan awards are denominated in units; however, in this case, the numbers reported represent the LTIP phantom units each named executive officer was awarded under the LTIP during fiscal 2014.2016 |
67
(5) | The dollar amounts reported in this column represent the aggregate fair value of the RUP awards on the grant date, net of estimated future distributions during the vesting period. The fair value shown may not be indicative of the value realized in the future upon vesting due tobecause of the variability in the trading price of our Common Units. |
Note: Columns (j) and (k) were omitted from the Grants of Plan Based Awards Table because we do not award options to our employees. Outstanding Equity Awards at Fiscal Year End 20142016 Table The following table sets forth certain information concerning outstanding equity awards under our Restricted Unit PlanRUP and LTIP unit awards under our LTIP for each named executive officer as of September 27, 2014:24, 2016: | | | | | | | | | | | | | | | | | Stock Awards | | Name | | Number of Shares
or Units of Stock
That Have Not
Vested
(#)(7) | | | Market Value
of Shares or
Units of
Stock That
Have Not
Vested
($)(8) | | | Equity Incentive Plan
Awards: Number of
Unearned Shares,
Units or Other
Rights that Have Not
Vested
(#)(9) | | | Equity Incentive Plan
Awards: Market or
Payout Value of
Unearned Shares,
Units or Other
Rights That Have
Not Vested
($)(10) | | | (a) | | (g) | | | (h) | | | (i) | | | (j) | | Michael J. Dunn, Jr. (1) | | | 25,009 | | | $ | 1,107,774 | | | | 11,963 | | | $ | 658,436 | | Michael A. Stivala (2) | | | 50,627 | | | $ | 2,242,523 | | | | 5,800 | | | $ | 319,229 | | Michael A. Kuglin (3) | | | 30,879 | | | $ | 1,367,785 | | | | 3,770 | | | $ | 207,499 | | Mark Wienberg (4) | | | 38,685 | | | $ | 1,713,552 | | | | 5,413 | | | $ | 297,929 | | Steven C. Boyd(5) | | | 38,685 | | | $ | 1,713,552 | | | | 5,607 | | | $ | 308,606 | | Douglas T. Brinkworth (6) | | | 38,865 | | | $ | 1,713,552 | | | | 5,220 | | | $ | 287,305 | |
Stock Awards | | Name | | Number of Shares or Units of Stock That Have Not Vested (7) | | | Market Value of Shares or Units of Stock That Have Not Vested (8) | | | Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights that Have Not Vested (9) | | | Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested (10) | | (a) | | (g) | | | (h) | | | (i) | | | (j) | | Michael A. Stivala (1) | | | 37,516 | | | $ | 1,276,857 | | | | 11,865 | | | $ | 518,660 | | Michael A. Kuglin (2) | | | 20,811 | | | $ | 708,302 | | | | 5,834 | | | $ | 255,025 | | Steven C. Boyd (3) | | | 24,032 | | | $ | 817,929 | | | | 6,574 | | | $ | 287,368 | | Douglas T. Brinkworth (4) | | | 24,032 | | | $ | 817,929 | | | | 6,213 | | | $ | 271,587 | | Paul Abel (5) | | | 21,163 | | | $ | 720,283 | | | | 5,634 | | | $ | 246,277 | | Mark Wienberg (6) | | | 16,721 | | | $ | 569,099 | | | | 6,721 | | | $ | 293,793 | |
(1) | Mr. Dunn’s RUP awards will vest as follows: |
| | | | | Vesting Date
| | Mar 28
2015 | | Quantity of Units
| | | 25,009 | |
(2) | Mr. Stivala’s RUP awards will vest as follows: |
| Vesting Date | | Nov 15
2014 | | | Apr 1
2015 | | | Nov 15
2015 | | | Apr 1
2016 | | | Nov 15
2016 | | | Apr 1
2017 | | | Nov 15
2017 | | | November 15, 2016 | | | April 1, 2017 | | | November 15, 2017 | | | November 15, 2018 | | Quantity of Units | | | 7,275 | | | | 7,962 | | | | 8,189 | | | | 7,962 | | | | 7,062 | | | | 7,961 | | | | 4,216 | | | | 13,155 | | | | 7,961 | | | | 10,309 | | | | 6,091 | |
(3)(2) | Mr. Kuglin’s RUP awards will vest as follows: |
| Vesting Date | | Nov 15
2014 | | | Apr 1
2014 | | | Nov 15
2015 | | | Apr 1
2016 | | | Nov 15
2016 | | | Apr 1
2017 | | | Nov 15
2017 | | | November 15, 2016 | | | April 1, 2017 | | | November 15, 2017 | | | November 15, 2018 | | Quantity of Units | | | 5,084 | | | | 3,981 | | | | 5,795 | | | | 3,981 | | | | 5,046 | | | | 3,981 | | | | 3,011 | | | | 7,971 | | | | 3,981 | | | | 5,936 | | | | 2,923 | |
(4)(3) | Mr. Boyd’s RUP awards will vest as follows: |
Vesting Date | | November 15, 2016 | | | April 1, 2017 | | | November 15, 2017 | | | November 15, 2018 | | Quantity of Units | | | 9,987 | | | | 3,981 | | | | 7,141 | | | | 2,923 | |
(4) | Mr. Brinkworth’s RUP awards will vest as follows: |
Vesting Date | | November 15, 2016 | | | April 1, 2017 | | | November 15, 2017 | | | November 15, 2018 | | Quantity of Units | | | 9,987 | | | | 3,981 | | | | 7,141 | | | | 2,923 | |
(5) | Mr. Abel’s RUP awards will vest as follows: |
Vesting Date | | November 15, 2016 | | | April 1, 2017 | | | November 15, 2017 | | | November 15, 2018 | | Quantity of Units | | | 8,323 | | | | 3,981 | | | | 5,936 | | | | 2,923 | |
(6) | Mr. Wienberg’s RUP awards will vest as follows: |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | Vesting Date | | Nov 15
2014 | | | Apr 1
2015 | | | Nov 15
2015 | | | Apr 1
2016 | | | Nov 15
2016 | | | Apr 1
2017 | | | Nov 15
2017 | | Quantity of Units | | | 7,275 | | | | 3,981 | | | | 8,189 | | | | 3,981 | | | | 7,062 | | | | 3,981 | | | | 4,216 | |
Vesting Date | | November 27, 2016 | | | | | | | | Quantity of Units | | | 16,721 | | | | | | | |
(5)(7) | Mr. Boyd’s RUP awards will vest as follows: |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | Vesting Date | | Nov 15
2014 | | | Apr 1
2015 | | | Nov 15
2015 | | | Apr 1,
2016 | | | Nov 15
2016 | | | Apr 1
2017 | | | Nov 15
2017 | | Quantity of Units | | | 7,275 | | | | 3,981 | | | | 8,189 | | | | 3,981 | | | | 7,062 | | | | 3,981 | | | | 4,216 | |
(6) | Mr. Brinkworth’s RUP awards will vest as follows: |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | Vesting Date | | Nov 15
2014 | | | Apr 1
2015 | | | Nov 15
2015 | | | Apr 1,
2016 | | | Nov 15
2016 | | | Apr 1
2017 | | | Nov 15
2017 | | Quantity of Units | | | 7,275 | | | | 3,981 | | | | 8,189 | | | | 3,981 | | | | 7,062 | | | | 3,981 | | | | 4,216 | |
(7) | The figures reported in this column represent the total quantity of each of our named executive officer’s unvested RUP awards. |
(8) | 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 26, 2014,23, 2016, the last trading day of fiscal 2014.2016. |
(9) | The amounts reported in this column represent the quantities of LTIPphantom units that underlie the outstanding and unvested fiscal 20142016 and fiscal 20132015 awards under the LTIP. Payments, if earned, for the 2013 award, will be made to participants at the end of a three-year measurement period and will be based upon our total return to our Common Unitholders in comparison to the total return provided by a predetermined peer group of eleven other companies, all of which are publicly-traded partnerships, to their unitholders. Payments if earned, for the 2014 award, will be made to participants at the end of a three-year measurement period and will be based upon the Partnership’s distribution coverage ratio for the three-year measurement period. For more information on the LTIP, refer to the subheading “Long-Term Incentive Plan” in the “Compensation Discussion and Analysis.” |
(10) | The amounts reported in this column represent the estimated future target payouts of the fiscal 20142016 and fiscal 20132015 awards granted under the LTIP. These amounts were computed by multiplying the quantities of the unvested LTIPphantom units in column (i) by the average of the closing prices of our Common Units for the twenty business days preceding September 27, 201424, 2016 (in accordance with the plan’sLTIP’s valuation methodology), and by adding to the product of that calculation the product of each year’s underlying LTIPphantom units times the sum of the distributions that are estimated to inure to an outstanding Common Unit during each award’s three-year measurement period. Due toBecause of the variability inof the trading prices of our Common Units, as well as our performance relative to the peer group, actual payments, if any, at the end of the three-year measurement period may differ. The following chart provides a breakdown of each year’s awards: |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | Mr. Dunn | | | Mr. Stivala | | | Mr. Kuglin | | | Mr. Wienberg | | | Mr. Boyd | | | Mr. Brinkworth | | Fiscal 2014 LTIP Units | | | 5,404 | | | | 2,620 | | | | 1,703 | | | | 2,445 | | | | 2,533 | | | | 2,358 | | Value of Fiscal 2014 LTIP Units | | $ | 240,756 | | | $ | 116,725 | | | $ | 75,871 | | | $ | 108,928 | | | $ | 112,849 | | | $ | 105,052 | | Estimated Distributions over Measurement Period | | $ | 56,742 | | | $ | 27,510 | | | $ | 17,882 | | | $ | 25,673 | | | $ | 26,597 | | | $ | 24,759 | | Fiscal 2013 LTIP Units | | | 6,559 | | | | 3,180 | | | | 2,067 | | | | 2,968 | | | | 3,074 | | | | 2,862 | | Value of Fiscal 2013 LTIP Units | | $ | 292,213 | | | $ | 141,674 | | | $ | 92,088 | | | $ | 132,229 | | | $ | 136,951 | | | $ | 127,506 | | Estimated Distributions over Measurement Period | | $ | 68,725 | | | $ | 33,320 | | | $ | 21,658 | | | $ | 31,099 | | | $ | 32,209 | | | $ | 29,988 | |
| | Mr. Stivala | | | Mr. Kuglin | | | Mr. Boyd | | | Mr. Brinkworth | | | Mr. Abel | | | Mr. Wienberg | | Fiscal 2016 Phantom Units | | | 7,095 | | | | 3,519 | | | | 3,746 | | | | 3,519 | | | | 3,193 | | | | 3,803 | | Value of Fiscal 2016 Phantom Units | | $ | 234,656 | | | $ | 116,386 | | | $ | 123,893 | | | $ | 116,386 | | | $ | 105,604 | | | $ | 125,779 | | Estimated Distributions over Measurement Period | | $ | 75,562 | | | $ | 37,477 | | | $ | 39,895 | | | $ | 37,477 | | | $ | 34,005 | | | $ | 40,502 | | | | | | | | | | | | | | | | | | | | | | | | | | | Fiscal 2015 Phantom Units | | | 4,770 | | | | 2,315 | | | | 2,828 | | | | 2,694 | | | | 2,441 | | | | 2,918 | | Value of Fiscal 2015 Phantom Units | | $ | 157,761 | | | $ | 76,565 | | | $ | 93,532 | | | $ | 89,100 | | | $ | 80,732 | | | $ | 96,508 | | Estimated Distributions over Measurement Period | | $ | 50,681 | | | $ | 24,597 | | | $ | 30,048 | | | $ | 28,624 | | | $ | 25,936 | | | $ | 31,004 | |
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 20142016 Table” because we do not grant options to our employees. Equity Vested Table for Fiscal 20142016 Awards under the Restricted Unit PlansRUP are settled in Common Units upon vesting. Awards under the LTIP, a LTIP-equityphantom unit plan, are settled in cash. The following two tables set forth certain information concerning the vesting of awards under our Restricted Unit PlansRUP and the vesting of the fiscal 20122014 award under our LTIP for each named executive officer during the fiscal year ended September 27, 2014:24, 2016: Restricted Unit Plan | | Restricted Unit Plan | | | | | | | | Unit Awards | | Restricted Unit Plans | | Unit Awards | | | Name | | Number of
Common Units
Acquired on
Vesting (#) | | | Value
Realized
on Vesting
($)(1) | | | Number of Common Units Acquired on Vesting | | | Value Realized on Vesting (1) | | Michael J. Dunn, Jr. | | | -0- | | | $ | -0- | | | Michael A. Stivala | | | 5,044 | | | $ | 232,680 | | | | 16,151 | | | $ | 488,208 | | Michael A. Kuglin | | | 4,728 | | | $ | 218,103 | | | | 9,776 | | | $ | 296,131 | | Mark Wienberg | | | 4,242 | | | $ | 195,683 | | | Steven C. Boyd | | | 3,920 | | | $ | 180,830 | | | | 12,170 | | | $ | 369,375 | | Douglas T. Brinkworth | | | 4,242 | | | $ | 195,683 | | | | 12,170 | | | $ | 369,375 | | Paul Abel | | | | 10,355 | | | $ | 313,846 | | Mark Wienberg | | | | 12,170 | | | $ | 369,375 | |
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(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. |
| | | | | | | | | Long-Term Incentive Plan—Fiscal 2012(2) Award | | Cash Awards | | Name | | Number of
LTIP Units
Acquired
on Vesting
(#) (3) | | | Value
Realized on
Vesting
($) (4) | | Michael J. Dunn, Jr. | | | 5,258 | | | $ | 0 | | Michael A. Stivala | | | 2,435 | | | $ | 0 | | Michael A. Kuglin | | | 1,547 | | | $ | 0 | | Mark Wienberg | | | 2,214 | | | $ | 0 | | Steven C. Boyd | | | 2,391 | | | $ | 0 | | Douglas T. Brinkworth | | | 2,169 | | | $ | 0 | |
Long-Term Incentive Plan - Fiscal 2014 Award (2) | | | | Cash Awards | | Name | | Number of Phantom Units Cashed Out on Vesting (3) | | | Value Realized on Vesting (4) | | Michael A. Stivala | | | 2,620 | | | $ | — | | Michael A. Kuglin | | | 1,703 | | | $ | — | | Steven C. Boyd | | | 2,533 | | | $ | — | | Douglas T. Brinkworth | | | 2,358 | | | $ | — | | Paul Abel | | | 2,025 | | | $ | — | | Mark Wienberg | | | 2,445 | | | $ | — | |
(2) | The fiscal 20122014 award’s three-year measurement period concluded on September 27, 2014.24, 2016. |
(3) | In accordance with the formula described in the “Compensation Discussion and Analysis” under the subheading “Long-Term Incentive Plan,” these quantities were calculated at the beginning of the three-year measurement period and were therefore, based upon each individual’s salary and target cash bonus at that time. |
(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 “Long-Term Incentive Plan” in the “Compensation Discussion and Analysis.” |
PensionRetirement Benefits Table for Fiscal 20142016
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 27, 2014:24, 2016: | | | | | | | | | | | | | | | 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 | | | $ | 256,392 | | | $ | — | | | | LTIP(3) | | | N/A | | | $ | 658,436 | | | $ | — | | | | RUP(4) | | | N/A | | | $ | 1,107,774 | | | $ | — | | Michael A. Stivala (2) | | N/A | | | N/A | | | $ | — | | | $ | — | | Michael A. Kuglin (2) | | N/A | | | N/A | | | $ | — | | | $ | — | | Mark Wienberg (2) | | N/A | | | N/A | | | $ | — | | | $ | — | | Steven Boyd | | Cash Balance Plan (1) | | | 15 | | | $ | 198,829 | | | $ | — | | Douglas T. Brinkworth | | Cash Balance Plan (1) | | | 6 | | | $ | 124,541 | | | $ | — | |
Name | | Plan Name | | Number of Years Credited Service | | Present Value of Accumulated Benefit | | | Payments During Last Fiscal Year | | Michael A. Stivala (1) | | N/A | | N/A | | $ | — | | | $ | — | | | | | | | | | | | | | | | Michael A. Kuglin (1) | | N/A | | N/A | | $ | — | | | $ | — | | | | | | | | | | | | | | | Steven C. Boyd | | Cash Balance Plan (2) | | 15 | | $ | 243,955 | | | $ | — | | | | | | | | | | | | | | | Douglas T. Brinkworth | | Cash Balance Plan (2) | | 6 | | $ | 150,578 | | | $ | — | | | | | | | | | | | | | | | Paul Abel (1) | | N/A | | N/A | | $ | — | | | $ | — | | | | LTIP (3) | | N/A | | $ | 246,277 | | | $ | — | | | | RUP (4) | | N/A | | $ | 720,283 | | | $ | — | | | | | | | | | | | | | | | Mark Wienberg (1) | | N/A | | N/A | | $ | — | | | $ | — | |
(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, Mr. Kuglin, Mr. Abel and Mr. Wienberg commenced employment with the Partnership after January 1, 2000, the date on which the Cash Balance Plan was closed to new participants, they do not participate in the Cash Balance Plan. |
(3)(2) | Currently,For more information on the Cash Balance Plan, refer to the subheading “Pension Plan” in the “Compensation Discussion and Analysis.” |
(3) | On September 24, 2016, Mr. Dunn isAbel was the only named executive officer who meetsmet the retirement criteria of the LTIP. For such participants, upon retirement, outstanding but unvested awards under the LTIP become fully vested. However, payouts on thosethese awards are deferred until the conclusion of each outstanding award’s three-year measurement period, based on the outcome of the TRU relative to the peer group for the 2012 award and the outcome of the distributable cash flow measurement for the 2014 award.2016 and 2015 awards. The number reported on this line represents a projected payout of Mr. Dunn’sAbel’s outstanding fiscal 20142016 and fiscal 20132015 awards under the LTIP. Because the ultimate payout, if any, is predicated on the trading prices of the Partnership’s Common Units at the end of the three-year measurement period, the value reported 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. |
(4) | Currently,On September 24, 2016, Mr. Dunn isAbel was the only named executive officer who meetsmet the retirement criteria of the RUP. For more information on this and the retirement provisions, refer to the subheading “Restricted Unit Plans”Plan” in the “Compensation Discussion and Analysis.” For participants who meet the retirement criteria, upon retirement, outstandingall RUP awards vest six months and one day after retirement. |
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Potential Payments Upon Termination 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 27, 201424, 2016 termination date. For more information on Mr. Dunn’s letter agreement,severance and change of control payments, refer to the subheading “Letter Agreementsubheadings “Severance Benefits” and “Change of Mr. Dunn” in the “Compensation Discussion and Analysis.” As was indicated above in the “Compensation Discussion and Analysis,” concurrent with the beginning of fiscal 2015, Mr. Dunn’s retirement became effective; as such, in Mr. Dunn’s case, the numbers reported for him under the column heading “Involuntary Termination Without Cause by the Partnership or by the Executive for Good Reason without a Change of Control Event” reflect actual future payments that will be made to him in accordance with the letter agreement between him and the Partnership.Control” above.
| Executive Payments and Benefits Upon Termination | | Death | | | Disability | | | Involuntary
Termination
Without Cause
by the
Partnership or
by the
Executive for
Good Reason
without a
Change of
Control Event | | | Involuntary
Termination
Without Cause
by the
Partnership or
by the
Executive for
Good Reason
with a Change
of Control
Event | | | Death | | | Disability | | | Involuntary Termination Without Cause by the Partnership or by the Executive for Good Reason without a Change of Control Event | | | Involuntary Termination Without Cause by the Partnership or by the Executive for Good Reason with a Change of Control Event | | | Michael J. Dunn, Jr. | | | | | | | | | | Cash Compensation (1) (2) (3) (4) | | $ | -0- | | | $ | 990,000 | | | $ | 990,000 | | | $ | 1,485,000 | | | Accelerated Vesting of Fiscal 2014, 2013, and 2012 LTIP Awards (5) | | | N/A | | | | N/A | | | | N/A | | | | 1,103,213 | | | Accelerated Vesting of Outstanding RUP Awards (6) | | | 1,107,774 | | | | 1,107,774 | | | | 1,107,774 | | | | 1,107,774 | | | Medical Benefits (3) | | | N/A | | | | N/A | | | | N/A | | | | N/A | | | Total | | $ | 1,107,774 | | | $ | 2,097,774 | | | $ | 2,097,774 | | | $ | 3,695,987 | | | | Michael A. Stivala | | | | | | | | | | | | | | | | | | | | | | | | | Cash Compensation (1) (2) (3) (4) | | $ | -0- | | | $ | -0- | | | $ | 425,000 | | | $ | 1,275,000 | | | $ | — | | | $ | — | | | $ | 500,000 | | | $ | 1,500,000 | | Accelerated Vesting of Fiscal 2014, 2013, and 2012 LTIP Awards (5) | | | N/A | | | | N/A | | | | N/A | | | | 527,025 | | | Accelerated Vesting of Fiscal 2016, 2015 and 2014 LTIP Awards (5) | | | | — | | | | — | | | | — | | | | 706,405 | | Accelerated Vesting of Outstanding RUP Awards (6) | | | 2,242,523 | | | | 949,685 | | | | N/A | | | | 2,242,523 | | | | 1,276,857 | | | | 654,799 | | | | — | | | | 1,276,857 | | Medical Benefits (3) | | | N/A | | | | N/A | | | | 18,853 | | | | N/A | | | | — | | | | — | | | | 23,233 | | | | — | | Total | | $ | 2,242,523 | | | $ | 949,685 | | | $ | 443,853 | | | $ | 4,044,548 | | | $ | 1,276,857 | | | $ | 654,799 | | | $ | 523,233 | | | $ | 3,483,262 | | | | | | | | | | | | | | | | | | | | Michael A. Kuglin | | | | | | | | | | | | | | | | | | | | | | | | | Cash Compensation (1) (2) (3) (4) | | $ | -0- | | | $ | -0- | | | $ | 265,000 | | | $ | 675,750 | | | $ | — | | | $ | — | | | $ | 310,000 | | | $ | 837,000 | | Accelerated Vesting of Fiscal 2014, 2013, and 2012 LTIP Awards (5) | | | N/A | | | | N/A | | | | N/A | | | | 340,110 | | | Accelerated Vesting of Outstanding RUP Awards (6) | | | 1,367,785 | | | | 650,871 | | | | N/A | | | | 1,367,785 | | | Medical Benefits (3) | | | N/A | | | | N/A | | | | 16,917 | | | | N/A | | | Total | | $ | 1,367,785 | | | $ | 650,871 | | | $ | 281,917 | | | $ | 2,383,645 | | | | Mark Wienberg | | | | | | | | | | Cash Compensation (1) (2) (3) (4) | | $ | -0- | | | $ | -0- | | | $ | 325,000 | | | $ | 877,500 | | | Accelerated Vesting of Fiscal 2014, 2013, and 2012 LTIP Awards (5) | | | N/A | | | | N/A | | | | N/A | | | | 487,838 | | | Accelerated Vesting of Fiscal 2016, 2015 and 2014 LTIP Awards (5) | | | | — | | | | — | | | | — | | | | 369,835 | | Accelerated Vesting of Outstanding RUP Awards (6) | | | 1,713,552 | | | | 949,685 | | | | N/A | | | | 1,713,552 | | | | 708,302 | | | | 409,713 | | | | — | | | | 708,302 | | Medical Benefits (3) | | | N/A | | | | N/A | | | | 19,008 | | | | N/A | | | | — | | | | — | | | | 20,786 | | | | — | | Total | | $ | 1,713,552 | | | $ | 949,685 | | | $ | 344,008 | | | $ | 3,078,890 | | | $ | 708,302 | | | $ | 409,713 | | | $ | 330,786 | | | $ | 1,915,137 | | | | | | | | | | | | | | | | | | | | Steven C. Boyd | | | | | | | | | | | | | | | | | | | | | | | | | Cash Compensation (1) (2) (3) (4) | | $ | -0- | | | $ | -0- | | | $ | 315,000 | | | $ | 850,500 | | | $ | — | | | $ | — | | | $ | 330,000 | | | $ | 891,000 | | Accelerated Vesting of Fiscal 2014, 2013, and 2012 LTIP Awards (5) | | | N/A | | | | N/A | | | | N/A | | | | 512,031 | | | Accelerated Vesting of Fiscal 2016, 2015 and 2014 LTIP Awards (5) | | | | — | | | | — | | | | — | | | | 451,213 | | Accelerated Vesting of Outstanding RUP Awards (6) | | | 1,713,552 | | | | 949,685 | | | | N/A | | | | 1,713,552 | | | | 817,929 | | | | 519,340 | | | | — | | | | 817,929 | | Medical Benefits(3) | | | N/A | | | | N/A | | | | 18,654 | | | | N/A | | | | — | | | | — | | | | 21,362 | | | | — | | Total | | $ | 1,713,552 | | | $ | 949,685 | | | $ | 333,654 | | | $ | 3,076,083 | | | $ | 817,929 | | | $ | 519,340 | | | $ | 351,362 | | | $ | 2,160,142 | | | | | | | | | | | | | | | | | | | | Douglas T. Brinkworth | | | | | | | | | | | | | | | | | | | | | | | | | Cash Compensation (1) (2) (3) (4) | | $ | -0- | | | $ | -0- | | | $ | 300,000 | | | $ | 810,000 | | | $ | — | | | $ | — | | | $ | 310,000 | | | $ | 837,000 | | Accelerated Vesting of Fiscal 2014, 2013, and 2012 LTIP Awards (5) | | | N/A | | | | N/A | | | | N/A | | | | 472,775 | | | Accelerated Vesting of Fiscal 2016, 2015 and 2014 LTIP Awards (5) | | | | — | | | | — | | | | — | | | | 424,570 | | Accelerated Vesting of Outstanding RUP Awards (6) | | | 1,713,552 | | | | 949,685 | | | | N/A | | | | 1,713,552 | | | | 817,929 | | | | 519,340 | | | | — | | | | 817,929 | | Medical Benefits (3) | | | N/A | | | | N/A | | | | 18,706 | | | | N/A | | | | — | | | | — | | | | 21,092 | | | | — | | Total | | $ | 1,713,552 | | | $ | 949,685 | | | $ | 318,706 | | | $ | 2,996,327 | | | $ | 817,929 | | | $ | 519,340 | | | $ | 331,092 | | | $ | 2,079,499 | | | | | | | | | | | | | | | | | | | | Paul Abel | | | | | | | | | | | | | | | | | | Cash Compensation (1) (2) (3) (4) | | | $ | — | | | $ | — | | | $ | 300,000 | | | $ | 787,500 | | Accelerated Vesting of Fiscal 2016, 2015 and 2014 LTIP Awards (5) | | | | — | | | | — | | | | — | | | | 378,815 | | Accelerated Vesting of Outstanding RUP Awards (6) | | | | 720,283 | | | | 720,283 | | | | — | | | | 720,283 | | Medical Benefits (3) | | | | — | | | | — | | | | 10,194 | | | | — | | Total | | | $ | 720,283 | | | $ | 720,283 | | | $ | 310,194 | | | $ | 1,886,598 | |
(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. |
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(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 27, 2014, 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 substantially 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 our health insurance plans for one year. The terms of our letter agreement with Mr. Dunn became effective on September 29, 2012; therefore, Mr. Dunn’s severance benefits for a termination of employment without cause or resignation for good reason have been calculated in accordance with this agreement. For more information on Mr. Dunn’s letter agreement, refer to the subheading “Letter Agreement of Mr. Dunn” in the “Compensation Discussion and Analysis.” |
(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 will vest immediately regardless of whether termination immediately follows. If a change of control event occurs, at the pre-fiscal 2014 awardconclusion of fiscal 2016, payments will bewould have been equal to 125% of the cash value of a participant’s unvested LTIPphantom units plus a sum equal to 125% of a participant’s unvested LTIP units multiplied by an amount equal to the cumulative, per-Common Unit distribution from the beginning of an unvested award’s three-year measurement period through the date on which the change of control occurred. The post-fiscal 2013 award payments will be equal to 150% of the cash value of a participant’s unvested LTIP units plus a sum equal to 150% of a participant’s unvested LTIPphantom units multiplied by an amount equal to the cumulative, per-Common Unit distribution from the beginning of an unvested award’s three-year measurement period through the date on which the change of control occurred (beginning in fiscal 2017, this percentage has been changed to 150%). If a change of control event occurred on September 27, 2014,24, 2016, the fiscal 2014,2016, fiscal 2013,2015 and fiscal 20122014 awards would have been subject to this treatment. Although Mr. Wienberg was no longer employed by the Partnership on September 24, 2016, if a change of control occurred on that date, his cash payment under the change of control provisions of the LTIP would have been $453,529. For more information, refer to the subheading “Long-Term Incentive Plan” in the “Compensation Discussion and Analysis.” |
In the event of death, the inability to continue employment due tobecause of 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 us and will be subject to the same risks as awards held by all other participants. (6) | Effective November 13, 2012, the Committee amended the RUP document to provide for the vesting of all unvested awards held by a participant at the time of his or her death. If a recipient of a RUP award becomes permanently disabled, only those awards that have been held for at least one year on the date that the employee’s employment is terminated as a result of his or her permanent disability will immediately vest; all awards held by the recipient for less than one year will be forfeited by the recipient. IfBecause each of our named executive officers received a RUP award during fiscal 2016, if any or all of the fivefollowing four named executive officers had become permanently disabled on September 28, 2013,24, 2016, the following quantities of unvested restricted units would have vested: Dunn, 25,009; Stivala, 21,440;19,239; Kuglin, 14,694; Wienberg, 21,440;12,038; Boyd, 21,440; and15,259; Brinkworth, 21,440.15,259. The following quantities would have been forfeited: Stivala, 29,187;18,277; Kuglin, 16,185; Wienberg, 17,245;8,773; Boyd, 17,245; and8,773; Brinkworth, 17,245.8,773. Because all of Mr. Dunn’sAbel’s unvested awards arewere subject to the plan’s retirement provisions at the conclusion of fiscal 2016, if Mr. Dunn becameAbel had become permanently disabled on the last day of the fiscal year,September 24, 2016, none of his unvested awards would have been forfeited. |
All of Mr. Dunn’s unvested awards are subject to the plan’s retirement provisions.
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. Because all of Mr. Abel’s unvested awards were subject to the retirement provisions on the last day of fiscal 2016, if Mr. Abel had been terminated without cause on September 24, 2016, none of his unvested awards would have been 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. In accordance with the provisions of the RUP document and his severance agreement, if a change of control occurred on September 24, 2016, Mr. Wienberg would have received 7,311 Common Units for the 7,311 restricted units that were forfeited in addition to the 16,721 Common Units provided for under the terms of his severance agreement (total value on September 24, 2016: $817,929).
72
SUPERVISORS’ COMPENSATION The following table sets forth the compensation of the non-employee members of the Board of Supervisors of the Partnership during fiscal 2014.2016. | Supervisor | | Fees Earned
or Paid in
Cash
($) (1) | | | Unit
Awards
($) (2) | | | Total
($) | | | Fees Earned or Paid in Cash (1) | | | Unit Awards (2) | | | Total | | Harold R. Logan, Jr. | | $ | 115,000 | | | | N/A | | | $ | 115,000 | | | $ | 125,000 | | | $ | 258,861 | | | $ | 383,861 | | Lawrence C. Caldwell | | $ | 85,000 | | | | N/A | | | $ | 85,000 | | | $ | 90,000 | | | $ | 207,079 | | | $ | 297,079 | | Matthew J. Chanin | | $ | 85,000 | | | | N/A | | | $ | 85,000 | | | $ | 100,000 | | | $ | 207,079 | | | $ | 307,079 | | John D. Collins | | $ | 85,000 | | | | N/A | | | $ | 85,000 | | | $ | 105,000 | | | $ | 207,079 | | | $ | 312,079 | | Dudley C. Mecum | | $ | 85,000 | | | | N/A | | | $ | 85,000 | | | John Hoyt Stookey | | $ | 85,000 | | | | N/A | | | $ | 85,000 | | | $ | 90,000 | | | $ | 207,079 | | | $ | 297,079 | | Jane Swift | | $ | 85,000 | | | | N/A | | | $ | 85,000 | | | $ | 90,000 | | | $ | 207,079 | | | $ | 297,079 | |
(1) | This includes amounts earned for fiscal 2014,2016, including quarterly retainer installments for the fourth quarter of 20142016 that were paid in November 2014.2016. It does not include amounts paid in fiscal 20142016 for fiscal 20132015 quarterly retainer installments. |
(2) | During fiscal 2014, the Compensation Committee did not make any additional grants ofOn September 24, 2016, Mr. Logan held 15,467 unvested restricted units, to the members of our Board of Supervisors. As of September 27, 2014, Messrs. Logan,Mr. Caldwell and Mr. Chanin each held 13,290 unvested restricted units, and Mr. Collins, Mecum,Mr. Stookey and Ms. Swift each held awards of 7,80013,273 unvested restricted units and Messrs. Caldwell and Chanin each held awards of 6,023 unvested restricted units. |
At its meeting on July 21, 2015, the Compensation Committee approved the following RUP awards with an effective grant date of November 15, 2015: Supervisor | | Grant Quantities | | Mr. Logan | | | 10,967 | | Mr. Caldwell | | | 8,773 | | Mr. Chanin | | | 8,773 | | Mr. Collins | | | 8,773 | | Mr. Stookey | | | 8,773 | | Ms. Swift | | | 8,773 | |
The aggregate grant date fair values of these RUP awards, computed in accordance with accounting principles generally accepted in the United States of America, are reported in the column above titled “Unit Awards.” 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 the Partnership does not provide these forms of compensation to its non-employee supervisors. Fees and Benefit Plans for Non-Employee Supervisors
Annual Cash Retainer Fees. As the Chairman of the Board of Supervisors, Mr. Logan receivedreceives an annual cash retainer of $115,000 in fiscal 2014,$125,000, payable in quarterly installments of $28,750$31,250 each. Each of the other non-employee Supervisors receivedreceives an annual cash retainer of $85,000 in fiscal 2014,$90,000 each, payable in quarterly installments of $21,250$22,500. As Chair of the Compensation Committee, Mr. Chanin receives an additional annual cash retainer of $10,000, payable in quarterly installments of $2,500 each. As Chair of the Audit Committee, Mr. Collins receives an additional annual cash retainer of $15,000, payable in quarterly installments of $3,750 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.Plan. Each non-employee Supervisor participates in the Restricted Unit Plans.RUP. All awards vest in accordance with the provisions of the plan document (see “Compensation Discussion and Analysis” section titled “Restricted Unit Plans”Plan” for a description of the vesting schedule). Upon vesting, all awards are settled by issuing Common Units. As of September 27, 2014 Messrs. Logan, Collins, Mecum, Stookey, and Ms. Swift each held awards of 7,800 unvested restricted units and Messrs. Caldwell and Chanin each held awards of 6,023 unvested restricted units. At its November 11, 2014 meeting, the Compensation Committee established a policy of granting a retiring Supervisor an award of 1,000 restricted units, in recognition of his or her services to the Partnership. Pursuant to this policy, the Compensation Committee granted Mr. Mecum, who has informed the Board that he does not intend to run for re-election at the next Tri-Annual Meeting of the Partnership’s Unitholders (currently scheduled for Spring 2015), an award of 1,000 unvested restricted units. 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 20142016 for each Supervisor. 73
ITEM 12. | SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERSOWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS |
The following table sets forth certain information as of November 24, 201421, 2016 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; (c) each executive officer named in the Summary Compensation Table in Item 11 of this Annual Report; and (d) all members of the Board of Supervisors and executive officers as a group. 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. | | | | | | | | | Name of Beneficial Owner | | Amount and
Nature of
Beneficial
Ownership (1) | | | Percent of
Class (2) | | Neuberger Berman Group LLC (a) | | | 7,080,982 | | | | 11.7 | % | Michael J. Dunn, Jr. (b) | | | 113,888 | | | | * | | Michael A. Stivala (c) | | | 22,319 | | | | * | | Michael A. Kuglin (d) | | | 5,084 | | | | * | | Mark Wienberg (e) | | | 8,275 | | | | * | | Steven C. Boyd (f) | | | 26,001 | | | | * | | Douglas T. Brinkworth (g) | | | 24,093 | | | | * | | John Hoyt Stookey (h) | | | 9,366 | | | | * | | Harold R. Logan, Jr.(h) | | | 10,240 | | | | * | | Jane Swift (h) | | | -0- | | | | * | | John D. Collins (h) | | | 17,246 | | | | * | | Dudley C. Mecum (i) | | | 18,934 | | | | * | | Lawrence C. Caldwell (j) | | | 15,963 | | | | * | | Matthew J. Chanin (k) | | | 5,000 | | | | * | | | | | All Members of the Board of Supervisors and Executive Officers, as a Group (19 persons) (l) | | | 343,032 | | | | * | |
Name of Beneficial Owner | | Amount and Nature of Beneficial Ownership (1) | | | Percent of Class (2) | Michael A. Stivala (a) | | | 52,196 | | | * | Michael A. Kuglin (b) | | | 16,429 | | | * | Steven C. Boyd (c) | | | 45,048 | | | * | Douglas T. Brinkworth (d) | | | 31,512 | | | * | Paul Abel (e) | | | 33,504 | | | * | Mark Wienberg (f) | | | — | | | * | | | | | | | | Harold R. Logan, Jr. (g) | | | 17,463 | | | * | John Hoyt Stookey (h) | | | 17,091 | | | * | Jane Swift (h) | | | 6,225 | | | * | John D. Collins (h) | | | 19,275 | | | * | Lawrence C. Caldwell (i) | | | 32,460 | | | * | Matthew J. Chanin (j) | | | 12,937 | | | * | | | | | | | | All Members of the Board of Supervisors and Executive Officers, as a group (16 persons) (k) | | | 367,558 | | | * |
(1) | With the exception of the 7,080,982 units held by Neuberger Berman Group LLC (of which the Partnership has no knowledge, see note (a) below), the 784 units held by the General Partner (see note (c) below)(a) below and the 10,09216,252 units held by charitable organizations over which Mr. Caldwell has shared investment and voting power (see note (i) below), there is a possibility that any of the above listed units couldmay be held in brokerage accounts where they are pledged as security. |
(2) | Based upon 60,457,78061,041,252 Common Units outstanding on November 24, 2014.21, 2016. |
(a) | Based upon a Schedule 13G/A dated February 12, 2014 filed by Neuberger Berman Group LLC and Neuberger Berman LLC, which indicates that as of December 31, 2013 they had the shared power to vote or direct the vote of 6,774,935 Common Units and the shared power to dispose or direct the disposition of 7,080,982 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) | Excludes 25,009 unvested restricted units, none of which will vest in the 60-day period following November 24, 2014. |
(c) | Includes 784 Common Units held by the General Partner, of which Mr. Stivala is the sole member. Excludes 43,35256,225 unvested restricted units, none of which will vest in the 60-day period following November 24, 2014.21, 2016. |
(d)(b) | Excludes 25,79532,915 unvested restricted units, none of which will vest in the 60-day period following November 24, 2014.21, 2016. |
(e)(c) | Excludes 31,41029,977 unvested restricted units, none of which will vest in the 60-day period following November 24, 2014.21, 2016. |
(f)(d) | Excludes 31,41029,977 unvested restricted units, none of which will vest in the 60-day period following November 24, 2014.21, 2016. |
(g)(e) | Excludes 31,41028,772 unvested restricted units, none of which will vest in the 60-day period following November 24, 2014.21, 2016. |
(h)(f) | Excludes 7,80016,721 unvested restricted units, all of which will vest in the 60-day period following November 21, 2016. |
(g) | Excludes 10,311 unvested restricted units, none of which will vest in the 60-day period following November 24, 2014.21, 2016. |
(i)(h) | Excludes 8,8008,848 unvested restricted units, none of which will vest in the 60-day period following November 24, 2014.21, 2016. |
(j)(i) | Includes 10,09216,252 Common Units held by charitable organizations over which Mr. Caldwell has shared investment and voting power. Excludes 6,0238,859 unvested restricted units, none of which will vest in the 60-day period following November 24, 2014.21, 2016. |
(k)(j) | Excludes 6,0238,859 unvested restricted units, none of which will vest in the 60-day period following November 24, 2014.21, 2016. |
(l)(k) | Inclusive of the unvested restricted units referred to in footnotes (a), (b), (c), (d), (e), (f), (g), (h), (i), and (j) and (k) above, the reported number of units excludes 361,882314,371 unvested restricted units, none of which will vest in the 60-day period following November 24, 2014.21, 2016. |
74
Securities Authorized for Issuance Under the Restricted Unit PlansPlan The following table sets forth certain information, as of September 27, 2014,24, 2016, with respect to the Partnership’s Restricted Unit Plans,Plan, 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. | 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) | | | 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 Plan (excluding securities reflected in column (a)) (c) | | Equity compensation plans approved by security holders (1) | | | 694,927 | (2) | | $ | 32.07 | | | | 417,758 | | | | 654,120 | | (2) | $ 26.74 | | | | 1,173,408 | | Equity compensation plans not approved by security holders | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | | | | | | | | | | Total | | | 694,927 | | | $ | 32.07 | | | | 417,758 | | | | 654,120 | | | $ 26.74 | | | | 1,173,408 | | | | | | | | | | | | |
(1) |  Relates to the Restricted Unit Plans.Plan.
|
(2) | Represents number of restricted units that, as of September 27, 2014,24, 2016, had been granted under the Restricted Unit PlansPlan but had not yet vested. |
75
ITEM 13. | CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE |
Related Person Transactions None. See “Partnership Management” under Item 10 above for a description of the Audit Committee’s role in reviewing, and approving or ratifying, related party transactions. 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. 76
ITEM 14. | PRINCIPAL ACCOUNTINGACCOUNTING FEES AND SERVICES |
The following table sets forth the aggregate fees for services related to fiscal years 20142016 and 20132015 provided by PricewaterhouseCoopers LLP, our independent registered public accounting firm. | | | | Fiscal
2014 | | | Fiscal
2013 | | | Fiscal 2016 | | | Fiscal 2015 | | Audit Fees (a) | | $ | 2,440,000 | | | $ | 2,378,400 | | | $ | 2,308,300 | | | $ | 2,487,000 | | Tax Fees (b) | | | 1,064,200 | | | | 1,399,000 | | | | 971,000 | | | | 1,033,000 | | All Other Fees (c) | | | 1,800 | | | | 1,800 | | | | 1,800 | | | | 1,800 | | | | | | | | | | | | $ | 3,506,000 | | | $ | 3,779,200 | | | | | | | | | | | Total | | | $ | 3,281,100 | | | $ | 3,521,800 | |
(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) | Tax Fees consist of fees for professional services related to tax reporting, tax compliance and transaction services assistance. |
(c) | 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 20142016 and fiscal 2013. PART IV2015.
77
PART IV ITEM 15. | ITEM 15.
| EXHIBITS, FINANCIAL STATEMENT SCHEDULES |
| (a) | The following documents are filed as part of this Annual Report: |
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. See “Index to Exhibits” set forth on page E-1. 78
SIGNATURESSIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. | | | | | | | | | | | | | | | | | | | SUBURBAN PROPANE PARTNERS, L.P. | | | | | | | Date:November 23, 2016 | By: | November 26, 2014 | | | | | | By: | | /s/ MICHAEL A. STIVALA | | | | | | | | | | | Michael A. Stivala | | | | | | | | | | | 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 A. STIVALA | | President, Chief Executive | | November 23, 2016 | | (Michael A. Stivala) | | Officer and Supervisor | | November 26, 2014 | | | (Michael A. Stivala) | | | | By: | | | | By: | | /s/ HAROLD R. LOGAN, JR. | | Chairman and Supervisor | | November 26, 201423, 2016 | | | (Harold R. Logan, Jr.) | | | | | | | | | | | By: | | /s/ JOHN HOYT STOOKEY | | Supervisor | | November 26, 201423, 2016 | | | (John Hoyt Stookey) | | | | | | | | | | | By: | | /s/ DUDLEY C. MECUM | | Supervisor | | November 26, 2014 | | | (Dudley C. Mecum) | | | | | | | By: | | /s/ JOHN D. COLLINS | | Supervisor | | November 26, 201423, 2016 | | | (John D. Collins) | | | | | | | | | | | By: | | /s/ JANE SWIFT | | Supervisor | | November 26, 201423, 2016 | | | (Jane Swift) | | | | | | | | | | | By: | | /s/ LAWRENCE C. CALDWELL | | Supervisor | | November 26, 201423, 2016 | | | (Lawrence C. Caldwell) | | | | | | | | | | | By | | /s/ MATTHEW J. CHANIN | | Supervisor | | November 26, 201423, 2016 | | | (Matthew J. Chanin) | | | | | | | | | | | By: | | /s/ MICHAEL A. KUGLIN | | Chief Financial Officer and | | November 23, 2016 | | (Michael A. Kuglin) | | Chief Accounting Officer | | November 26, 2014 | | | (Michael A. Kuglin) | | | | By: | | | | By: | | /s/ DANIEL S. BLOOMSTEIN | | Controller | | November 26, 201423, 2016 | | | (Daniel S. Bloomstein) | | | | |
INDEX TO EXHIBITS 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
Number | | 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 the Partnership dated May 26, 1999 (Incorporated by reference to Exhibit 3.2 to the Partnership’s Quarterly Report on Form 10-Q filed August 6, 2009). | | | | 3.4 | | Amended and Restated Certificate of Limited Partnership of the Operating Partnership dated May 26, 1999 (Incorporated by reference to Exhibit 3.3 to the Partnership’s Quarterly Report on Form 10-Q filed August 6, 2009). | | | | 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 Corp. and The Bank of New York Mellon, as Trustee, including the form of 7.375% Senior Notes due 2020. (Incorporated by reference to Exhibit 4.1 to the Partnership’s Current Report on Form 8-K filed March 23, 2010). | | | 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 Corp. and The Bank of New York Mellon, as Trustee. (Incorporated by reference to Exhibit 4.2 to the Partnership’s Current Report on Form 8-K filed March 23, 2010). | | | 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 4.3 | | First Supplemental Indenture, dated as of May 23, 2014, 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. (Incorporated by reference to Exhibit 4.1 to the Partnership’s Current Report on Form 8-K filed May 27, 2014). |
| | | | | | 4.6 4.4 | | Indenture, dated as of May 27, 2014, relating to the 5.50 %5.50% Senior Notes due 2024, among Suburban Propane Partners, L.P., Suburban Energy Finance Corp. and The Bank of New York Mellon, as Trustee, including the form of 5.50 %5.50% Senior Notes due 2024. (Incorporated by reference to Exhibit 4.1 to the Partnership’s Current Report on Form 8-K filed May 28, 2014). | | | | 4.7 4.5 | | First Supplemental Indenture, dated as of May 27, 2014, relating to the 5.50 %5.50% Senior Notes due 2024, among Suburban Propane Partners, L.P., Suburban Energy Finance Corp. and The Bank of New York Mellon, as Trustee. (Incorporated by reference to Exhibit 4.1 to the Partnership’s Current Report on Form 8-K filed May 28, 2014). | | | | 4.8 4.6 | | Second Supplemental Indenture, dated as of February 25, 2015, to the Indenture, dated as of May 27, 2014, relating to the 5.75% Senior Notes due 2025, among Suburban Propane Partners, L.P., Suburban Energy Finance Corp. and The Bank of New York Mellon, as Trustee. (Incorporated by reference to Exhibit 4.1 to the Partnership’s Current Report on Form 8-K filed February 25, 2015). | | | | 4.7 | | 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 13, 2012. (Incorporated by reference to Exhibit 99.1 to the Partnership’s Current Report on Form 8-K filed November 14, 2012). | | | 10.3 | | Suburban Propane Partners, L.P. 2009 Restricted Unit Plan, effective August 1, 2009, as amended on November 13, 2012, and August 6, 2013.2013 and May 13, 2015. (Incorporated by reference to Exhibit 99.210.1 to the Partnership’s Current Report on Form 8-K filed August 7, 2013)May 14, 2015). | | | | 10.4 10.2 | | 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 | | |
10.3 | | Suburban Propane, L.P. 20032014 Long Term Incentive Plan, effective October 1, 2013, as amended on October 17, 2006 and as further amended on July 31, 2007, October 31, 2007, January 24, 2008 and January 20, 2009.November 14, 2016. (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 99.199.2 to the Partnership’s Current Report on Form 8-K filed November 10, 2011)16, 2016). | | | | 10.7 10.4 | | 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(effective as of January 1, 1998)2013). (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)(Filed herewith). | | | | 10.9 10.5 | | First Amendment No. 1 to the Retirement Savings and Investment Plan of Suburban Propane (effective January 1, 2002)2015). (Incorporated by reference to Exhibit 10.25(Filed herewith). | | | | 10.6 | | Second Amendment to the Partnership’s Annual Report on Form 10-K for the fiscal year ended September 28, 2002)Retirement Savings and Investment Plan of Suburban Propane (effective January 1, 2016). (Filed herewith). | | | | 10.10 10.7 | | Second 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 January 5, 2012.March 3, 2016. (Incorporated by reference to Exhibit 10.1 to the Partnership’s Current Report on Form 8-K filed on January 6, 2012)March 3, 2016). |
| | | | | | 10.11 10.8 | | First Amendment to the 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 August 1, 2012. (Incorporated by reference to Exhibit 10.1 to the Partnership’s Current Report on Form 8-K filed on August 2, 2012). | | | 10.12 | | Second Amendment to the 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 May 9, 2014. (Incorporated by reference to Exhibit 10.1 to the Partnership’s Current Report on Form 8-K filed on May 12, 2014). | | | 10.13 | | 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., as amended on November 10, 2015. (Incorporated by reference to Exhibit 99.1 to the Partnership’s CurrentAnnual Report on Form 8-K dated May 10, 2010)10-K filed November 25, 2015). | | | | 99.2 | | Five-Year Performance Graph (Filed herewith). | | | | 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 |
INDEX TO FINANCIAL STATEMENTS SUBURBAN PROPANE PARTNERS, L.P. AND SUBSIDIARIES | | | | Page | | | Page | | Report of Independent Registered Public Accounting Firm | | | F-2 | | | | Consolidated Balance Sheets – As of September 27, 201424, 2016 and September 28, 201326, 2015 | | | F-3 | | | | Consolidated Statements of Operations – Years Ended September 27, 2014,24, 2016, September 28, 201326, 2015 and September 29, 201227, 2014 | | | F-4 | | | | Consolidated Statements of Comprehensive Income – Years Ended September 27, 2014,24, 2016, September 28, 201326, 2015 and September 29, 201227, 2014 | | | F-5 | | | | Consolidated Statements of Cash Flows – Years Ended September 27, 2014,24, 2016, September 28, 201326, 2015 and September 29, 201227, 2014 | | | F-6 | | | | Consolidated Statements of Partners’ Capital – Years Ended September 27, 2014,24, 2016, September 28, 201326, 2015 and September 29, 201227, 2014 | | | F-7 | | | | Notes to Consolidated Financial Statements | | | F-8 | |
Report of Independent RegisteredRegistered Public Accounting Firm 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, comprehensive income, partners’ capital, comprehensive income and cash flows present fairly, in all material respects, the financial position of Suburban Propane Partners, L.PL.P. and its subsidiaries at September 27, 201424, 2016 and September 28, 2013,26, 2015, and the results of their operations and their cash flows for each of the three fiscal years in the period ended September 27, 201424, 2016 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 27, 2014,24, 2016, based on criteria established inInternal Control—Control - Integrated Framework (1992)(2013)issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Partnership’sPartnership'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’sManagement's Report on Internal Control over Financial Reporting appearing in Item 9A.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 OversightOversight 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 26, 2014 23, 2016
SUBURBAN PROPANE PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (in thousands) | | | | | | September 24, | | | September 26, | | | | | September 27,
2014 | | September 28,
2013 | | | 2016 | | | 2015 | | ASSETS | | | | | | | | | | | | | Current assets: | | | | | | | | | | | | | Cash and cash equivalents | | $ | 92,639 | | | $ | 107,232 | | | $ | 37,341 | | | $ | 152,338 | | Accounts receivable, less allowance for doubtful accounts of $11,122 and $6,786, respectively | | | 96,915 | | | 94,854 | | | Accounts receivable, less allowance for doubtful accounts of $2,441 and $3,520, respectively | | | | 53,802 | | | | 59,929 | | Inventories | | | 90,965 | | | 77,623 | | | | 45,352 | | | | 47,686 | | Other current assets | | | 14,346 | | | 13,613 | | | | 10,804 | | | | 13,460 | | | | | | | | | | Total current assets | | | 294,865 | | | | 293,322 | | | | 147,299 | | | | 273,413 | | Property, plant and equipment, net | | | 826,826 | | | | 888,232 | | | | 742,129 | | | | 781,058 | | Goodwill | | | 1,087,429 | | | | 1,087,429 | | | | 1,094,635 | | | | 1,087,429 | | Other intangible assets, net | | | 359,293 | | | | 416,771 | | | | 276,329 | | | | 307,789 | | Other assets | | | 40,950 | | | | 42,233 | | | | 35,577 | | | | 36,041 | | | | | | | | | | Total assets | | $ | 2,609,363 | | | $ | 2,727,987 | | | $ | 2,295,969 | | | $ | 2,485,730 | | | | | | | | | | LIABILITIES AND PARTNERS’ CAPITAL | | | | | | LIABILITIES AND PARTNERS' CAPITAL | | | | | | | | | | Current liabilities: | | | | | | | | | | | | | Accounts payable | | $ | 49,253 | | | $ | 52,766 | | | $ | 32,286 | | | $ | 34,922 | | Accrued employment and benefit costs | | | 24,033 | | | | 23,559 | | | | 16,495 | | | | 29,236 | | Accrued insurance | | | 10,040 | | | | 6,650 | | | | 16,270 | | | | 13,430 | | Customer deposits and advances | | | 107,386 | | | | 107,562 | | | | 106,155 | | | | 105,147 | | Accrued interest | | | 16,313 | | | | 24,357 | | | | 16,589 | | | | 16,382 | | Other current liabilities | | | 15,241 | | | | 19,000 | | | | 17,259 | | | | 11,229 | | | | | | | | | | Total current liabilities | | | 222,266 | | | | 233,894 | | | | 205,054 | | | | 210,346 | | Long-term borrowings | | | 1,242,685 | | | | 1,245,237 | | | | 1,238,172 | | | | 1,241,107 | | Accrued insurance | | | 52,410 | | | | 51,502 | | | | 43,406 | | | | 43,653 | | Other liabilities | | | 70,549 | | | | 68,228 | | | | 101,106 | | | | 92,304 | | | | | | | | | | Total liabilities | | | 1,587,910 | | | | 1,598,861 | | | | 1,587,738 | | | | 1,587,410 | | | | | | | | | | Commitments and contingencies | | | | | | | | | | | | | Partners’ capital: | | | | | | Common Unitholders (60,317 and 60,231 units issued and outstanding at September 27, 2014 and September 28, 2013, respectively) | | | 1,067,358 | | | | 1,176,479 | | | Partners' capital: | | | | | | | | | | Common Unitholders (60,789 and 60,531 units issued and outstanding at September 24, 2016 and September 26, 2015, respectively) | | | | 754,063 | | | | 947,203 | | Accumulated other comprehensive loss | | | (45,905 | ) | | | (47,353 | ) | | | (45,832 | ) | | | (48,883 | ) | | | | | | | | | Total partners’ capital | | | 1,021,453 | | | | 1,129,126 | | | | | | | | | | | Total liabilities and partners’ capital | | $ | 2,609,363 | | | $ | 2,727,987 | | | | | | | | | | | Total partners' capital | | | | 708,231 | | | | 898,320 | | Total liabilities and partners' capital | | | $ | 2,295,969 | | | $ | 2,485,730 | |
The accompanying notes are an integral part of these consolidated financial statements.
SUBURBAN PROPANE PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS (in thousands, except per unit amounts) | | | | | | | | Year Ended | | | | | Year Ended | | | September 24, | | | September 26, | | | September 27, | | | | | September 27,
2014 | | September 28,
2013 | | September 29,
2012 | | | 2016 | | | 2015 | | | 2014 | | Revenues | | | | | | | | | | | | | | | | | | | Propane | | $ | 1,606,840 | | | $ | 1,357,102 | | | $ | 843,648 | | | $ | 884,169 | | | $ | 1,176,980 | | | $ | 1,606,840 | | Fuel oil and refined fuels | | | 194,684 | | | 208,957 | | | 114,288 | | | | 68,759 | | | | 127,495 | | | | 194,684 | | Natural gas and electricity | | | 87,093 | | | 79,432 | | | 67,419 | | | | 50,763 | | | | 66,865 | | | | 87,093 | | All other | | | 49,640 | | | 58,115 | | | 38,103 | | | | 42,420 | | | | 45,639 | | | | 49,640 | | | | | | | | | | | | | | 1,046,111 | | | | 1,416,979 | | | | 1,938,257 | | | | | 1,938,257 | | | | 1,703,606 | | | | 1,063,458 | | | Costs and expenses | | | | | | | | | | | | | | | | | | | Cost of products sold | | | 1,080,750 | | | | 861,905 | | | | 599,059 | | | | 361,953 | | | | 593,380 | | | | 1,080,750 | | Operating | | | 466,389 | | | | 469,496 | | | | 298,772 | | | | 412,756 | | | | 444,251 | | | | 466,389 | | General and administrative | | | 64,593 | | | | 64,845 | | | | 59,020 | | | | 61,149 | | | | 68,296 | | | | 64,593 | | Acquisition-related costs | | | — | | | | — | | | | 17,916 | | | Depreciation and amortization | | | 136,399 | | | | 130,384 | | | | 47,034 | | | | 129,616 | | | | 133,294 | | | | 136,399 | | | | | | | | | | | | | | 965,474 | | | | 1,239,221 | | | | 1,748,131 | | | | | 1,748,131 | | | | 1,526,630 | | | | 1,021,801 | | | | | | | | | | | | | | Gain on sale of business | | | | 9,769 | | | | — | | | | — | | Operating income | | | 190,126 | | | | 176,976 | | | | 41,657 | | | | 90,406 | | | | 177,758 | | | | 190,126 | | Loss on debt extinguishment | | | (11,589 | ) | | | (2,144 | ) | | | (2,249 | ) | | | 292 | | | | 15,072 | | | | 11,589 | | Interest expense | | | (83,261 | ) | | | (95,427 | ) | | | (38,633 | ) | | | | | | | | | | | | | Interest expense, net | | | | 75,086 | | | | 77,634 | | | | 83,261 | | Income before provision for income taxes | | | 95,276 | | | | 79,405 | | | | 775 | | | | 15,028 | | | | 85,052 | | | | 95,276 | | Provision for income taxes | | | 767 | | | | 607 | | | | 137 | | | | 588 | | | | 700 | | | | 767 | | | | | | | | | | | | | Net income | | $ | 94,509 | | | $ | 78,798 | | | $ | 638 | | | $ | 14,440 | | | $ | 84,352 | | | $ | 94,509 | | | | | | | | | | | | | | Income per Common Unit - basic | | $ | 1.56 | | | $ | 1.35 | | | $ | 0.02 | | | | | | | | | | | | | | | Net income per Common Unit - basic | | | $ | 0.24 | | | $ | 1.39 | | | $ | 1.56 | | Weighted average number of Common Units outstanding - basic | | | 60,481 | | | | 58,378 | | | | 38,848 | | | | 60,956 | | | | 60,650 | | | | 60,481 | | | | | | | | | | | | | Income per Common Unit - diluted | | $ | 1.56 | | | $ | 1.34 | | | $ | 0.02 | | | | | | | | | | | | | | Net income per Common Unit - diluted | | | $ | 0.24 | | | $ | 1.38 | | | $ | 1.56 | | Weighted average number of Common Units outstanding - diluted | | | 60,751 | | | | 58,600 | | | | 38,990 | | | | 61,176 | | | | 60,907 | | | | 60,751 | | | | | | | | | | | | |
The accompanying notes are an integral part of these consolidated financial statements.
SUBURBAN PROPANE PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (in thousands) | | | | | | | | Year Ended | | | | | Year Ended | | | September 24, | | | September 26, | | | September 27, | | | | | September 27,
2014 | | September 28,
2013 | | | September 29,
2012 | | | 2016 | | | 2015 | | | 2014 | | Net income | | $ | 94,509 | | | $ | 78,798 | | | $ | 638 | | | $ | 14,440 | | | $ | 84,352 | | | $ | 94,509 | | Other comprehensive income: | | | | | | | | | | | | | | | | | | | Net unrealized (losses) gains on cash flow hedges | | | (518 | ) | | 584 | | | | (3,561 | ) | | Net unrealized gains (losses) on cash flow hedges | | | | 6 | | | | (1,159 | ) | | | (518 | ) | Reclassification of realized losses on cash flow hedges into earnings | | | 1,406 | | | 2,465 | | | | 2,680 | | | | 1,100 | | | | 1,388 | | | | 1,406 | | Amortization of net actuarial losses and prior service credits into earnings and net change in funded status of benefit plans | | | 560 | | | 10,705 | | | | (310 | ) | | | (55 | ) | | | (5,207 | ) | | | 560 | | | | | | | | | | | | | Recognition in earnings of net actuarial loss for pension settlement | | | | 2,000 | | | | 2,000 | | | | — | | Other comprehensive income (loss) | | | 1,448 | | | | 13,754 | | | | (1,191 | ) | | | 3,051 | | | | (2,978 | ) | | | 1,448 | | | | | | | | | | | | | Total comprehensive income (loss) | | $ | 95,957 | | | $ | 92,552 | | | $ | (553 | ) | | | | | | | | | | | | | Total comprehensive income | | | $ | 17,491 | | | $ | 81,374 | | | $ | 95,957 | |
The accompanying notes are an integral part of these consolidated financial statements.
SUBURBAN PROPANE PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (in thousands) | | | | | | | | | | | | | | | | Year Ended | | | | | September 27,
2014 | | | September 28,
2013 | | | September 29,
2012 | | Cash flows from operating activities: | | | | | | | | | | | | | Net income | | $ | 94,509 | | | $ | 78,798 | | | $ | 638 | | Adjustments to reconcile net income to net cash provided by operations: | | | | | | | | | | | | | Depreciation and amortization expense | | | 136,399 | | | | 130,384 | | | | 47,034 | | Loss on debt extinguishment | | | 11,589 | | | | 2,144 | | | | 2,249 | | Other, net | | | 5,664 | | | | (2,796 | ) | | | 6,424 | | Changes in assets and liabilities: | | | | | | | | | | | | | (Increase) decrease in accounts receivable | | | (2,061 | ) | | | (5,910 | ) | | | 13,762 | | (Increase) decrease in inventories | | | (13,342 | ) | | | 10,553 | | | | 8,189 | | Increase (decrease) in accounts payable | | | (3,513 | ) | | | (375 | ) | | | 15,669 | | Increase (decrease) in accrued employment and benefit costs | | | 474 | | | | 7,045 | | | | (8,586 | ) | Increase (decrease) in accrued insurance | | | 4,298 | | | | 3,601 | | | | (4,451 | ) | Increase (decrease) in customer deposits and advances | | | (176 | ) | | | (16,735 | ) | | | 18,352 | | (Increase) decrease in other current and noncurrent assets | | | 266 | | | | 5,436 | | | | (754 | ) | Increase (decrease) in other current and noncurrent liabilities | | | (8,556 | ) | | | 2,161 | | | | 12,447 | | | | | | | | | | | | | | | Net cash provided by operating activities | | | 225,551 | | | | 214,306 | | | | 110,973 | | | | | | | | | | | | | | | Cash flows from investing activities: | | | | | | | | | | | | | Capital expenditures | | | (30,052 | ) | | | (27,823 | ) | | | (17,476 | ) | Acquisitions of businesses, net of cash acquired | | | — | | | | — | | | | (223,731 | ) | Proceeds from sale of property, plant and equipment | | | 13,520 | | | | 7,310 | | | | 1,449 | | Adjustment to purchase price for Inergy Propane | | | — | | | | 5,850 | | | | — | | | | | | | | | | | | | | | Net cash (used in) investing activities | | | (16,532 | ) | | | (14,663 | ) | | | (239,758 | ) | | | | | | | | | | | | | | Cash flows from financing activities: | | | | | | | | | | | | | Proceeds from long-term borrowings | | | 525,000 | | | | — | | | | 100,000 | | Repayments of long-term borrowings (includes premium and fees) | | | (528,077 | ) | | | (168,915 | ) | | | (100,000 | ) | Proceeds from borrowings under revolving credit facility | | | 61,700 | | | | — | | | | — | | Repayment of borrowings under revolving credit facility | | | (61,700 | ) | | | — | | | | — | | Proceeds from short-term borrowings | | | — | | | | — | | | | 225,000 | | Repayments of short-term borrowings | | | — | | | | — | | | | (225,000 | ) | Debt issuance costs | | | (9,515 | ) | | | — | | | | (25,199 | ) | Net proceeds from issuance of Common Units | | | — | | | | 143,444 | | | | 259,842 | | Partnership distributions | | | (211,020 | ) | | | (201,257 | ) | | | (121,094 | ) | | | | | | | | | | | | | | Net cash (used in) provided by financing activities | | | (223,612 | ) | | | (226,728 | ) | | | 113,549 | | | | | | | | | | | | | | | Net (decrease) in cash and cash equivalents | | | (14,593 | ) | | | (27,085 | ) | | | (15,236 | ) | Cash and cash equivalents at beginning of year | | | 107,232 | | | | 134,317 | | | | 149,553 | | | | | | | | | | | | | | | Cash and cash equivalents at end of year | | $ | 92,639 | | | $ | 107,232 | | | $ | 134,317 | | | | | | | | | | | | | | | Supplemental disclosure of cash flow information: | | | | | | | | | | | | | Cash paid for interest | | $ | 91,836 | | | $ | 86,583 | | | $ | 38,294 | | 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 | |
| | Year Ended | | | | September 24, | | | September 26, | | | September 27, | | | | 2016 | | | 2015 | | | 2014 | | Cash flows from operating activities: | | | | | | | | | | | | | Net income | | $ | 14,440 | | | $ | 84,352 | | | $ | 94,509 | | Adjustments to reconcile net income to net cash provided by operations: | | | | | | | | | | | | | Depreciation and amortization | | | 129,616 | | | | 133,294 | | | | 136,399 | | Loss on debt extinguishment | | | 292 | | | | 15,072 | | | | 11,589 | | Gain on sale of business | | | (9,769 | ) | | | — | | | | — | | Pension settlement charge | | | 2,000 | | | | 2,000 | | | | — | | Other, net | | | 9,181 | | | | 11,605 | | | | 5,664 | | Changes in assets and liabilities: | | | | | | | | | | | | | Accounts receivable | | | 6,258 | | | | 36,986 | | | | (2,061 | ) | Inventories | | | 2,415 | | | | 43,279 | | | | (13,342 | ) | Other current and noncurrent assets | | | 2,037 | | | | 3,223 | | | | 266 | | Accounts payable | | | (1,885 | ) | | | (14,761 | ) | | | (3,513 | ) | Accrued employment and benefit costs | | | (13,055 | ) | | | 5,203 | | | | 474 | | Accrued insurance | | | 2,593 | | | | (5,367 | ) | | | 4,298 | | Customer deposits and advances | | | 1,163 | | | | (2,239 | ) | | | (176 | ) | Contribution to defined pension benefit plan | | | (715 | ) | | | — | | | | — | | Other current and noncurrent liabilities | | | 12,537 | | | | 11,562 | | | | (8,556 | ) | Net cash provided by operating activities | | | 157,108 | | | | 324,209 | | | | 225,551 | | Cash flows from investing activities: | | | | | | | | | | | | | Capital expenditures | | | (38,375 | ) | | | (41,213 | ) | | | (30,052 | ) | Acquisition of business | | | (42,945 | ) | | | (6,500 | ) | | | — | | Proceeds from sale of property, plant and equipment | | | 5,950 | | | | 11,741 | | | | 13,520 | | Proceeds from sale of business | | | 21,465 | | | | — | | | | — | | Net cash (used in) investing activities | | | (53,905 | ) | | | (35,972 | ) | | | (16,532 | ) | Cash flows from financing activities: | | | | | | | | | | | | | Proceeds from long-term borrowings | | | — | | | | 250,000 | | | | 525,000 | | Repayment of long-term borrowings (includes premium and fees) | | | — | | | | (260,852 | ) | | | (528,077 | ) | Proceeds from borrowings under revolving credit facility | | | 100,000 | | | | — | | | | 61,700 | | Repayment of borrowings under revolving credit facility | | | (100,000 | ) | | | — | | | | (61,700 | ) | Issuance costs associated with long-term borrowings | | | (2,678 | ) | | | (4,568 | ) | | | (9,515 | ) | Partnership distributions | | | (215,522 | ) | | | (213,118 | ) | | | (211,020 | ) | Net cash (used in) financing activities | | | (218,200 | ) | | | (228,538 | ) | | | (223,612 | ) | Net (decrease) increase in cash and cash equivalents | | | (114,997 | ) | | | 59,699 | | | | (14,593 | ) | Cash and cash equivalents at beginning of period | | | 152,338 | | | | 92,639 | | | | 107,232 | | Cash and cash equivalents at end of period | | $ | 37,341 | | | $ | 152,338 | | | $ | 92,639 | | | | | | | | | | | | | | | Supplemental disclosure of cash flow information: | | | | | | | | | | | | | Cash paid for interest | | $ | 74,289 | | | $ | 75,597 | | | $ | 91,836 | |
The accompanying notes are an integral part of these consolidated financial statements.
SUBURBAN PROPANE PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL (in thousands) | | | | | | | | | | | | | | | | | | | | Number
of
Common
Units | | | Common
Unitholders | | | Accumulated
Other
Compre-
hensive
(Loss)
Income | | | Total
Partners’
Capital | | 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 | | | | | | | | | | | | | | | | | | | 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 | | | | | | | | | | | | | | | | | | | Balance at September 28, 2013 | | | 60,231 | | | $ | 1,176,479 | | | $ | (47,353 | ) | | $ | 1,129,126 | | | | | | | Net income | | | | | | | 94,509 | | | | | | | | 94,509 | | Net unrealized losses on cash flow hedges | | | | | | | | | | | (518 | ) | | | (518 | ) | Reclassification of realized losses on cash flow hedges into earnings | | | | | | | | | | | 1,406 | | | | 1,406 | | Amortization of net actuarial losses and prior service credits into earnings and net change in funded status of benefit plans | | | | | | | | | | | 560 | | | | 560 | | Partnership distributions | | | | | | | (211,020 | ) | | | | | | | (211,020 | ) | Common Units issued under Restricted Unit Plans | | | 86 | | | | | | | | | | | | | | Compensation cost recognized under Restricted Unit Plans, net of forfeitures | | | | | | | 7,390 | | | | | | | | 7,390 | | | | | | | | | | | | | | | | | | | Balance at September 27, 2014 | | | 60,317 | | | $ | 1,067,358 | | | $ | (45,905 | ) | | $ | 1,021,453 | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | Accumulated | | | | | | | | | | | | | | | | Other | | | Total | | | | Number of | | | Common | | | Comprehensive | | | Partners' | | | | Common Units | | | Unitholders | | | (Loss) | | | Capital | | Balance at September 28, 2013 | | | 60,231 | | | $ | 1,176,479 | | | $ | (47,353 | ) | | $ | 1,129,126 | | Net income | | | | | | | 94,509 | | | | | | | | 94,509 | | Net unrealized losses on cash flow hedges | | | | | | | | | | | (518 | ) | | | (518 | ) | Reclassification of realized losses on cash flow hedges into earnings | | | | | | | | | | | 1,406 | | | | 1,406 | | Amortization of net actuarial losses and prior service credits into earnings and net change in funded status of benefit plans | | | | | | | | | | | 560 | | | | 560 | | Partnership distributions | | | | | | | (211,020 | ) | | | | | | | (211,020 | ) | Common Units issued under Restricted Unit Plans | | | 86 | | | | | | | | | | | | | | Compensation cost recognized under Restricted Unit Plans, net of forfeitures | | | | | | | 7,390 | | | | | | | | 7,390 | | Balance at September 27, 2014 | | | 60,317 | | | $ | 1,067,358 | | | $ | (45,905 | ) | | $ | 1,021,453 | | Net income | | | | | | | 84,352 | | | | | | | | 84,352 | | Net unrealized losses on cash flow hedges | | | | | | | | | | | (1,159 | ) | | | (1,159 | ) | Reclassification of realized losses on cash flow hedges into earnings | | | | | | | | | | | 1,388 | | | | 1,388 | | Amortization of net actuarial losses and prior service credits into earnings and net change in funded status of benefit plans | | | | | | | | | | | (5,207 | ) | | | (5,207 | ) | Recognition in earnings of net actuarial loss for pension settlement | | | | | | | | | | | 2,000 | | | | 2,000 | | Partnership distributions | | | | | | | (213,118 | ) | | | | | | | (213,118 | ) | Common Units issued under Restricted Unit Plans | | | 214 | | | | | | | | | | | | | | Compensation cost recognized under Restricted Unit Plans, net of forfeitures | | | | | | | 8,611 | | | | | | | | 8,611 | | Balance at September 26, 2015 | | | 60,531 | | | $ | 947,203 | | | $ | (48,883 | ) | | $ | 898,320 | | Net income | | | | | | | 14,440 | | | | | | | | 14,440 | | Net unrealized gains on cash flow hedges | | | | | | | | | | | 6 | | | | 6 | | Reclassification of realized losses on cash flow hedges into earnings | | | | | | | | | | | 1,100 | | | | 1,100 | | Amortization of net actuarial losses and prior service credits into earnings and net change in funded status of benefit plans | | | | | | | | | | | (55 | ) | | | (55 | ) | Recognition in earnings of net actuarial loss for pension settlement | | | | | | | | | | | 2,000 | | | | 2,000 | | Partnership distributions | | | | | | | (215,522 | ) | | | | | | | (215,522 | ) | Common Units issued under Restricted Unit Plan | | | 258 | | | | | | | | | | | | | | Compensation cost recognized under Restricted Unit Plans, net of forfeitures | | | | | | | 7,942 | | | | | | | | 7,942 | | Balance at September 24, 2016 | | | 60,789 | | | $ | 754,063 | | | $ | (45,832 | ) | | $ | 708,231 | |
The accompanying notes are an integral part of these consolidated financial statements.
SUBURBAN PROPANE PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (dollars in thousands, except unit and per unit amounts) 1.
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 60,316,74660,789,374 Common Units outstanding at September 27, 2014.24, 2016. 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”), as 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 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. The Partnership serves approximately 1.21.1 million residential, commercial, industrial and agricultural customers from approximately 710through 675 locations in 41 states. The Partnership’s operations are principally concentrated in the east and west coast regions includingof the United States, as well as portions of the Midwest region of the United States and Alaska. No single customer accounted for 10% or more of the Partnership’s revenues during fiscal 2014, 20132016, 2015 or 2012. 2014.2. Summary of Significant Accounting Policies
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 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. Fiscal Period. The Partnership uses a 52/53 week fiscal year which ends on the last Saturday in September. The Partnership’s fiscal quarters are generally 13 weeks in duration. When the Partnership’s fiscal year is 53 weeks long, the corresponding fourth quarter is 14 weeks in duration. Fiscal 20142016, fiscal 2015 and fiscal 20132014 included 52 weeks of operations and fiscal 2012 included 53 weeks of operations.
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 annually billed 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 1: Quoted prices in active markets for identical assets or liabilities. 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. Level 3: Valuations derived from valuation techniques in which one or more significant inputs are unobservable. Business Combinations. The Partnership accounts for business combinations using the acquisition 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 statements from the acquisition date. The Partnership expenses all acquisition-related costs as incurred. 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, allowances for doubtful 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. Cash and Cash Equivalents. The Partnership considers all highly liquid instruments purchased with an original maturity of three months or less to be cash equivalents. The carrying amount approximates fair value because of the short maturity of these instruments. 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.Activities Commodity Price Risk. Given the retail nature of its operations, the Partnership maintains a certain level of priced physical inventory to help 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 options 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 help 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 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 derivative 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 derivative 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 plus 1⁄2 ½ 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. 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. Long-Lived Assets.Assets 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 straight‑line method based upon the estimated useful life of the asset as follows: Buildings | | 40 Years | Buildings | | 40 Years | Building and land improvements | | 20 Years | Transportation equipment | | 3-203-10 Years | Storage facilities | | 7-407-30 Years | Office equipment | | 5-10 Years | Tanks and cylinders | | 10-40 Years | Computer software | | 3-7 Years |
The weighted average estimated useful life of the Partnership’s storage facilities and tanks and cylinders is approximately 2122 years and 28 years, respectively.
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 as of the end of fiscal July of each year, or when an event occurs or circumstances change that would indicate potential impairment. The Partnership 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 relationships, tradenames, non-compete agreements and leasehold interests. Customer relationships 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 20162017 and 2021.2025. 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. Accrued Insurance. Accrued insurance represents the estimated costs of known and anticipated or unasserted claims for self-insured liabilities related to general and product, workers’ compensation and automobile liability. Accrued insurance provisions for unasserted claims arising from unreported incidents are based on an analysis of historical claims data. For each claim, the Partnership records a provision up to the estimated amount of the probable claim utilizing actuarially determined loss development factors applied to actual claims data. The Partnership maintains insurance coverage such that its net exposure for insured claims is limited to the insurance deductible, claims above which are paid by the Partnership’s insurance carriers. For the portion of the estimated liability that exceeds insurance deductibles, the Partnership records an asset related to the amount of the liability expected to be covered by insurance. Pension and Other Postretirement Benefits. The Partnership estimates the rate of return on plan assets, the discount rate used to estimate the present value of future benefit obligations and the expected cost of future health care benefits in determining its annual pension and other postretirement benefit costs. In October 2014, the Society of Actuaries (“SOA”) issued new mortality tables (RP-2014) and a new mortality improvement scale (MP-2014). The Partnership uses SOA and other actuarial life expectancy information when developing the annual mortality assumptions for the pension and postretirement benefit plans, which are used to measure net periodic benefit costs and the obligation under these plans. 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 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. Unit-Based Compensation. 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 remeasurement 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. 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,Plan, 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.Plan. In computing diluted net income per Common Unit, weighted average units outstanding used to compute basic
net income per Common Unit were increased by 269,867, 222,419220,112, 256,794 and 141,570269,867 units for fiscal 2014, 20132016, 2015 and 2012,2014, respectively, to reflect the potential dilutive effect of the unvested restricted units outstanding using the treasury stock method. Comprehensive Income. The Partnership reports comprehensive income (the total of net income and all other non-owner changes in partners’ capital) within the consolidated statement of 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. plans, and net actuarial losses recognized in earnings associated with pension settlements.Recently Issued Accounting Pronouncements. In May 2014,August 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting StandardsStandard Update (“ASU”) No. 2016-15, “Classification of Certain Cash Receipts and Cash Payments” (“ASU 2016-15”). This update addresses eight specific cash flow issues and is intended to reduce diversity in practice on how certain cash receipts and cash payments are presented and classified in the statement of cash flows. ASU 2016-15 is effective for the first interim period within annual reporting periods beginning after December 15, 2017, which will be the Partnership’s first quarter of fiscal 2019. Early adoption of ASU 2016-15 is permitted. The Partnership is currently evaluating the impact that the standard will have on the Partnership’s cash flows. In March 2016, the FASB issued ASU No. 2016-09, “Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting” (“ASU 2016-09”). This update is intended to simplify several areas of accounting for share-based compensation arrangements, including the income tax impact, classification on the statement of cash flows and forfeitures. ASU 2016-09 is effective for the first interim period within annual reporting periods beginning after December 15, 2016, which will be the Partnership’s first quarter of fiscal 2018. Early adoption of ASU 2016-09 is permitted. The Partnership is currently evaluating the impact that the standard will have on the Partnership’s results of operations, financial position and cash flows. In February 2016, the FASB issued ASU 2016-02, “Leases” (“ASU 2016-02”). The standard amends the existing accounting standards for lease accounting, including requiring lessees to recognize most leases on their balance sheets and making targeted changes to lessor accounting. ASU 2016-02 is effective for the first interim period within annual reporting periods beginning after December 15, 2018, which will be the Partnership’s first quarter of fiscal 2020. Early adoption of ASU 2016-02 is permitted. The new leases standard requires a modified retrospective transition approach for all leases existing at, or entered into after, the date of initial application, with an option to use certain transition relief. The Partnership is currently evaluating the impact of adopting ASU 2016-02 on the Partnership’s results of operations, financial position and cash flows. In April 2015, the FASB issued ASU 2015-03, “Simplifying the Presentation of Debt Issuance Costs” (“ASU 2015-03”). This update requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with the presentation of original issue debt discounts. ASU 2015-03 is effective for the first interim period within annual reporting periods beginning after December 15, 2015, which will be the Partnership’s first quarter of fiscal 2017. In August 2015, the FASB issued ASU No. 2015-15, which provides additional guidance related to the presentation and subsequent measurement of debt issuance costs related to line-of-credit arrangements. An entity may present debt issuance costs as an asset and subsequently amortize the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings. Other than the reclassification of existing unamortized debt issuance costs on the balance sheet, the adoption of ASU 2015-03 will have no impact on the Partnership’s operations or cash flows. In May 2014, the FASB issued ASU 2014-09 “Revenue from Contracts with Customers” (“ASU 2014-09”). This update provides a principles-based approach to revenue recognition, requiring revenue recognition to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The ASU provides a five-step model to be applied to all contracts with customers. The five steps are to identify the contract(s) with the customer, identify the performance obligations in the contract, determine the transaction price, allocate the transaction price to the performance obligations in the contract and recognize revenue when each performance obligation is satisfied. On July 9, 2015, the FASB finalized a one-year deferral of the effective date of ASU 2014-09. The revenue standard is therefore effective for the first interim period within annual reporting periods beginning after December 15, 2016,2017, which will be the Partnership’s first quarter of fiscal year 2018.2019. Early adoption as of the original effective date is permitted. ASU 2014-09 can be applied either retrospectively to either each prior reporting period presented or retrospectively with the cumulative effect of initially applying the update recognized at the date of the initial application along with additional disclosures. TheWhile the Partnership is still in the process of evaluating the impacts, if any,potential impact of ASU 2014-09, it does not expect the adoption of ASU 2014-09 will have a material impact on the Partnership’s results of operations, financial position or cash flows. Recently Adopted Accounting Pronouncements. In December 2011,
3. | Acquisition and Disposition of Businesses |
On April 22, 2016, the FASB issued an ASU regarding disclosures about offsettingOperating Partnership sold certain assets and liabilities (“ASU 2011-11”).operations in a non-strategic market of its propane segment for $26,000, including $5,000 representing non-compete consideration that will be received over a five-year period, resulting in a gain of $9,769 that was recognized during the third quarter of fiscal 2016. The new guidance requires an entity to disclose information about offsetting and related arrangements to enable users of financial statements to understand the effect of those arrangements on its financial position. The amendment, further clarified with ASU 2013-01, enhances 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 Partnership adopted ASU 2011-11 and ASU 2013-01 on September 29, 2013 and included further disclosure regarding offsettingcorresponding net assets and liabilities for derivative instruments accounted for under ASC 815. As this guidance affects disclosures only, its adoption had no impact on the Partnership’s financial position, results of operations or cash flows. 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 Partnership adopted ASU 2013-02 on September 29, 2013 and its adoption did not change the items that must be reported in other comprehensive income, nor did it have an impact on the Partnership’s financial position, results of operations or 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 Propanematerial 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 onfinancial position and cash flows.
On December 15, 2015, the Acquisition Date. Pursuant toOperating Partnership acquired the Contribution Agreement,assets of Propane USA Distribution, LLC (“Propane USA”), a propane marketer headquartered in Margate, Florida, and its affiliate companies, for $45,000, including $3,000 for non-compete consideration, plus working capital acquired. As of September 24, 2016, $42,945 was paid, of which $41,250 was paid at closing, and 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 averageremainder 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 topurchase price will 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 paidfunded in accordance with the terms of the Exchange Offers (such payment, the “Inergy Cash Consideration”).non-compete agreements. 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%acquisition 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 noteholdersPropane USA 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 14, 2012.
On April 25, 2012, the Partnership 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 senior notes (with an aggregate par value of $1,000,000) and $184,761 in cash to tendering Inergy noteholdersconsummated pursuant to the Exchange Offers; (ii) $65,000 inPartnership’s strategic growth initiatives and was funded entirely from 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 net of amounts owed to Inergy by the Partnership at the Acquisition Date).on hand. The fair value of the newly issued senior notes was determined using Level 2 inputs and the fair value of the 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 Acquisition Date fair value of certain assets acquired in the Inergy Propane Acquisition, principally property, plant and equipment, and intangible assets. The consolidated balance sheets since 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 | | | | | | | 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 | | | | | | | Total assets acquired | | $ | 1,976,889 | | | | | | | 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 $4,870 decrease to goodwill as of the Acquisition Date. As a result, results of operations for fiscal 2012 have been revised for a $205 decreaseof Propane USA were not material to depreciation expense and a $1,449 increase to amortization expense.
The following presents unaudited pro forma combined financial information as if the Inergy Propane Acquisition had occurred on September 25, 2011, the first day of the Partnership’s 2012 fiscal year, as adjusted for the final purchase price allocation. The unaudited pro forma combinedconsolidated financial information was prepared under the assumption that the net proceeds from the issuanceposition and statement 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 Acquisition Date). As a result, the Common Units were assumed to have been issued on September 30, 2011, 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.operations.
| | | | | | | | Year Ended
September 29,
2012 | | Revenues | | $ | 1,842,698 | | Net income | | $ | 12,824 | | Income per common unit | | | | | Basic | | $ | 0.23 | | Diluted | | $ | 0.23 | |
4. | 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 indicated nor is it necessarily indicative of future operating results.
4. Distributions of Available Cash
|
The Partnership makes distributions to its partners no later than 45 days after the end of each fiscal quarter 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 27, 2014:24, 2016: | | | | | | | | Fiscal | | | Fiscal | | | Fiscal | | | | | Fiscal
2014 | | | Fiscal
2013 | | | Fiscal
2012 | | | 2016 | | | 2015 | | | 2014 | | First Quarter | | $ | 0.8750 | | | $ | 0.8750 | | | $ | 0.8525 | | | $ | 0.8875 | | | $ | 0.8750 | | | $ | 0.8750 | | Second Quarter | | | 0.8750 | | | | 0.8750 | | | | 0.8525 | | | | 0.8875 | | | | 0.8875 | | | | 0.8750 | | Third Quarter | | | 0.8750 | | | | 0.8750 | | | | 0.8525 | | | | 0.8875 | | | | 0.8875 | | | | 0.8750 | | Fourth Quarter | | | 0.8750 | | | | 0.8750 | | | | 0.8525 | | | | 0.8875 | | | | 0.8875 | | | | 0.8750 | |
5.
5. | Selected Balance Sheet Information |
Inventories consist of the following: | | | | | | As of | | | | | As of | | | September 24, | | | September 26, | | | | | September 27,
2014 | | | September 28,
2013 | | | 2016 | | | 2015 | | Propane, fuel oil and refined fuels and natural gas | | $ | 89,470 | | | $ | 75,885 | | | $ | 43,905 | | | $ | 45,918 | | Appliances | | | 1,495 | | | | 1,738 | | | | 1,447 | | | | 1,768 | | | | | | | | | | $ | 45,352 | | | $ | 47,686 | | | | $ | 90,965 | | | $ | 77,623 | | | | | | | | | | |
The Partnership enters into contracts for the supply of propane, fuel oil and natural 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 | | | | | As of | | | September 24, | | | September 26, | | | | | September 27,
2014 | | September 28,
2013 | | | 2016 | | | 2015 | | Land and improvements | | $ | 201,353 | | | $ | 207,516 | | | $ | 193,194 | | | $ | 195,430 | | Buildings and improvements | | | 103,751 | | | 104,137 | | | | 109,345 | | | | 104,998 | | Transportation equipment | | | 64,254 | | | 71,815 | | | | 57,823 | | | | 58,650 | | Storage facilities | | | 110,586 | | | 113,571 | | | | 110,528 | | | | 110,033 | | Equipment, primarily tanks and cylinders | | | 823,478 | | | 830,282 | | | | 845,650 | | | | 833,479 | | Computer systems | | | 49,904 | | | 49,049 | | | Computer Systems | | | | 52,643 | | | | 51,039 | | Construction in progress | | | 3,420 | | | 4,472 | | | | 3,845 | | | | 7,177 | | | | | | | | | | | | | 1,356,746 | | | | 1,380,842 | | | | 1,373,028 | | | | 1,360,806 | | Less: accumulated depreciation | | | (529,920 | ) | | | (492,610 | ) | | | (630,899 | ) | | | (579,748 | ) | | | | | | | | | $ | 742,129 | | | $ | 781,058 | | | | $ | 826,826 | | | $ | 888,232 | | | | | | | | | | |
Depreciation expense for fiscal 2014, 20132016, 2015 and 20122014 amounted to $78,921, $72,353$72,471, $75,920 and $35,032,$78,921, respectively. 6.
6. | Goodwill and Other Intangible Assets |
The Partnership’s fiscal 20142016 and fiscal 20132015 annual goodwill impairment review resulted in no adjustments to the carrying amount of goodwill. The carrying values of goodwill assigned to the Partnership’s operating segments are as follows: | | | | | | | | | | Propane | | | Fuel oil and refined fuels | | | Natural gas and electricity | | | Total | | | | | Propane | | | Fuel oil
and
refined
fuels | | Natural
gas and
electricity | | | Total | | | Balance as of September 27, 2014 and September 28, 2013 | | | | | | | | | | Balance as of September 26, 2015 | | | | | | | | | | | | | | | | | | Goodwill | | $ | 1,075,091 | | | $ | 10,900 | | | $ | 7,900 | | | $ | 1,093,891 | | | $ | 1,075,091 | | | $ | 10,900 | | | $ | 7,900 | | | $ | 1,093,891 | | Accumulated adjustments | | | — | | | | (6,462 | ) | | | — | | | | (6,462 | ) | | | — | | | | (6,462 | ) | | | — | | | | (6,462 | ) | | | | | | | | | | | | | | | $ | 1,075,091 | | | $ | 4,438 | | | $ | 7,900 | | | $ | 1,087,429 | | | | $ | 1,075,091 | | | $ | 4,438 | | | $ | 7,900 | | | $ | 1,087,429 | | | | | | | | | | | | | | | | | | Fiscal 2016 Activity | | | | | | | | | | | | | | | | | | Goodwill acquired (1) | | | $ | 14,710 | | | $ | — | | | $ | — | | | $ | 14,710 | | Goodwill disposed (2) | | | | (7,504 | ) | | | — | | | | — | | | | (7,504 | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Balance as of September 24, 2016 | | | | | | | | | | | | | | | | | | Goodwill | | | $ | 1,082,297 | | | $ | 10,900 | | | $ | 7,900 | | | $ | 1,101,097 | | Accumulated adjustments | | | | — | | | | (6,462 | ) | | | — | | | | (6,462 | ) | | | | $ | 1,082,297 | | | $ | 4,438 | | | $ | 7,900 | | | $ | 1,094,635 | |
Other intangible assets consist of the following: | | | | | | As of | | | | | As of | | | September 24, | | | September 26, | | | | | September 27,
2014 | | September 28,
2013 | | | 2016 | | | 2015 | | Customer relationships | | $ | 466,959 | | | $ | 466,959 | | | Non-compete agreements | | | 26,815 | | | 26,815 | | | Customer relationships (1) (2) | | | $ | 492,656 | | | $ | 471,829 | | Non-compete agreements (1) | | | | 31,040 | | | | 27,815 | | Tradenames | | | 3,482 | | | 3,482 | | | | 3,482 | | | | 3,482 | | Other | | | 1,967 | | | 1,967 | | | | 1,967 | | | | 1,967 | | | | | | | | | | | | | 499,223 | | | | 499,223 | | | | | | | | | | | | 529,145 | | | | 505,093 | | Less: accumulated amortization | | | | | | | | | | | | | Customer relationships | | | (122,411 | ) | | | (71,382 | ) | | | (225,634 | ) | | | (173,823 | ) | Non-compete agreements | | | (13,962 | ) | | | (8,138 | ) | | | (22,533 | ) | | | (19,337 | ) | Tradenames | | | (2,573 | ) | | | (2,040 | ) | | | (3,482 | ) | | | (3,069 | ) | Other | | | (984 | ) | | | (892 | ) | | | (1,167 | ) | | | (1,075 | ) | | | | | | | | | | (252,816 | ) | | | (197,304 | ) | | | | (139,930 | ) | | | (82,452 | ) | | $ | 276,329 | | | $ | 307,789 | | | | | | | | | | | | $ | 359,293 | | | $ | 416,771 | | | | | | | | | | |
(1) | Reflects the impact from the Propane USA acquisition (Note 3). |
(2) | Reflects the impact from the disposition of certain assets and operations in a non-strategic market of the propane |
segment (Note 3). Aggregate amortization expense related to other intangible assets for fiscal 2016, 2015 and 2014 2013was $57,145, $57,374 and 2012 was $57,478, $58,031 and $12,002, respectively. Aggregate amortization expense for each of the five succeeding fiscal years related to other intangible assets held as of September 27, 201424, 2016 is estimated as follows: 2015 - $56,767; 2016 - $53,971; 2017 - $52,686;$56,454; 2018 - $52,326; and$56,094; 2019 - $51,303.$55,071; 2020 - $54,086; and 2021 - $44,577. 7.
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 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 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 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 Common Unitholder’s basis in the Partnership. As described in Note 1 and Note 2, the earnings of the Corporate Entities are subject to corporate level federal and state income tax. However, based upon past performance, the Corporate Entities are currently reporting an income tax provision composed primarily of minimum state income taxes. A full valuation allowance has been provided against the deferred tax assets based upon an analysis of all available evidence, both negative and positive at the balance sheet date, which, taken as a whole, indicates that it is more likely than not that sufficient future taxable income will not be available to utilize the assets. Management’s periodic reviews include, among other things, the nature and amount of the taxable income and expense items, the expected timing of when assets will be used or liabilities will be required to be reported and the reliability of historical profitability of businesses expected to provide future earnings. Furthermore, management considered tax-planning strategies it could use to increase the likelihood that the deferred tax assets will be realized.
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 | | | | | Year Ended | | | September 24, | | | September 26, | | | September 27, | | | | | September 27,
2014 | | | September 28,
2013 | | | September 29,
2012 | | | 2016 | | | 2015 | | | 2014 | | Current | | | | | | | | | | | | | | | | | | | Federal | | $ | 10 | | | $ | 26 | | | $ | 18 | | | $ | 7 | | | $ | 23 | | | $ | 10 | | State and local | | | 757 | | | | 581 | | | | 119 | | | | 581 | | | | 677 | | | | 757 | | | | | | | | | | | | | | 588 | | | | 700 | | | | 767 | | | | | 767 | | | | 607 | | | | 137 | | | Deferred | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | | | | | | | | | | $ | 588 | | | $ | 700 | | | $ | 767 | | | | $ | 767 | | | $ | 607 | | | $ | 137 | | | | | | | | | | | | | |
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 | | | | | Year Ended | | | September 24, | | | September 26, | | | September 27, | | | | | September 27,
2014 | | September 28,
2013 | | September 29,
2012 | | | 2016 | | | 2015 | | | 2014 | | Income tax provision at federal statutory tax rate | | $ | 33,346 | | | $ | 27,792 | | | $ | 271 | | | $ | 5,260 | | | $ | 29,768 | | | $ | 33,346 | | Impact of Partnership income not subject to federal income taxes | | | (38,919 | ) | | (35,187 | ) | | (4,564 | ) | | | (9,844 | ) | | | (32,148 | ) | | | (38,919 | ) | Permanent differences | | | 86 | | | 71 | | | 244 | | | | 182 | | | | 210 | | | | 86 | | Transfer of assets to Corporate Entities | | | — | | | | — | | | 8,181 | | | Change in valuation allowance | | | 5,458 | | | 9,771 | | | (3,567 | ) | | | 4,737 | | | | 2,181 | | | | 5,458 | | State income taxes | | | (60 | ) | | (1,135 | ) | | 339 | | | | (211 | ) | | | 253 | | | | (60 | ) | Other | | | 856 | | | (705 | ) | | (767 | ) | | | 464 | | | | 436 | | | | 856 | | | | | | | | | | | | | Provision for income taxes—current | | $ | 767 | | | $ | 607 | | | $ | 137 | | | | | | | | | | | | | | Provision for income taxes - current | | | $ | 588 | | | $ | 700 | | | $ | 767 | |
The components of net deferred taxes and the related valuation allowance using currently enacted tax rates are as follows: | | | | | | Year Ended | | | | | As of | | | September 24, | | | September 26, | | | | | September 27,
2014 | | September 28,
2013 | | | 2016 | | | 2015 | | Deferred tax assets: | | | | | | | | | | | | | Net operating loss carryforwards | | $ | 51,321 | | | $ | 46,356 | | | $ | 60,628 | | | $ | 55,033 | | Allowance for doubtful accounts | | | 1,371 | | | 878 | | | | 184 | | | | 340 | | Inventory | | | 433 | | | 525 | | | | 457 | | | | 395 | | Intangible assets | | | 122 | | | 577 | | | Deferred revenue | | | 1,524 | | | 2,188 | | | | 1,091 | | | | 1,241 | | Derivative instruments | | | 71 | | | 109 | | | | 78 | | | | — | | AMT credit carryforward | | | 1,086 | | | 1,086 | | | | 1,086 | | | | 1,086 | | Other accruals | | | 2,060 | | | 2,062 | | | | 1,101 | | | | 1,718 | | | | | | | | | | Total deferred tax assets | | | 57,988 | | | | 53,781 | | | | 64,625 | | | | 59,813 | | | | | | | | | | Deferred tax liabilities: | | | | | | | | | | | | | Derivative instruments | | | | — | | | | 142 | | Intangible assets | | | | 775 | | | | 312 | | Property, plant and equipment | | | 6,124 | | | | 7,375 | | | | 5,068 | | | | 5,314 | | | | | | | | | | Total deferred tax liabilities | | | 6,124 | | | | 7,375 | | | | 5,843 | | | | 5,768 | | | | | | | | | | Net deferred tax assets | | | 51,864 | | | | 46,406 | | | | 58,782 | | | | 54,045 | | Valuation allowance | | | (51,864 | ) | | | (46,406 | ) | | | (58,782 | ) | | | (54,045 | ) | | | | | | | | | 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 27,
2014 | | | September 28,
2013 | | 7.5% senior notes, due October 1, 2018, including unamortized premium of $-0- and $28,614, respectively | | $ | — | | | $ | 525,171 | | 7.375% senior notes, due March 15, 2020, net of unamortized discount of $1,183 and $1,400, respectively | | | 248,817 | | | | 248,600 | | 7.375% senior notes, due August 1, 2021, including unamortized premium of $22,688 and $25,286, respectively | | | 368,868 | | | | 371,466 | | 5.5% senior notes, due June 1, 2024 | | | 525,000 | | | | — | | Revolving Credit Facility, due January 5, 2017 | | | 100,000 | | | | 100,000 | | | | | | | | | | | | | $ | 1,242,685 | | | $ | 1,245,237 | | | | | | | | | | |
| | As of | | | | September 24, | | | September 26, | | | | 2016 | | | 2015 | | 7.375% senior notes, due August 1, 2021, including unamortized premium of $16,992 and $19,927, respectively | | $ | 363,172 | | | $ | 366,107 | | 5.5% senior notes, due June 1, 2024 | | | 525,000 | | | | 525,000 | | 5.75% senior notes, due March 1, 2025 | | | 250,000 | | | | 250,000 | | Revolving Credit Facility, due March 3, 2021 | | | 100,000 | | | | — | | Revolving Credit Facility, due January 5, 2017 | | | — | | | | 100,000 | | | | $ | 1,238,172 | | | $ | 1,241,107 | |
Senior Notes.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.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 2021 Senior Notes require semi-annual interest payments in February and August. On December 19, 2012, the Partnership completed an offer to exchange its then-outstanding unregistered 7.5% senior notes due 2018 and 7.375% senior notes due 2021 for an equal principal amount of 7.5% senior notes due 2018 and 7.375% senior notes due 2021, respectively, that have been registered under the Securities Act of 1933, as amended. On August 2, 2013, the Partnership repurchased, pursuant to an optional redemption, $133,400 of its 2021 Senior Notes using net proceeds from a May 2013 public offering of Common Units 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. On May 27, 2014, the Partnership repurchased and satisfied and discharged all of its 2018 Senior Notes with net proceeds from the issuance of the 2024 Senior Notes, as defined below, and cash on hand pursuant to a tender offer and redemption during the third quarter of fiscal 2014.redemption. In connection with this tender offer and redemption, the Partnership recognized a loss on the extinguishment of debt of $11,589 consisting of $31,633 for the redemption premium and related fees, as well as the write-off of $5,230 and ($25,274) in unamortized debt origination costs and unamortized premium, respectively. The 2018 Senior Notes required semi-annual interest payments in April and October, and the 2021 Senior Notes require semi-annual interest payments in February and August. The 2021 Senior Notes are redeemable, at the Partnership’s option, in whole or in part, at any time on or 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 then-outstanding unregistered 7.5% senior notes due 2018 and 7.375% senior notes due 2021 (collectively, the “Old Notes”) for an equal principal amount of 7.5% senior notes due 2018 and 7.375% senior notes due 2021 (collectively, 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 amount, 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 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 and require semi-annual interest payments in March and September.
The 2020 Senior Notes are redeemable, at the Partnership’s option, in whole or in part, at any time on or after March 15, 2015, 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 | | 2016 | | | 103.688% | | 2017 | | | 102.459% | | 2018 | | | 101.229% | | 2019 and thereafter | | | 100.000% | |
| | | | | Year | | Percentage | | 2015 | | | 103.688 | % | 2016 | | | 102.458 | % | 2017 | | | 101.229 | % | 2018 and thereafter | | | 100.000 | % |
2024 Senior Notes As previously discussed, onOn May 27, 2014, the Partnership and its 100%-owned subsidiary, Suburban Energy Finance Corp., completed a public offering of $525,000 in aggregate principal amount of 5.5% senior notes due June 1, 2024 (the “2024 Senior Notes”). The 2024 Senior Notes were issued at 100% of the principal amount and require semi-annual interest payments in June and December, beginning in December 2014.December. The net proceeds from the issuance of the 2024 Senior Notes, along with cash on hand, were used to repurchase and satisfy and discharge all of the 2018 Senior Notes.
The 2024 Senior Notes are redeemable, at the Partnership’s option, in whole or in part, at any time on or after June 1, 2019, 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 | | | Percentage | | 2019 | | | 102.750 | % | | | 102.750% | | 2020 | | | 101.833 | % | | | 101.833% | | 2021 | | | 100.917 | % | | | 100.917% | | 2022 and thereafter | | | 100.000 | % | | | 100.000% | |
2025 Senior Notes On February 25, 2015, the Partnership and its 100%-owned subsidiary, Suburban Energy Finance Corp., completed a public offering of $250,000 in aggregate principal amount of 5.75% senior notes due March 1, 2025 (the “2025 Senior Notes”). The 2025 Senior Notes were issued at 100% of the principal amount and require semi-annual interest payments in March and September. The net proceeds from the issuance of the 2025 Senior Notes, along with cash on hand, were used to repurchase and satisfy and discharge all of the previously outstanding 7.375% senior notes due March 15, 2020 (“2020 Senior Notes”). In connection with this tender offer and redemption, the Partnership recognized a loss on the extinguishment of debt of $15,072 consisting of $11,124 for the redemption premium and related fees, as well as the write-off of $2,855 and $1,093 in unamortized debt origination costs and unamortized discount, respectively. The 2025 Senior Notes are redeemable, at the Partnership’s option, in whole or in part, at any time on or after March 1, 2020, 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 | | 2020 | | | 102.875% | | 2021 | | | 101.917% | | 2022 | | | 100.958% | | 2023 and thereafter | | | 100.000% | |
The Partnership’s obligations under the 2020 Senior Notes, 2021 Senior Notes, 2024 Senior Notes and 20242025 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 Partnership is permitted to redeem some or all of the Senior Notes at redemption prices and times as specified in the indentures governing the Senior Notes. The Senior Notes each 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. Credit Agreement The Operating Partnership has an amended and restated credit agreement entered into on January 5, 2012, as amended on August 1, 2012, and May 9, 2014 and March 3, 2016 (collectively, the “Amended Credit Agreement”) that provides for a five-year $400,000$500,000 revolving credit facility (the “Revolving Credit Facility”), of which $100,000 was outstanding as of September 27, 201424, 2016 and September 28, 2013.26, 2015. Borrowings under the Revolving Credit Facility may be used for general corporate purposes, including working capital, capital expenditures and acquisitions. The Operating Partnership has the right to prepay any borrowings under the Revolving Credit Facility, in whole or in part, without penalty at any time prior to maturity. During In connection with the second quarter of fiscal 2014,Amended Credit Agreement, the Partnership experiencedrecognized a significant increase in working capital requirements asnon-cash charge of $292 to write-off a resultportion of unamortized debt origination costs of the significant increase in wholesale propane costs. The increase in working capital resulted in the net borrowing of $55,000 under the Partnership’s Revolving Credit Facility in the second quarter of fiscal 2014. These additional borrowings were repaid in full in April 2014 with internally generated cash.previous credit agreement.
The amendment and restatement of 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. 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, its subsidiaries and the Partnership, as well as certain financial covenants. The amendment on May 9, 2014 made certain technical amendments with respect to agreements related to debt refinancing.
The amendment on March 3, 2016 amends and restates the previous amended and restated credit agreement to, among other things, extend the maturity date from January 5, 2017 to March 3, 2021, reduce the borrowing rate, amend certain affirmative and negative covenants and increase the revolving credit commitments from $400,000 to $500,000. The amendment also amended certain restrictive and affirmative covenants applicable to the Operating Partnership, its subsidiaries and the Partnership, as well as certain financial covenants, including (a) requiring the Partnership’s consolidated interest coverage ratio, as defined in the amendment,Amended Credit Agreement, to be not less than 2.02.5 to 1.0 as of the end of any fiscal quarter;quarter and (b) prohibiting the total consolidated leverage ratio, as defined in the amendment,Amended Credit Agreement, of the Partnership from being greater than 7.05.5 to 1.0 as of the end of any fiscal quarter. The minimum consolidated interest coverage ratio increases over time,Partnership and commencing with the second quartercertain subsidiaries of fiscal 2014, such minimum ratio is 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 is 4.75 to 1.0 (or 5.0 to 1.0 during an acquisition period as defined in the amendment). On May 9, 2014, the Operating Partnership executed a second amendment to the Amended Credit Agreement to make certain technical amendments with respect to agreements relating to debt refinancing.
The Partnership actsact as a guarantorguarantors 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 plus 1⁄2 ½ of 1%, the administrative 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 27, 2014,24, 2016, the interest rate for the Revolving Credit Facility was approximately 2.5%3.1%. The interest rate and the applicable margin will be reset atfollowing the end of each calendar quarter. In connection with the Amended Credit Agreement,January 5, 2012 amendment, the Operating Partnership entered into an interest rate swap agreement with a notional amount of $100,000, an effective date of June 25, 2013 and a termination date of January 5, 2017. Under this interest rate swap agreement, the 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 the Operating Partnership a floating rate, namely LIBOR, on the same notional principal amount. The interest rate swap has been designated as a cash flow hedge. In addition, at the time the March 3, 2016 Amended Credit Agreement was entered into, the Operating Partnership had letters of credit issued under the revolving credit facility of the previous credit agreement, all of which have been rolled into the Revolving Credit Facility of the Amended Credit Agreement. As of September 27, 2014,24, 2016, the Partnership had standby letters of credit issued under the Revolving Credit Facility in the aggregate amount of $44,882$43,256 which expire periodically through April 3, 2015. Therefore, as of September 27, 2014 the Partnership had available borrowing capacity of $255,118 under the Revolving Credit Facility.2017. The Amended Credit Agreement and the Senior Notes both contain various restrictive and affirmative covenants applicable to the Operating Partnership, its subsidiaries 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. Under the Amended Credit Agreement and the indentures governing the Senior Notes, the Operating Partnership and 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 Senior Notes and the Amended Credit Agreement as of September 27, 2014.24, 2016. 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 2014,2016, the Partnership recognized charges of $5,230$292 to write-off unamortized debt origination costs and capitalized $2,678 in costs incurred in connection with the amendments to the Amended Credit Agreement. During fiscal 2015, the Partnership recognized charges of $2,855 to write-off unamortized debt origination costs associated with the tender offer and redemption of its 2018 Senior Notes. During fiscal 2013, the Partnership recognized charges of $2,064 million to write-off unamortized debt origination costs associated with the repurchase of its 20212020 Senior Notes. Other assets at September 27, 201424, 2016 and September 28, 201326, 2015 include debt origination costs with a net carrying amount of $21,023$17,391 and $21,254,$18,458, respectively. The aggregate amounts of long-term debt maturities subsequent to September 27, 201424, 2016 are as follows: fiscal 2015 through fiscal 2016:2017: $-0-; fiscal 2017: $100,000; fiscal 2018: $-0-; fiscal 2019: $-0-; fiscal 2020: $-0-; fiscal 2021: $446,180; and thereafter: $1,121,180.$775,000. 9.
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 re-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 fiscalPlan. On July 22, 2009, the Partnership adopted the Suburban Propane Partners, L.P. 2000 Restricted Unit Plan and 2009 Restricted Unit Plan, (collectively, theas amended (the “Restricted Unit Plans”Plan”), 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 PlansPlan was 1,902,1222,400,000 as of September 27, 2014.24, 2016. In accordance with an August 6, 2013 amendment to the Restricted Unit Plans,Plan, 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. Prior to the August 6, 2013 amendment, unless otherwise stipulated by the Compensation Committee of the Partnership’s Board of Supervisors on or before the grant date, restricted units issued under the Restricted Unit PlansPlan 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. The Restricted Unit PlansPlan 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.Plan. Compensation expense for the unvested awards is recognized ratably over the vesting periods and is net of estimated forfeitures. The following is a summary of activity in the Restricted Unit Plans:Plan: | | | | | | | | | | Weighted Average | | | | | Units | | Weighted
Average
Grant
Date Fair
Value
Per Unit | | | | | | | Grant Date Fair | | Outstanding September 24, 2011 | | | 485,423 | | | $ | 32.71 | | | Granted | | | 108,674 | | | 32.60 | | | Forfeited | | | (12,225 | ) | | (30.78 | ) | | Issued | | | (139,021 | ) | | (33.14 | ) | | | | | | | | | Outstanding September 29, 2012 | | | 442,851 | | | | 32.68 | | | Granted | | | 200,933 | | | | 23.42 | | | Forfeited | | | (3,497 | ) | | | (32.15 | ) | | Issued | | | (112,660 | ) | | | (32.01 | ) | | | | | | | | | Units | | | Value Per Unit | | Outstanding September 28, 2013 | | | 527,627 | | | | 29.30 | | | | 527,627 | | | $ | 29.30 | | Granted | | | 256,273 | | | | 37.43 | | | | 256,273 | | | | 37.43 | | Forfeited | | | (3,119 | ) | | | (28.39 | ) | | | (3,119 | ) | | | (28.39 | ) | Issued | | | (85,854 | ) | | | (31.23 | ) | | | (85,854 | ) | | | (31.23 | ) | | | | | | | | Outstanding September 27, 2014 | | | 694,927 | | | $ | 32.07 | | | | 694,927 | | | | 32.07 | | | | | | | | | Granted | | | | 154,403 | | | | 37.59 | | Forfeited | | | | (7,607 | ) | | | (31.04 | ) | Issued | | | | (214,324 | ) | | | (36.68 | ) | Outstanding September 26, 2015 | | | | 627,399 | | | | 31.87 | | Granted | | | | 307,559 | | | | 23.62 | | Forfeited | | | | (12,057 | ) | | | (25.44 | ) | Issued | | | | (268,781 | ) | | | (35.19 | ) | Outstanding September 24, 2016 | | | | 654,120 | | | $ | 26.74 | |
As of September 27, 2014,24, 2016, unrecognized compensation cost related to unvested restricted units awarded under the Restricted Unit PlansPlan amounted to $8,255.$3,861. Compensation cost associated with the unvested awards is expected to be recognized over a weighted-average period of 1.41.2 years. Compensation expense for the Restricted Unit PlansPlan for fiscal 2016, 2015 and 2014 2013was $8,256, $8,611 and 2012 was $7,390, $3,888 and $4,059, respectively. Long-Term Incentive Plans.Plan. On August 6, 2013, the Compensation Committee of the Partnership’s Board of Supervisors adopted the 2014 Long-Term Incentive Plan (“LTIP”). The Partnership hasLTIP is a non-qualified, unfunded, long-term incentive plan for officers and key employees (the “LTIP”) whichthat provides for payment, in the form of cash, of an award of equity-based compensation at the end of a three-year performance period. For the fiscal 2013 and 2012 awards, theThe level of compensation earned under the 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 consisting solely of other master limited partnerships, approved by the Compensation Committee of the Board of Supervisors, over the same three-year performance period. 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 the existing LTIP. As a result, for the fiscal 2014 award, the level of compensation earned under the 2014 LTIP is based on the average distribution coverage ratio over the three-year measurement period. The Partnership’s average distribution coverage ratio is calculated as the Partnership’s average distributable cash flow, as defined inby the 2014 LTIP, for each of the three years in the measurement period, subject to certain adjustments as set forth in the 2014 LTIP, divided by the amount of annualized cash distributions to be paid by the Partnership, based on the annualized cash distribution rate at the beginning of the measurement period. Compensation expense, which includes adjustments to previously recognized compensation expense for current period changes in the fair value of unvested awards, for fiscal 2016, 2015 and 2014 2013was income of ($1,362) and 2012 wasexpense of $1,814 and $120, $1,439 and ($340), respectively. The cash payouts in fiscal 2014, 20132016, 2015 and 2012,2014, which related to the fiscal 2011, 20102013, 2012 and 20092011 awards, were $-0-,$1,473, $-0- and $3,336,$-0-, respectively. 10. Employee Benefit Plans
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 totaledcontribution costs were $1,477, $1,844 and $1,848 $1,915 and $1,359 for fiscal 2016, 2015 and 2014, 2013 and 2012, 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. Contributions, as needed, are made to a trust maintained by the Partnership. Contributions to the defined benefit pension plan are made by the Partnership in accordance with the Employee Retirement Income Security Act of 1974 minimum funding standards plus additional amounts made at the discretion of the Partnership, which may be determined from time to time. A minimum required funding payment of $715 was made by the Partnership in fiscal 2016. There were no minimumsuch funding requirements for the defined benefit pension plan forin fiscal 2014, 20132015 or 2012.2014. During the last decade, cash balance plans came under increased scrutiny which resulted in litigation pertaining to the cash balance feature and the Internal Revenue Service (“IRS”) issued additional regulations governing these types of plans. In fiscal 2010, the IRS completed its review of the Partnership’s defined benefit pension plan and issued a favorable determination letter pertaining to the cash balance formula. However, there can be no assurances that future legislative developments will not have an adverse effect on the Partnership’s results of operations or cash flows. 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,March 31, 1998, the Partnership terminatedfroze participation in its postretirement health care benefit plan, for allwith no new retirees eligible employees retiring after March 1, 1998.to participate in the plan. 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.
Projected Benefit Obligation, Fair Value of Plan Assets and Funded Status.The following tables provide a reconciliation of the changes in the benefit obligations and the fair value of the plan assets for fiscal 20142016 and 20132015 and a statement of the funded status for both years. Under the Partnership’s cash balance defined benefit pension plan, the accumulated benefit obligation and the projected benefit obligation are the same. | | | | Pension Benefits | | Retiree Health and Life
Benefits | | | Pension Benefits | | | Retiree Health and Life Benefits | | | | | 2014 | | 2013 | | 2014 | | 2013 | | | 2016 | | | 2015 | | | 2016 | | | 2015 | | Reconciliation of benefit obligations: | | | | | | | | | | | | | | | | | | | | | | | | | Benefit obligation at beginning of year | | $ | 148,631 | | | $ | 165,906 | | | $ | 17,754 | | | $ | 20,232 | | | $ | 146,907 | | | $ | 149,836 | | | $ | 15,294 | | | $ | 16,954 | | Service cost | | | — | | | | — | | | 5 | | | 8 | | | Interest cost | | | 5,774 | | | 5,229 | | | 640 | | | 586 | | | | 5,041 | | | | 5,128 | | | | 520 | | | | 575 | | Actuarial loss (gain) | | | 8,459 | | | (11,446 | ) | | (278 | ) | | (1,784 | ) | | | 11,547 | | | | 5,239 | | | | (1,198 | ) | | | (1,281 | ) | Lump sum benefits paid | | | (5,401 | ) | | (3,155 | ) | | | — | | | | — | | | | (5,816 | ) | | | (5,777 | ) | | | — | | | | — | | Ordinary benefits paid | | | (7,627 | ) | | (7,903 | ) | | (1,167 | ) | | (1,288 | ) | | | (7,316 | ) | | | (7,519 | ) | | | (838 | ) | | | (954 | ) | | | | | | | | | | | | | | | Benefit obligation at end of year | | $ | 149,836 | | | $ | 148,631 | | | $ | 16,954 | | | $ | 17,754 | | | $ | 150,363 | | | | 146,907 | | | $ | 13,778 | | | $ | 15,294 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Reconciliation of fair value of plan assets: | | | | | | | | | | | | | | | | | | | | | | | | | Fair value of plan assets at beginning of year | | $ | 120,776 | | | $ | 133,873 | | | $ | — | | | $ | — | | | $ | 104,303 | | | $ | 117,771 | | | $ | — | | | $ | — | | Actual return on plan assets | | | 10,023 | | | | (2,039 | ) | | | — | | | | — | | | | 9,191 | | | | (172 | ) | | | — | | | | — | | Employer contributions | | | — | | | | — | | | | 1,167 | | | | 1,288 | | | | 715 | | | | — | | | | 838 | | | | 954 | | Lump sum benefits paid | | | (5,401 | ) | | | (3,155 | ) | | | — | | | | — | | | | (5,816 | ) | | | (5,777 | ) | | | — | | | | — | | Ordinary benefits paid | | | (7,627 | ) | | | (7,903 | ) | | | (1,167 | ) | | | (1,288 | ) | | | (7,316 | ) | | | (7,519 | ) | | | (838 | ) | | | (954 | ) | | | | | | | | | | | | | | | Fair value of plan assets at end of year | | $ | 117,771 | | | $ | 120,776 | | | $ | — | | | $ | — | | | $ | 101,077 | | | $ | 104,303 | | | $ | — | | | $ | — | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Funded status: | | | | | | | | | | | | | | | | | | | | | | | | | Funded status at end of year | | $ | (32,065 | ) | | $ | (27,855 | ) | | $ | (16,954 | ) | | $ | (17,754 | ) | | $ | (49,286 | ) | | $ | (42,604 | ) | | $ | (13,778 | ) | | $ | (15,294 | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Amounts recognized in consolidated balance sheets consist of: | | | | | | | | | | | | | | | | | | | | | | | | | Net amount recognized at end of year | | $ | (32,065 | ) | | $ | (27,855 | ) | | $ | (16,954 | ) | | $ | (17,754 | ) | | $ | (49,286 | ) | | $ | (42,604 | ) | | $ | (13,778 | ) | | $ | (15,294 | ) | Less: Current portion | | | — | | | | — | | | | 1,276 | | | | 1,427 | | | | | | | | | | | | | | | | | Non-current benefit liability | | $ | (32,065 | ) | | $ | (27,855 | ) | | $ | (15,678 | ) | | $ | (16,327 | ) | | Less: current portion | | | | — | | | | — | | | | 922 | | | | 1,025 | | Noncurrent benefit liability | | | $ | (49,286 | ) | | $ | (42,604 | ) | | $ | (12,856 | ) | | $ | (14,269 | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Amounts not yet recognized in net periodic benefit cost and included in accumulated other comprehensive income (loss): | | | | | | | | | | | | | | | | | | | | | | | | | Actuarial net (loss) gain | | $ | (49,034 | ) | | $ | (49,986 | ) | | $ | 3,780 | | | $ | 3,683 | | | $ | (51,391 | ) | | $ | (52,836 | ) | | $ | 5,764 | | | $ | 4,865 | | Prior service credits | | | — | | | | — | | | | 889 | | | | 1,379 | | | | — | | | | — | | | | — | | | | 399 | | | | | | | | | | | | | | | | Net amount recognized in accumulated other comprehensive | | | | | | | | | | (loss) income | | $ | (49,034 | ) | | $ | (49,986 | ) | | $ | 4,669 | | | $ | 5,062 | | | | | | | | | | | | | | | | | Net amount recognized in accumulated other comprehensive (loss) income | | | $ | (51,391 | ) | | $ | (52,836 | ) | | $ | 5,764 | | | $ | 5,264 | |
Amounts recognized in other comprehensive income included net actuarial losses (gains) arising during the period of $3,538 and ($4,126) for pension benefits for fiscal 2014 and 2013, respectively, and net actuarial (gains) arising during the period of ($278) and ($1,784) for other postretirement benefits for fiscal 2014 and 2013, respectively.
The amounts in accumulated other comprehensive loss as of September 27, 201424, 2016 that are expected to be recognized as components of net periodic benefit costs during fiscal 20152017 are expenses of $4,522$5,201 and credits of $(686)($389) 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 six 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 80% and 90%; and (ii) equity securities portion of the portfolio should range between 10% and 20%.
The following table presents the actual allocation of assets held in trust as of: | | | | | | September 24, | | | September 26, | | | | | September 27,
2014 | | September 28,
2013 | | | 2016 | | | 2015 | | Fixed income securities | | | 85 | % | | 85 | % | | | 85% | | | | 86% | | Equity securities | | | 15 | % | | 15 | % | | | 15% | | | | 14% | | | | | | | | | | | 100% | | | | 100% | | | | | 100 | % | | | 100 | % | | | | | | | | | |
The Partnership’s valuations include the use of the funds’ reported net asset values for commingled fund investments. Commingled funds are valued at the net asset value for theirof its underlying securities. The Partnership further corroboratesvaluation of the valuations withassets held by the commingled funds are based on observable market data using level 1 and 2 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, | | | September 26, | | | | | September 27,
2014 | | | September 28,
2013 | | | 2016 | | | 2015 | | Short term investments (1) | | $ | 1,500 | | | $ | 1,516 | | | $ | 1,456 | | | $ | 99 | | | | | | | | | | | | Equity securities: (1) (2) | | | | | | | | | | | | | Domestic | | | 6,370 | | | | 11,780 | | | | 5,397 | | | | 5,264 | | International | | | 10,916 | | | | 5,959 | | | | 9,501 | | | | 8,923 | | | | | | | | | | | | Fixed income securities (1) (3) | | | 98,985 | | | | 101,521 | | | | 84,723 | | | | 90,017 | | | | | | | | | | $ | 101,077 | | | $ | 104,303 | | | | $ | 117,771 | | | $ | 120,776 | | | | | | | | | | |
(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 U.S. and Non-U.S. common stock. |
(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 expects to contribute approximately $10,704 to the Partnership’s defined benefit pension plan forduring fiscal 2015.2017. Estimated future benefit payments for both pension and retiree health and life benefits are as follows: | | | | | | Pension | | | Retiree Health and | | Fiscal Year | | Pension
Benefits | | | Retiree
Health
and
Life
Benefits | | | Benefits | | | Life Benefits | | 2015 | | $ | 32,316 | | | $ | 1,276 | | | 2016 | | | 12,632 | | | | 1,202 | | | 2017 | | | 11,194 | | | | 1,122 | | | $ | 31,607 | | | $ | 922 | | 2018 | | | 11,317 | | | | 1,048 | | | | 11,817 | | | | 865 | | 2019 | | | 10,244 | | | | 972 | | | | 10,776 | | | | 806 | | 2020 through 2024 | | | 45,032 | | | | 3,599 | | | 2020 | | | | 10,326 | | | | 735 | | 2021 | | | | 10,073 | | | | 672 | | 2022 through 2026 | | | | 42,360 | | | | 2,470 | |
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 20152017 will elect to receive a benefit payment in fiscal 2015.2017. 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.
Effect on Operations. The following table provides the components of net periodic benefit costs included in operating expenses for fiscal 2014, 20132016, 2015 and 2012:2014: | | | | | | | | | | | | | | Pension Benefits | | | Retiree Health and Life Benefits | | | | | Pension Benefits | | Retiree Health and Life
Benefits | | | 2016 | | | 2015 | | | 2014 | | | 2016 | | | 2015 | | | 2014 | | | | | 2014 | | 2013 | | 2012 | | 2014 | | 2013 | | 2012 | | | Service cost | | $ | — | | | $ | — | | | $ | — | | | $ | 5 | | | $ | 8 | | | $ | 7 | | | Interest cost | | | 5,774 | | | 5,229 | | | 6,311 | | | 640 | | | 586 | | | 802 | | | $ | 5,041 | | | $ | 5,128 | | | $ | 5,774 | | | $ | 520 | | | $ | 575 | | | $ | 645 | | Expected return on plan assets | | | (5,102 | ) | | (5,281 | ) | | (5,665 | ) | | | — | | | | — | | | | — | | | | (3,418 | ) | | | (4,913 | ) | | | (5,102 | ) | | | — | | | | — | | | | — | | Amortization of prior service credit | | | — | | | | — | | | | — | | | (490 | ) | | (490 | ) | | (490 | ) | | | — | | | | — | | | | — | | | | (399 | ) | | | (490 | ) | | | (490 | ) | Recognized net actuarial loss | | | 4,492 | | | 5,285 | | | 5,271 | | | (181 | ) | | | — | | | | — | | | | | | | | | | | | | | | | | | | | | | | Settlement charge | | | | 2,000 | | | | 2,000 | | | | — | | | | — | | | | — | | | | — | | Recognized net actuarial loss (gain) | | | | 5,218 | | | | 4,522 | | | | 4,492 | | | | (299 | ) | | | (196 | ) | | | (181 | ) | Net periodic benefit costs | | $ | 5,164 | | | $ | 5,233 | | | $ | 5,917 | | | $ | (26 | ) | | $ | 104 | | | $ | 319 | | | $ | 8,841 | | | $ | 6,737 | | | $ | 5,164 | | | $ | (178 | ) | | $ | (111 | ) | | $ | (26 | ) | | | | | | | | | | | | | | | | | | | | |
During fiscal 2016, lump sum pension settlement payments to either terminated or retired individuals amounted to $5,816, which exceeded the settlement threshold (combined service and interest costs of net periodic pension cost) of $5,041 for fiscal 2016, and as a result, the Partnership was required to recognize a non-cash settlement charge of $2,000 during fiscal 2016. During fiscal 2015, lump sum pension settlement payments to either terminated or retired individuals amounted to $5,777, which exceeded the settlement threshold (combined service and interest costs of net periodic pension cost) of $5,128 for fiscal 2015, and as a result, the Partnership was required to recognize a non-cash settlement charge of $2,000 during fiscal 2015. The non-cash charges were required to accelerate recognition of a portion of cumulative unamortized losses in the defined benefit pension plan. During fiscal 2014, the amount of the pension benefit obligation settled through lump sum payments did not exceed the settlement threshold; therefore, a settlement charge was not required to be recognized. Actuarial Assumptions. The assumptions used in the measurement of the Partnership’s benefit obligations as of September 27, 201424, 2016 and September 28, 201326, 2015 are shown in the following table: | | | | Pension Benefits | | Retiree Health
and Life Benefits | | | Pension Benefits | | | Retiree Health and Life Benefits | | | | | 2014 | | 2013 | | 2014 | | 2013 | | | 2016 | | | 2015 | | | 2016 | | | 2015 | | Weighted-average discount rate | | | 3.875 | % | | 4.375 | % | | 3.500 | % | | 3.750 | % | | | 3.125 | % | | | 3.875 | % | | | 2.875 | % | | | 3.500 | % | Average rate of compensation increase | | | n/a | | | n/a | | | n/a | | | n/a | | | n/a | | | n/a | | | n/a | | | n/a | | Health care cost trend | | | n/a | | | n/a | | | 7.120 | % | | 7.330 | % | | n/a | | | n/a | | | | 6.840 | % | | | 7.100 | % |
The assumptions used in the measurement of net periodic pension benefit and postretirement benefit costs for fiscal 2014, 20132016, 2015 and 20122014 are shown in the following table: | | | | Pension Benefits | | Retiree Health and Life
Benefits | | | Pension Benefits | | | Retiree Health and Life Benefits | | | | | 2014 | | 2013 | | 2012 | | 2014 | | 2013 | | 2012 | | | 2016 | | | 2015 | | | 2014 | | | 2016 | | | 2015 | | | 2014 | | Weighted-average discount rate | | | 4.375 | % | | 3.500 | % | | 4.375 | % | | 3.750 | % | | 3.000 | % | | 4.000 | % | | | 3.875 | % | | | 3.875 | % | | | 4.375 | % | | | 3.500 | % | | | 3.500 | % | | | 3.750 | % | Average rate of compensation increase | | | n/a | | | n/a | | | n/a | | | n/a | | | n/a | | | n/a | | | n/a | | | n/a | | | n/a | | | n/a | | | n/a | | | n/a | | Weighted-average expected long- term rate of return on plan assets | | | 4.900 | % | | 4.500 | % | | 4.800 | % | | n/a | | | n/a | | | n/a | | | Weighted-average expected long-term rate of return on plan assets | | | | 3.900 | % | | | 4.900 | % | | | 4.900 | % | | n/a | | | n/a | | | n/a | | Health care cost trend | | | n/a | | | n/a | | | n/a | | | 7.330 | % | | 7.530 | % | | 7.740 | % | | n/a | | | n/a | | | n/a | | | | 7.100 | % | | | 7.120 | % | | | 7.330 | % |
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. The 7.12%6.84% increase in health care costs assumed at September 27, 201424, 2016 is assumed to decrease gradually to 4.48%4.50% in fiscal 20282040 and to remain at that level thereafter. An increase or decrease of the assumed health care cost trend rates by 1.0% in each year would have no material impact to the Partnership’s benefit obligation as of September 27, 201424, 2016 nor the aggregate of service and interest components of net periodic postretirement benefit expense for fiscal 2014.2016. The Partnership has concluded that the prescription drug benefits within the retiree medical plan do not entitle the Partnership to an available Medicare subsidy.
MultiemployerMulti-Employer Pension Plans. As a result of the Inergy Propane Acquisition, the Partnership contributes to multiemployermulti-employer 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. During fiscal 2015, the Partnership accrued $11,300 for its further voluntary partial withdrawal, and during fiscal 2016 the Partnership accrued an additional $6,600 for its voluntary full withdrawal. As of September 27, 2014,24, 2016 and September 26, 2015, the accrual was $6,880 for itsPartnership’s estimated obligation to these MEPPs.MEPPs was $24,205 and $18,041, respectively. Due to the uncertainty regarding future factors that could triggerimpact the withdrawal liability, including the integration of Inergy Propane, the Partnership is unable to determine the amount and timing of anythe payment of the future withdrawal liability, or additional 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 ana 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 ana 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 multiemployermulti-employer 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’splan'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 multiemployermulti-employer pension plans for the fiscal year ended September 27, 201424, 2016 are shown below and reflect contributions made from the Inergy Propane Acquisition Date.below. | | | | | | | | | | | | | | | | | | | | | | | | | | | | EIN/Pension
Plan Number | | PPA Zone Status | | FIP/RP
Status | | Contributions | | | Contributions greater
than 5% of Total
Plan Contributions | | Expiration
date of
CBA | Pension Fund | | | 2014 | | 2013 | | | 2014 | | | 2013 | | | 2012 | | | | New England Teamsters & Trucking Industry Pension Fund | | 04-6372430 | | Red (a) | | Red (a) | | Implemented | | $ | 616 | | | $ | 562 | | | $ | 30 | | | No | | April 2016 - March 2017 | Local 282 Pension Trust Fund | | 11-6245313 | | Green (b) | | Green (b) | | n/a | | | 336 | | | | 284 | | | | 66 | | | No | | July 2019 | Teamsters Industrial Employees Pension Fund | | 22-6099363 | | Red (c) | | Red (c) | | Implemented | | | 185 | | | | 179 | | | | 15 | | | No | | June 2017 | Other (d) | | | | | | | | | | | 31 | | | | 137 | | | | 48 | | | No | | n/a | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | 1,168 | | | $ | 1,162 | | | $ | 159 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | PPA Zone Status | | | | Contributions | | | Contributions greater than 5% of | | Expiration | Pension Fund | | EIN/Pension Plan Number | | 2016 | | 2015 | | FIP/RP Status | | 2016 | | | 2015 | | | 2014 | | | Total Plan Contributions | | date of CBA | Local 282 Pension Trust (a) | | 11-6245313 | | Green | | Green | | n/a | | $ | 281 | | | $ | 269 | | | $ | 336 | | | No | | August 2019 | Teamsters Industrial Employees Pension Fund (b) | | 22-6099363 | | Green | | Green | | n/a | | | 207 | | | | 200 | | | | 185 | | | Yes | | June 2017 | Other (c) | | | | | | | | | | | 260 | | | | 604 | | | | 647 | | | No | | n/a | | | | | | | | | | | $ | 748 | | | $ | 1,073 | | | $ | 1,168 | | | | | |
(a) | Based on most recent available valuation information for plan yearsyear ended September 2013.February 2016. |
(b) | Based on most recent available valuation information for plan years ended February 2014. |
(c) | Based on most recent available valuation information for plan yearsyear ended December 2013.2015. |
(d)(c) | Includes the MEPPs from which the Partnership withdrew in fiscal 2013.withdrew. |
Additionally, the Partnership contributes to certain multi-employer plans that provide health and welfare benefits and defined annuity plans. Contributions to those plans were $1,897, $2,040$1,446, $1,817 and $309$1,897 for fiscal 2016, 2015 and 2014, fiscal 2013 and fiscal 2012, respectively. 11. | Financial Instruments and Risk Management |
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.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 sheets as of September 27, 201424, 2016 and September 28, 2013,26, 2015, respectively: | | | | As of September 27, 2014 | | | As of September 28, 2013 | | | As of September 24, 2016 | | | As of September 26, 2015 | | | Asset Derivatives | | Location | | | Fair Value | | | Location | | Fair Value | | | Location | | Fair Value | | | Location | | Fair Value | | Derivatives not designated as hedging instruments: | | | | | | | | | | | | | | | | | | | | | Commodity-related derivatives | | | Other current assets | | | $ | 3,924 | | | Other current assets | | $ | 2,546 | | | Other current assets | | $ | 3,306 | | | Other current assets | | $ | 7,013 | | | | | Other assets | | | | 62 | | | Other assets | | | 716 | | | Other assets | | | 1,546 | | | Other assets | | | 485 | | | | | | | | | | | | | | | | $ | 4,852 | | | | | $ | 7,498 | | | | | | $ | 3,986 | | | | | $ | 3,262 | | | | | | | | | | | | | | | | | | | | | | | | | | | | Liability Derivatives | | Location | | | Fair Value | | | Location | | Fair Value | | | Location | | Fair Value | | | Location | | Fair Value | | Derivatives designated as hedging instruments: | | | | | | | | | | | | | | | | | | | | | Interest rate swaps | | | Other current liabilities | | | $ | 1,257 | | | Other current liabilities | | $ | 1,307 | | | | | | Other liabilities | | | | 283 | | | Other liabilities | | | 1,121 | | | | | | | | | | | | | | | | | | $ | 1,540 | | | | | $ | 2,428 | | | Interest rate swap | | | Other current liabilities | | $ | 205 | | | Other current liabilities | | $ | 1,112 | | | | | | | | | | | | | | Other liabilities | | | — | | | Other liabilities | | | 200 | | | | | | | | | | $ | 205 | | | | | $ | 1,312 | | Derivatives not designated as hedging instruments: | Derivatives not designated as hedging instruments: | | | | | | | | | | | | | | | | | | | | Commodity-related derivatives | | | Other current liabilities | | | $ | 1,527 | | | Other current liabilities | | $ | 430 | | | Other current liabilities | | $ | 1,002 | | | Other current liabilities | | $ | — | | | | | Other liabilities | | | | 53 | | | Other liabilities | | | — | | | Other liabilities | | | 1,353 | | | Other liabilities | | | 2,567 | | | | | | | | | | | | | | | | $ | 2,355 | | | | | $ | 2,567 | | | | | | $ | 1,580 | | | | | $ | 430 | | | | | | | | | | | | | | |
The following summarizes the reconciliation of the beginning and ending balances of assets and liabilities measured at fair value on a recurring basis using significant unobservable inputs: | | | | Fair Value Measurement Using Significant
Unobservable Inputs (Level 3) | | | Fair Value Measurement Using Significant Unobservable Inputs (Level 3) | | | | | Fiscal 2014 | | | Fiscal 2013 | | | Fiscal 2016 | | | Fiscal 2015 | | | | | Assets | | Liabilities | | | Assets | | Liabilities | | | Assets | | | Liabilities | | | Assets | | | Liabilities | | Beginning balance of over-the-counter options | | $ | 1,847 | | | $ | — | | | $ | 5,002 | | | $ | 1,209 | | | $ | 2,781 | | | $ | 347 | | | $ | 1,512 | | | $ | — | | Beginning balance realized during the period | | | (1,166 | ) | | | — | | | | (4,400 | ) | | (1,182 | ) | | | (2,781 | ) | | | (347 | ) | | | (1,450 | ) | | | — | | Contracts purchased during the period | | | 1,145 | | | | — | | | | 1,825 | | | | — | | | | 809 | | | | — | | | | 2,067 | | | | 347 | | Change in the fair value of outstanding contracts | | | (314 | ) | | | — | | | | (580 | ) | | (27 | ) | | | — | | | | — | | | | 652 | | | | — | | | | | | | | | | | | | | | | Ending balance of over-the-counter options | | $ | 1,512 | | | $ | — | | | $ | 1,847 | | | $ | — | | | $ | 809 | | | $ | — | | | $ | 2,781 | | | $ | 347 | | | | | | | | | | | | | | | |
As of September 27, 201424, 2016 and September 28, 2013,26, 2015, the Partnership’s outstanding commodity-related derivatives had a weighted average maturity of approximately foursix and fiveseven months, respectively. The effect of the Partnership’s derivative instruments on the consolidated statements of operations for fiscal 2014, 20132016, 2015 and 20122014 are as follows: | | | | | | | | | | | | | | | | Amount of
(Losses) Gains
Recognized in OCI
(Effective Portion) | | | Gains (Losses) Reclassified from
Accumulated OCI into Income
(Effective Portion) | | Derivatives in Cash Flow Hedging Relationships: | | | Location | | | Amount | | Interest rate swaps: | | | | | | | | | | | | | Fiscal 2014 | | $ | (518 | ) | | | Interest expense | | | $ | (1,406 | ) | | | | | | | | | | | | | | Fiscal 2013 | | $ | 584 | | | | Interest expense | | | $ | (2,465 | ) | | | | | | | | | | | | | | Fiscal 2012 | | $ | (3,561 | ) | | | Interest expense | | | $ | (2,680 | ) | | | | | | | | | | | | | |
| | Amount of Gains | | | Gains (Losses) Reclassified from | | | | (Losses) | | | Accumulated OCI into Income | | | | Recognized in OCI | | | (Effective Portion) | | Derivatives in Cash Flow Hedging Relationships | | (Effective Portion) | | | Location | | Amount | | Interest rate swaps: | | | | | | | | | | | Fiscal 2016 | | $ | 6 | | | Interest expense | | $ | (1,100 | ) | | | | | | | | | | | | Fiscal 2015 | | $ | (1,159 | ) | | Interest expense | | $ | (1,388 | ) | | | | | | | | | | | | Fiscal 2014 | | $ | (518 | ) | | Interest expense | | $ | (1,406 | ) |
| | | | | | | | | Derivatives Not Designated as Hedging Instruments: | | Location of Gains
(Losses) Recognized in
Income | | | Amount of
Unrealized
Gains
(Losses)
Recognized
in Income | | Commodity-related derivatives: | | | | | | | | | Fiscal 2014 | | | Cost of products sold | | | $ | 306 | | | | | | | | | | | Fiscal 2013 | | | Cost of products sold | | | $ | (4,318 | ) | | | | | | | | | | Fiscal 2012 | | | Cost of products sold | | | $ | 4,649 | | | | | | | | | | |
| | Unrealized Gains (Losses) Recognized in Income | | Derivatives Not Designated as Hedging Instruments | | Location | | Amount | | Commodity-related derivatives: | | | | | | | Fiscal 2016 | | Cost of products sold | | $ | (1,190 | ) | | | | | | | | Fiscal 2015 | | Cost of products sold | | $ | 1,855 | | | | | | | | | Fiscal 2014 | | Cost of products sold | | $ | 306 | |
The following table presents the fair value of the Partnership’s recognized derivative assets and liabilities on a gross basis and amounts offset on the consolidated balance sheets subject to enforceable master netting arrangements or similar agreements: | | | As of September 24, 2016 | | | | | | | | | | | | | | | | | | Net amounts | | | | | As of September 27, 2014 | | | | | | | | | | | presented in the | | | | | Gross
amounts | | | Effects
of
netting | | Net
amounts
presented
in the
balance
sheet | | | Gross amounts | | | Effects of netting | | | balance sheet | | Asset Derivatives | | | | | | | | | | | | | | | | | | | Commodity-related derivatives | | $ | 9,533 | | | $ | (5,547 | ) | | $ | 3,986 | | | $ | 6,842 | | | $ | (1,990 | ) | | $ | 4,852 | | Interest rate swap | | | 2,139 | | | | (2,139 | ) | | | — | | | | 230 | | | | (230 | ) | | | — | | | | | | | | | | | | | $ | 7,072 | | | $ | (2,220 | ) | | $ | 4,852 | | | | $ | 11,672 | | | $ | (7,686 | ) | | $ | 3,986 | | | | | | | | | | | | | | | | | | | | | | | | | Liability Derivatives | | | | | | | | | | | | | | | | | | | Commodity-related derivatives | | $ | 7,127 | | | $ | (5,547 | ) | | $ | 1,580 | | | $ | 4,345 | | | $ | (1,990 | ) | | $ | 2,355 | | Interest rate swap | | | 3,679 | | | | (2,139 | ) | | | 1,540 | | | | 435 | | | | (230 | ) | | | 205 | | | | | | | | | | | | | $ | 4,780 | | | $ | (2,220 | ) | | $ | 2,560 | | | | $ | 10,806 | | | $ | (7,686 | ) | | $ | 3,120 | | | | | | | | | | | | | |
| | | As of September 26, 2015 | | | | | | | | | | | | | | | | | | Net amounts | | | | | As of September 28, 2013 | | | | | | | | | | | presented in the | | | | | Gross
amounts | | | Effects
of
netting | | Net
amounts
presented
in the
balance
sheet | | | Gross amounts | | | Effects of netting | | | balance sheet | | Asset Derivatives | | | | | | | | | | | | | | | | | | | Commodity-related derivatives | | $ | 3,634 | | | $ | (372 | ) | | $ | 3,262 | | | $ | 13,063 | | | $ | (5,565 | ) | | $ | 7,498 | | Interest rate swap | | | 2,804 | | | | (2,804 | ) | | | — | | | | 740 | | | | (740 | ) | | | — | | | | | | | | | | | | | $ | 13,803 | | | $ | (6,305 | ) | | $ | 7,498 | | | | $ | 6,438 | | | $ | (3,176 | ) | | $ | 3,262 | | | | | | | | | | | | | | | | | | | | | | | | | Liability Derivatives | | | | | | | | | | | | | | | | | | | Commodity-related derivatives | | $ | 802 | | | $ | (372 | ) | | $ | 430 | | | $ | 8,132 | | | $ | (5,565 | ) | | $ | 2,567 | | Interest rate swap | | | 5,232 | | | | (2,804 | ) | | | 2,428 | | | | 2,052 | | | | (740 | ) | | | 1,312 | | | | | | | | | | | | | $ | 10,184 | | | $ | (6,305 | ) | | $ | 3,879 | | | | $ | 6,034 | | | $ | (3,176 | ) | | $ | 2,858 | | | | | | | | | | | | | |
The Partnership had no$206 and $553 posted cash collateral as of September 27, 201424, 2016 and September 28, 201326, 2015, respectively, with its brokers for outstanding commodity-related derivatives. Concentrations. The Partnership’s principal customers are residential and commercial end users of propane and fuel oil and refined fuels served by approximately 710675 locations in 41 states. No single customer accounted for more than 10% of revenues during fiscal 2014, 20132016, 2015 or 20122014 and no concentration of receivables exists as of September 27, 201424, 2016 or September 28, 2013.26, 2015. During fiscal 2014,2016, Crestwood MidstreamEquity Partners L.P., Targa Liquids Marketing and Trade andLLC, Enterprise Products Partners L.P. and Phillips 66 Company provided approximately 19%, 14%, 13% and 13%10% of ourthe Partnership’s total propane purchases, respectively. No other single supplier accounted for more than 10% of the Partnership’s propane purchases in fiscal 2014.2016. The Partnership believes that, if supplies from any of these suppliers were interrupted, it would be able to secure adequate propane supplies from other sources without a material disruption of its operations. Credit Risk.Risk. Exchange-traded futures and options contracts are traded on and guaranteed by the 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 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 2020 Senior Notes, 2021 Senior Notes, and 2024 Senior Notes and 2025 Senior Notes was $263,250, $363,489$360,893, $534,188 and $508,594,$253,438, respectively, as of September 27, 2014.24, 2016. 12. Commitments and Contingencies
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 $31,849, $33,036$29,171, $32,737 and $23,593$31,849 for fiscal 2016, 2015 and 2014, 2013 and 2012, respectively. Future minimum rental commitments under noncancelable operating lease agreements as of September 27, 201424, 2016 are as follows: | Fiscal Year | | Minimum
Lease
Payments | | | Minimum Lease Payments | | 2015 | | $ | 25,266 | | | 2016 | | | 17,781 | | | 2017 | | | 12,199 | | | $ | 22,580 | | 2018 | | | 9,224 | | | | 18,796 | | 2019 | | | 6,131 | | | | 15,050 | | 2020 and thereafter | | | 7,469 | | | 2020 | | | | 12,519 | | 2121 | | | | 9,497 | | 2022 and thereafter | | | | 15,841 | |
Contingencies.
Self Insurance.Contingencies
Self-Insurance. As described in Note 2, the Partnership is self-insured for general and product, workers’ compensation and automobile liabilities up to predetermined amounts above which third party insurance applies. At September 27, 201424, 2016 and September 28, 2013,26, 2015, the Partnership had accrued liabilities of $62,450$59,676 and $58,152,$57,083, respectively, representing the total estimated losses under these self-insurance programs. For the portion of the estimated liability that exceeds insurance deductibles, the Partnership records an asset within other assets (or prepaid expenses and other current assets, as applicable) related to the amount of the liability expected to be covered by insurance which amounted to $18,410$15,524 and $18,330$15,783 as of September 27, 201424, 2016 and September 28, 2013,26, 2015, respectively. Legal Matters.The Partnership’s operations are subject to 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 as a result of these operating hazards and risks, and as a result of other aspects of its business. Although any litigation is inherently uncertain, based on past experience, the information currently available to the Partnership, and the amount of its accrued insurance liabilities, the Partnership does not believe that currently pending or threatened litigation matters, or known claims or known contingent claims, will have a material adverse effect on its results of operations, financial condition or cash flow. 13.
The Partnership has residual value guarantees associated with certain of its operating leases, related primarily to transportation equipment, with remaining lease periods scheduled to expire periodically through fiscal 2021.2023. Upon completion of the lease period, the Partnership guarantees that the fair value of the equipment will equal or exceed the guaranteed amount, or the Partnership will pay the lessor the difference. 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 the Partnership could be required to make under these leasing arrangements, assuming the equipment is deemed worthless at the end of the lease term, was $14,122$15,950 as of September 27, 2014.24, 2016. The fair value of residual value guarantees for outstanding operating leases was de minimis as of September 27, 201424, 2016 and September 28, 2013.26, 2015. 14. Amounts Reclassified Out of Accumulated Other Comprehensive Income
14. | Amounts Reclassified Out of Accumulated Other Comprehensive Income |
The following table summarizes amounts reclassified out of accumulated other comprehensive (loss) income for the years ended September 27, 2014,24, 2016, September 28, 201326, 2015 and September 29, 2012:27, 2014: | | | | | | | | | | | | | | | | | | | | For the year ended September 27, 2014 | | | | | Gains
and
Losses
on Cash
Flow
Hedges | | | Pension
Benefits | | | Postretirement
Benefits | | | Total | | Balance, beginning of period | | $ | (2,428 | ) | | $ | (49,987 | ) | | $ | 5,062 | | | $ | (47,353 | ) | | | | | | | | | | | | | | | | | | Other comprehensive income before reclassifications | | | (518 | ) | | | — | | | | — | | | | (518 | ) | Amounts reclassified from accumulated other comprehensive income | | | 1,406 | (a) | | | 953 | (b) | | | (393 | )(b) | | | 1,966 | | | | | | | | | | | | | | | | | | | Net current period other comprehensive income | | | 888 | | | | 953 | | | | (393 | ) | | | 1,448 | | | | | | | | | | | | | | | | | | | Balance, end of period | | $ | (1,540 | ) | | $ | (49,034 | ) | | $ | 4,669 | | | $ | (45,905 | ) | | | | | | | | | | | | | | | | | |
| | | | | | | | | | Year Ended | | | | | For the year ended September 28, 2013 | | | September 24, | | | September 26, | | | September 27, | | | | | Gains
and
Losses
on Cash
Flow
Hedges | | Pension
Benefits | | Postretirement
Benefits | | Total | | | 2016 | | | 2015 | | | 2014 | | Cash Flow Hedges | | | | | | | | | | | | | | Balance, beginning of period | | $ | (5,477 | ) | | $ | (59,398 | ) | | $ | 3,768 | | | $ | (61,107 | ) | | $ | (1,311 | ) | | $ | (1,540 | ) | | $ | (2,428 | ) | | | | | | | | | | | | | | | Other comprehensive income before reclassifications | | | 584 | | | | — | | | | — | | | | 584 | | | Amounts reclassified from accumulated other comprehensive income | | | 2,465 | (a) | | | 9,411 | (b) | | | 1,294 | (b) | | | 13,170 | | | | | | | | | | | | | | | | | Net current period other comprehensive income | | | 3,049 | | | | 9,411 | | | | 1,294 | | | | 13,754 | | | | | | | | | | | | | | | | | Other comprehensive income before reclassifications: | | | | | | | | | | | | | | Unrealized gains (losses) | | | | 6 | | | | (1,159 | ) | | | (518 | ) | Reclassifications to earnings: | | | | | | | | | | | | | | Realized losses (a) | | | | 1,100 | | | | 1,388 | | | | 1,406 | | Other comprehensive income | | | | 1,106 | | | | 229 | | | | 888 | | Balance, end of period | | $ | (2,428 | ) | | $ | (49,987 | ) | | $ | 5,062 | | | $ | (47,353 | ) | | $ | (205 | ) | | $ | (1,311 | ) | | $ | (1,540 | ) | | | | | | | | | | | | | | | | | | | | | | | | | | Pension Benefits | | | | | | | | | | | | | | Balance, beginning of period | | | $ | (52,836 | ) | | $ | (49,034 | ) | | $ | (49,987 | ) | Other comprehensive income before reclassifications: | | | | | | | | | | | | | | Net change in funded status of benefit plan | | | | (5,773 | ) | | | (10,324 | ) | | | (3,539 | ) | Reclassifications to earnings: | | | | | | | | | | | | | | Recognition of net actuarial loss for pension settlement (b) | | | | 2,000 | | | | 2,000 | | | | — | | Amortization of net loss (b) | | | | 5,218 | | | | 4,522 | | | | 4,492 | | Other comprehensive income (loss) | | | | 1,445 | | | | (3,802 | ) | | | 953 | | Balance, end of period | | | $ | (51,391 | ) | | $ | (52,836 | ) | | $ | (49,034 | ) | | | | | | | | | | | | | | | Postretirement Benefits | | | | | | | | | | | | | | Balance, beginning of period | | | $ | 5,264 | | | $ | 4,669 | | | $ | 5,062 | | Other comprehensive income before reclassifications: | | | | | | | | | | | | | | Net change in plan obligation | | | | 1,198 | | | | 1,281 | | | | 278 | | Reclassifications to earnings: | | | | | | | | | | | | | | Amortization of prior service credits (b) | | | | (399 | ) | | | (490 | ) | | | (490 | ) | Amortization of net gain (b) | | | | (299 | ) | | | (196 | ) | | | (181 | ) | Other comprehensive income (loss) | | | | 500 | | | | 595 | | | | (393 | ) | Balance, end of period | | | $ | 5,764 | | | $ | 5,264 | | | $ | 4,669 | | | | | | | | | | | | | | | | Accumulated Other Comprehensive Income (Loss) | | | | | | | | | | | | | | Balance, beginning of period | | | $ | (48,883 | ) | | $ | (45,905 | ) | | $ | (47,353 | ) | Other comprehensive income before reclassifications | | | | (4,569 | ) | | | (10,202 | ) | | | (3,779 | ) | Recognition of net actuarial loss for pension settlement | | | | 2,000 | | | | 2,000 | | | | — | | Reclassifications to earnings | | | | 5,620 | | | | 5,224 | | | | 5,227 | | Other comprehensive income (loss) | | | | 3,051 | | | | (2,978 | ) | | | 1,448 | | Balance, end of period | | | $ | (45,832 | ) | | $ | (48,883 | ) | | $ | (45,905 | ) |
| | | | | | | | | | | | | | | | | | | | For the year ended September 29, 2012 | | | | | Gains
and
Losses
on Cash
Flow
Hedges | | | Pension
Benefits | | | Postretirement
Benefits | | | Total | | Balance, beginning of period | | $ | (4,596 | ) | | $ | (59,503 | ) | | $ | 4,183 | | | $ | (59,916 | ) | | | | | | | | | | | | | | | | | | Other comprehensive income before reclassifications | | | (3,561 | ) | | | — | | | | — | | | | (3,561 | ) | Amounts reclassified from accumulated other comprehensive income | | | 2,680 | (a) | | | 105 | (b) | | | (415 | )(b) | | | 2,370 | | | | | | | | | | | | | | | | | | | Net current period other comprehensive income | | | (881 | ) | | | 105 | | | | (415 | ) | | | (1,191 | ) | | | | | | | | | | | | | | | | | | Balance, end of period | | $ | (5,477 | ) | | $ | (59,398 | ) | | $ | 3,768 | | | $ | (61,107 | ) | | | | | | | | | | | | | | | | | |
(a) | Reclassification of realized losses on cash flow hedges are recognized in interest expense. |
(b) | These amounts are included in the computation of net periodic benefit cost. See Note 10, “Employee Benefit Plans”. |
15. Public Offerings
On May 17, 2013, the Partnership sold 2,700,000 Common Units in a public offering at a price of $48.16 per Common Unit, realizing proceeds of $124,684, net of underwriting commissions and other offering expenses. On May 22, 2013, following the underwriters’ exercise of their over-allotment option, the Partnership sold an additional 405,000 Common Units at $48.16 per Common Unit, generating additional proceeds of $18,760, net of underwriting commissions. The net proceeds from the offering, including the net proceeds from the underwriters’ exercise of their over-allotment option, were used to redeem $133,400 of the Partnership’s 2021 Senior Notes in August 2013.
15. | 16. Segment Information
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The Partnership manages and evaluates its operations in fivefour 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. The fuel oil and refined fuels segment is primarily engaged in the retail distribution of fuel oil, diesel, kerosene and gasoline to residential and commercial customers for use primarily as a source of heat in homes and buildings. 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 Suburban Franchising subsidiaries. ventilation.
The following table presents certain data by reportable segment and provides a reconciliation of total operating segment information to the corresponding consolidated amounts for the periods presented: | | | | | | | | Year Ended | | | | | Year Ended | | | September 24, | | | September 26, | | | September 27, | | | | | September 27,
2014 | | September 28,
2013 | | September 29,
2012 | | | 2016 | | | 2015 | | | 2014 | | Revenues: | | | | | | | | | | | | | | | | | | | Propane | | $ | 1,606,840 | | | $ | 1,357,102 | | | $ | 843,648 | | | $ | 884,169 | | | $ | 1,176,980 | | | $ | 1,606,840 | | Fuel oil and refined fuels | | | 194,684 | | | 208,957 | | | 114,288 | | | | 68,759 | | | | 127,495 | | | | 194,684 | | Natural gas and electricity | | | 87,093 | | | 79,432 | | | 67,419 | | | | 50,763 | | | | 66,865 | | | | 87,093 | | All other | | | 49,640 | | | 58,115 | | | 38,103 | | | | 42,420 | | | | 45,639 | | | | 49,640 | | | | | | | | | | | | | Total revenues | | $ | 1,938,257 | | | $ | 1,703,606 | | | $ | 1,063,458 | | | $ | 1,046,111 | | | $ | 1,416,979 | | | $ | 1,938,257 | | | | | | | | | | | | | | | | | | | | | | | | Operating income: | | | | | | | | Operating income (loss): | | | | | | | | | | | | | | Propane | | $ | 295,916 | | | $ | 287,473 | | | $ | 142,548 | | | $ | 184,213 | | | $ | 280,761 | | | $ | 295,916 | | Fuel oil and refined fuels | | | 2,473 | | | | (2,799 | ) | | | 890 | | | | 5,649 | | | | 7,621 | | | | 2,473 | | Natural gas and electricity | | | 10,818 | | | | 11,565 | | | | 6,991 | | | | 10,755 | | | | 14,614 | | | | 10,818 | | All other | | | (25,644 | ) | | | (26,483 | ) | | | (17,239 | ) | | | (25,945 | ) | | | (25,409 | ) | | | (25,644 | ) | Corporate | | | (93,437 | ) | | | (92,780 | ) | | | (91,533 | ) | | | (84,266 | ) | | | (99,829 | ) | | | (93,437 | ) | | | | | | | | | | | | Total operating income | | | 190,126 | | | | 176,976 | | | | 41,657 | | | | 90,406 | | | | 177,758 | | | | 190,126 | | | | | | | | | | | | | | | | Reconciliation to net income: | | | | | | | | | | | | | | | | | | | Loss on debt extinguishment | | | 11,589 | | | | 2,144 | | | | 2,249 | | | | 292 | | | | 15,072 | | | | 11,589 | | Interest expense, net | | | 83,261 | | | | 95,427 | | | | 38,633 | | | | 75,086 | | | | 77,634 | | | | 83,261 | | Provision for income taxes | | | 767 | | | | 607 | | | | 137 | | | | 588 | | | | 700 | | | | 767 | | | | | | | | | | | | | Net income | | $ | 94,509 | | | $ | 78,798 | | | $ | 638 | | | $ | 14,440 | | | $ | 84,352 | | | $ | 94,509 | | | | | | | | | | | | | | | | | | | | | | | | Depreciation and amortization: | | | | | | | | | | | | | | | | | | | Propane | | $ | 106,491 | | | $ | 104,533 | | | $ | 34,826 | | | $ | 110,067 | | | $ | 110,728 | | | $ | 106,491 | | Fuel oil and refined fuels | | | 5,429 | | | | 4,634 | | | | 3,652 | | | | 2,725 | | | | 3,885 | | | | 5,429 | | Natural gas and electricity | | | 46 | | | | 198 | | | | 464 | | | | 3 | | | | 8 | | | | 46 | | All other | | | 699 | | | | 638 | | | | 345 | | | | 304 | | | | 288 | | | | 699 | | Corporate | | | 23,734 | | | | 20,381 | | | | 7,747 | | | | 16,517 | | | | 18,385 | | | | 23,734 | | | | | | | | | | | | | Total depreciation and amortization | | $ | 136,399 | | | $ | 130,384 | | | $ | 47,034 | | | $ | 129,616 | | | $ | 133,294 | | | $ | 136,399 | | | | | | | | | | | | |
| | | | | | As of | | | | | As of | | | September 24, | | | September 26, | | | | | September 27,
2014 | | | September 28,
2013 | | | 2016 | | | 2015 | | Assets: | | | | | | | | | | | | | Propane | | $ | 2,365,320 | | | $ | 2,452,909 | | | $ | 2,141,108 | | | $ | 2,209,343 | | Fuel oil and refined fuels | | | 69,360 | | | | 77,473 | | | | 53,266 | | | | 58,077 | | Natural gas and electricity | | | 13,992 | | | | 16,789 | | | | 13,415 | | | | 13,253 | | All other | | | 3,342 | | | | 3,860 | | | | 2,185 | | | | 2,888 | | Corporate | | | 157,349 | | | | 176,956 | | | | 85,995 | | | | 202,169 | | | | | | | | | | Total assets | | $ | 2,609,363 | | | $ | 2,727,987 | | | $ | 2,295,969 | | | $ | 2,485,730 | | | | | | | | | |
INDEX TO FINANCIAL STATEMENT SCHEDULE SUBURBAN PROPANE PARTNERS, L.P. AND SUBSIDIARIES
SCHEDULE II SUBURBAN PROPANE PARTNERS, L.P. AND SUBSIDIARIES VALUATION AND QUALIFYING ACCOUNTS (in thousands) | | | | | | | | | | | | Balance at Beginning of Period | | | Charged (credited) to Costs and Expenses | | | Other Additions | | | Deductions (a) | | | Balance at End of Period | | Year Ended September 27, 2014 | | | | | | | | | | | | | | | | | | | | | | | | | Balance at
Beginning
of Period | | | Charged
(credited) to Costs
and Expenses | | Other
Additions | | | Deductions (a) | | Balance
at End
of Period | | | | | | | | | | | | | | | | | | | | | | Year Ended September 29, 2012 | | | | | | | | | | | | Allowance for doubtful accounts | | $ | 6,960 | | | $ | 838 | | | $ | — | | | $ | (3,451 | ) | | $ | 4,347 | | | $ | 6,786 | | | $ | 11,933 | | | $ | — | | | $ | (7,597 | ) | | $ | 11,122 | | Valuation allowance for deferred tax assets | | | 40,202 | | | | (3,567 | ) | | | — | | | | — | | | 36,635 | | | | 46,406 | | | | 5,458 | | | | — | | | | — | | | | 51,864 | | Year Ended September 28, 2013 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Year Ended September 26, 2015 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Allowance for doubtful accounts | | $ | 4,347 | | | $ | 6,717 | | | $ | — | | | $ | (4,278 | ) | | $ | 6,786 | | | $ | 11,122 | | | $ | (397 | ) | | $ | — | | | $ | (7,205 | ) | | $ | 3,520 | | Valuation allowance for deferred tax assets | | | 36,635 | | | | 9,771 | | | | — | | | | — | | | 46,406 | | | | 51,864 | | | | 2,181 | | | | — | | | | — | | | | 54,045 | | Year Ended September 27, 2014 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Year Ended September 24, 2016 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Allowance for doubtful accounts | | $ | 6,786 | | | $ | 11,933 | | | $ | — | | | $ | (7,597 | ) | | $ | 11,122 | | | $ | 3,520 | | | $ | 1,146 | | | $ | — | | | $ | (2,225 | ) | | $ | 2,441 | | Valuation allowance for deferred tax assets | | | 46,406 | | | | 5,458 | | | | — | | | | — | | | $ | 51,864 | | | | 54,045 | | | | 4,737 | | | | — | | | | — | | | | 58,782 | |
(a) | Represents amounts that did not impact earnings. |
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