Item 1. Business.
Recent Developments
On November 24, 2009, we entered into a secured credit facility which provides borrowing capacity of up to $525 million in the form of a $450 million general partnership credit facility and a $75 million working capital credit facility. This facility replaces our former senior credit facility due 2010. This new facility will mature on November 22, 2013. Borrowings under this new facility are available for working capital needs, future acquisitions, capital expenditures and other general partnership purposes, including the refinancing of existing indebtedness under the former credit facility.
The new secured credit facility contains various affirmative and negative covenants and default provisions, as well as requirements with respect to the maintenance of specified financial ratios and limitations on making investments, permitting liens and entering into other debt obligations. All borrowings under the facility bear interest, at our option, subject to certain limitations, at a rate equal to the following:
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the Alternate Base Rate, which is defined as the higher of i) the federal funds rate plus 0.50%; ii) JP Morgan’s prime rate; or iii) the Adjusted LIBO Rate plus 1%; plus a margin varying from 1.50% to 2.75%; or
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the Adjusted LIBO Rate, which is defined as the LIBO Rate plus a margin varying from 2.50% to 3.75%.
General
Inergy, L.P., a publicly traded Delaware limited partnership, was formed on March 7, 2001 and we closed on our initial public offering on July 31, 2001. We own and operate a growing, geographically diverse retail and wholesale propane supply, marketing and distribution business. We also own and operate a growing midstream business that includes three natural gas storage facilities (“Stagecoach”, “Steuben” and “Thomas Corners”), a liquefied petroleum gas (“LPG”) storage facility (“Bath”), a natural gas liquids (“NGL”) business and a solution-mining and salt production company (“US Salt”). For the fiscal year ended September 30, 2009, we sold and physically delivered 310.0 million gallons of propane to retail customers and 380.6 million gallons of propane to wholesale customers.
We believe we are the fifth largest propane retailer in the United States based on retail propane gallons sold. Our propane business includes the retail marketing, sale and distribution of propane, including the sale and lease of propane supplies and equipment, to residential, commercial, industrial and agricultural customers. We market our propane products under various regional brand names. As of October 30, 2009, we serve approximately 700,000 retail customers in 28 states from 312 customer service centers, which have an aggregate of 31.1 million gallons of above-ground propane storage. In addition to our retail propane business, we operate a wholesale supply, marketing and distribution business, providing propane procurement, transportation and supply and price risk management services to our customer service centers, as well as to independent dealers, multistate marketers, petrochemical companies, refinery and gas processors and a number of other NGL marketing and distribution companies in 40 states, primarily in the Midwest, Northeast and South.
We also own and operate a midstream business which includes the following assets:
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the Stagecoach natural gas storage facility, a high performance, multi-cycle natural gas storage facility with 26.25 bcf of working gas capacity, a maximum withdrawal capability of 500 MMcf/day and a maximum injection capability of 250 MMcf/day. Located 150 miles northwest of New York City, the Stagecoach facility is the closest natural gas storage facility to the northeastern United States market. Stagecoach is connected to Tennessee Gas Pipeline Company’s 300-Line and the newly constructed Millennium pipeline. The facility is fee-based and is currently 100% contracted primarily with investment grade-rated companies with term contracts having a weighted average maturity extending to September 2014.
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an NGL business near Bakersfield, California, which includes a 25.0 MMcf/day natural gas processing plant, a 12,000 bpd NGL fractionation plant, an 8,000 bpd butane isomerization plant, NGL rail and truck terminals, a 24.0 million gallon NGL storage facility and NGL transportation/marketing operations.
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the Bath LPG Storage Facility, a 1.7 million barrel salt cavern LPG storage facility located near Bath, New York, approximately 210 miles northwest of New York City and 60 miles from our Stagecoach facility. The facility is supported by both rail and truck terminals capable of loading/unloading 20 - 23 rail cars per day and 17 truck transports per day.
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100% of the membership interests of Arlington Storage Company, LLC (“ASC”). ASC is the majority owner and operator of the Steuben Gas Storage Company (“Steuben”), which owns a 6.2 bcf natural gas storage facility located in Steuben County, New York.
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our recently completed development of Thomas Corners, a 7 bcf natural gas storage facility also located in Steuben County, New York. This facility was placed in service in November 2009.
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US Salt, an industry-leading solution mining and salt production company located in Schuyler County, New York, between our Stagecoach and Steuben natural gas storage facilities. US Salt produces and sells over 300,000 tons of salt each year. The solution mining process used by US Salt creates salt caverns that can be developed into usable natural gas storage capacity.
We have grown primarily through acquisitions and to a lesser extent through organic expansion projects. Since the inception of our predecessor in November 1996 through September 30, 2009, we have acquired 84 companies for an aggregate purchase price of approximately $1.8 billion, including working capital, assumed liabilities and acquisition costs. The acquisitions include the assets of three propane companies acquired during fiscal 2009 for an aggregate purchase price, net of cash acquired, of $11.8 million.
The following chart sets forth information about each business we acquired during the fiscal year ended September 30, 2009, and through the date of this filing:
The address of our principal executive offices is Two Brush Creek Boulevard, Suite 200, Kansas City, Missouri, 64112 and our telephone number at this location is 816-842-8181. Our common units trade on the NASDAQ Global Select National Market under the symbol “NRGY”. We electronically file certain documents with the Securities and Exchange Commission (“SEC”). We file annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K (as appropriate), along with any related amendments and supplements. From time-to-time, we also may file registration and related statements pertaining to equity or debt offerings. You may read and download our SEC filings over the internet from several commercial document retrieval services as well as at the SEC’s website at www.sec.gov. You may also read and copy our SEC filings at the SEC’s public reference room located at 100 F. Street, N.E., Washington, D.C. 20549. Please call the SEC 1-800-SEC-0330 for further information concerning the public reference room and any applicable copy charges. In addition, our SEC filings are available at no cost after the filing thereof on our website at www.inergypropane.com. Please note that any internet addresses provided in this Form 10-K are for information purposes only and are not intended to be hyperlinks. Accordingly, no information found and/or provided at such internet addresses is intended or deemed to be incorporated by reference herein.
Industry Background and Competition
Propane
Propane, a by-product of natural gas processing and petroleum refining, is a clean-burning energy source recognized for its transportability and ease of use relative to alternative stand-alone energy sources. Our retail propane business consists principally of transporting propane to our customer service centers and other distribution areas and then to tanks located on our customers’ premises. Retail propane falls into four broad categories: residential, industrial, commercial and agricultural. Residential customers use propane primarily for space and water heating. Industrial customers use propane primarily as fuel for forklifts and stationary engines, to fire furnaces, as a cutting gas, in mining operations and in other process applications. Commercial customers, such as restaurants, motels, laundries and commercial buildings, use propane in a variety of applications, including cooking, heating and drying. In the agricultural market, propane is primarily used for tobacco curing, crop drying, poultry brooding and weed control.
Propane is extracted from natural gas or oil wellhead gas at processing plants or separated from crude oil during the refining process. Propane 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, it is usable as a flammable gas. Propane is colorless and odorless; an odorant is added to allow its detection. Propane is clean-burning, producing negligible amounts of pollutants when consumed.
The retail market for propane is seasonal because it is used primarily for heating in residential and commercial buildings. Approximately 70% of our retail propane volume is sold during the peak heating season from October through March. Consequently, sales and operating profits are generated mostly in the first and fourth calendar quarters of each calendar year.
Propane competes primarily with natural gas, electricity and fuel oil as an energy source, principally on the basis of price, availability and portability. Propane is more expensive than natural gas on an equivalent BTU basis in locations served by natural gas, but serves as an alternative 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 extension of natural gas pipelines tends to displace propane distribution in areas affected, we believe that new opportunities for propane sales arise as more geographically remote neighborhoods are developed. Propane is generally less expensive to use than electricity for space heating, water heating, clothes drying and cooking. Although propane is similar to fuel oil in certain applications and market demand, propane and fuel oil compete to a lesser extent than propane and natural gas, primarily because of the cost of converting to fuel oil. The costs associated with switching from appliances that use fuel oil to appliances that use propane are a significant barrier to switching. By contrast, natural gas can generally be substituted for propane in appliances designed to use propane as a principal fuel source.
In addition to competing with alternative energy sources, we compete with other companies engaged in the retail propane distribution business. Competition in the propane industry is highly fragmented and generally occurs on a local basis with other large full-service, multi-state propane marketers, smaller local independent marketers and farm cooperatives. Based on industry publications, we believe that the 10 largest retailers account for 37% of the total retail sales of propane in the United States and that no single marketer has a greater than 10% share of the total retail market in the United States. Most of our customer service centers compete with several marketers or distributors. Each customer service center operates in its own competitive environment because retail marketers tend to locate in close proximity to customers. Our typical customer service center generally has an effective marketing radius of approximately 25 miles, although in certain rural areas the marketing radius may be extended by a satellite location.
The ability to compete effectively further depends on the reliability of service, responsiveness to customers and the ability to maintain competitive prices. We believe that our safety programs, policies and procedures are more
comprehensive than many of our smaller, independent competitors and give us a competitive advantage over such retailers. We also believe that our service capabilities and customer responsiveness differentiate us from many of these smaller competitors. Our employees are on call 24-hours and seven-days-a-week for emergency repairs and deliveries.
Retail propane distributors typically price retail usage based on a per gallon margin over wholesale costs. As a result, distributors generally seek to maintain their operating margins by passing costs through to customers, thus insulating themselves from volatility in wholesale propane prices.
The propane distribution industry is characterized by a large number of relatively small, independently owned and locally operated distributors. Each year, a number of these local distributors have sought to sell their business for reasons that include, among others, retirement and estate planning. In addition, the propane industry faces increasing environmental regulations and escalating capital requirements needed to acquire advanced, customer-oriented technologies. Primarily as a result of these factors, the industry is undergoing consolidation and we, as well as other national and regional distributors, have been active consolidators in the propane market. In recent years, an active, competitive market has existed for the acquisition of propane assets and businesses. We expect this acquisition market to continue for the foreseeable future.
The wholesale propane business is highly competitive. Our competitors in the wholesale business include producers and independent regional wholesalers. We believe that our wholesale supply and distribution business provides us with a stronger regional presence and a reasonably secure, efficient supply base and positions us well for expansion through acquisitions.
Midstream
We own, as part of our midstream operations, a high-performance, multi-cycle natural gas storage facility (Stagecoach) in New York that we acquired in August 2005. We also own an NGL business in California, which includes a 25.0 MMcf/day natural gas processing plant, a 12,000 bpd NGL fractionation plant, an 8,000 bpd butane isomerization plant, NGL rail and truck terminals, a 24.0 million gallon NGL storage facility and NGL transportation/marketing operations. We also own a 1.7 million barrel salt cavern liquefied petroleum gas storage facility near Bath, New York. In October 2007, we acquired a controlling interest in Steuben Gas Storage Company (“Steuben”), which owns a 6.2 bcf natural gas storage facility located in Steuben County, New York. In August 2008, we acquired US Salt, an industry leading solution mining and salt production company located in Schuyler County, New York. The solution mining process used by US Salt creates salt caverns that can be developed into usable natural gas storage and LPG storage capacity. In November 2009, we completed our development of Thomas Corners, a 7 bcf natural gas storage facility located in Steuben County, New York. We believe these businesses complement our existing propane operations and provide us with added long-term strategic benefits.
Natural Gas Storage Business
According to the Energy Information Administration’s consumption data, natural gas supplies approximately 25% of U.S. energy. In recent years, the market for natural gas has experienced increasingly volatile prices, due in part to the following factors:
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weather-related demand shifts;
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infrastructure constraints;
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trading impacts on short-term energy markets; and
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supply, demand and other factors affecting alternative fuels.
Underground natural gas storage facilities are a critical component of the North American natural gas transmission and distribution system. They provide an essential reliability cushion against unexpected disruptions in supply, transportation or markets and allow for the warehousing of gas to meet expected seasonal and daily variability in demand. According to the Energy Information Administration, U.S. natural gas consumption is expected to grow at a compound annual growth rate of 1.0% through 2020.
Most forecasts of North American natural gas supply and demand suggest a continuation of trends that will result in increased demand for natural gas storage capacity. Seasonal and weather sensitive demand sectors (residential and commercial heating demand and gas-fired power generation demand) have been growing and are expected to continue to do so, while the less seasonal industrial demand has been declining. Natural gas supply, meanwhile, has become almost entirely non-seasonal, requiring greater reliance on natural gas storage to respond to demand variability. On average, total North American natural gas consumption levels are approximately 40% higher in the winter months than summer months primarily due to the requirements of residential and commercial market sectors. These markets are very temperature sensitive with demand being highly variable both on a seasonal and a daily basis thus requiring that storage be capable of providing high maximum daily deliverability on the coldest days when storage due to infrastructure constraints provides as much as 50% of the market’s total requirement. Analysis has shown that seasonal winter demand has continued to show steady growth even though warmer winter temperature trends have muted the full impact of this increasing demand. Gas storage has facilitated the creation of a natural gas industry that is characterized by a production profile that is largely non-seasonal and a consumption profile that is highly seasonal and weather sensitive. Natural gas storage is essential in reallocating this inherent supply and demand imbalance.
In the natural gas storage business, there are significant barriers to entry, particularly in depleted reservoir storage such as the Stagecoach facility. Barriers include:
Geology: rock quality, depth, containment and reservoir size heavily influence development opportunities;
Geography: proximity to existing pipeline infrastructure, surface development and complicated land ownership all combine to further increase the difficulty in developing and operating natural gas storage facilities;
Specialized skills: finding and retaining qualified and skilled natural gas storage professionals is a challenge in today’s competitive job market in the oil & gas sectors due to the specialized nature of the skills required; and
Development costs: costs for new natural gas storage capacity development have continued to increase.
Although there are significant barriers to entry within the natural gas storage industry, competition is robust. Competition for natural gas storage is primarily based on location, connectivity and the ability to deliver natural gas in a timely and reliable manner. Our natural gas storage facilities compete with other means of natural gas storage, including other depleted reservoir facilities, salt cavern storage facilities and liquefied natural gas and pipelines.
Storage capacity is held by a wide variety of market participants for a variety of purposes such as:
Reliability: local distribution companies (“LDC’s”) hold the bulk of capacity and tend to use it in a manner relatively insensitive to gas prices, injecting gas into storage during the summer to meet fairly well-defined inventory targets and withdrawing it in winter to meet peak load requirements while retaining a sufficient cushion of inventory to meet worst-case late winter demands. For such customers with an obligation to serve core end use markets, the value of storage may be significantly greater than the price differential between winter and summer gas. LDC’s will pay the price to secure the natural gas storage they need up to the cost of alternatives (i.e., long haul pipeline capacity or above-ground storage).
Efficiency: pipeline operators use storage capacity for system balancing requirements and to manage maintenance schedules, as well as to provide storage services to shippers on their systems. Producers use capacity to minimize production fluctuations and to manage market commitments. Power generators use storage capacity to provide swing capability for their plants that experience high daily and even hourly variability of requirements.
Arbitrage: energy merchants and other trading entities use storage for gas price arbitrage purposes, buying and injecting gas at times of low gas prices and withdrawing at times of higher prices as driven by the fundamentals of the natural gas market.
The value of natural gas storage is a reflection of its critical role in providing the North American natural gas market with a degree of supply reliability, flexibility and seasonal and daily demand balancing.
NGL Business
In general, natural gas produced at the wellhead contains, along with methane, various NGLs. This raw natural gas is usually not acceptable for transportation in the nation’s major natural gas pipeline systems or for commercial use as a fuel. Our natural gas processing operation, located near Bakersfield, CA, separates, for the most part, the NGLs from the methane and delivers the methane to the local natural gas pipelines. The NGLs are retained for further processing within our fractionation facility.
NGL fractionation facilities separate mixed NGL streams into discrete NGL products: propane, normal butane, isobutane and pentanes (sometimes referred to as natural gasoline). The three primary sources of mixed NGLs fractionated in the United States are (i) domestic natural gas processing plants, (ii) domestic crude oil refineries and (iii) imports of butane and propane mixtures. The mixed NGLs delivered from domestic natural gas processing plants and crude oil refineries to our NGL fractionation facility are typically transported by NGL pipelines, railcar and NGL transport truck.
Other businesses within our NGL operation are butane isomerization and refrigerated storage. Our recently constructed isomerization facility chemically changes normal butane to isobutane, which we provide to area refineries for motor fuel blending.
The purity NGL products (propane, normal butane, isobutane and natural gasoline) are typically used as raw materials by the petrochemical industry, feedstocks by refiners in the production of motor gasoline and by industrial and residential users as fuel. Propane is used both as a petrochemical feedstock in the production of propylene and as a heating, engine and industrial fuel. Normal butane is used as a petrochemical feedstock in the production of butadiene (a key ingredient of synthetic rubber), as a blendstock for motor gasoline and to derive isobutane through isomerization. Some more common uses of isobutane is blendstock in motor gasoline to enhance the octane content and in the production of propylene oxide. Natural gasoline, a mixture of pentanes and heavier hydrocarbons, is primarily used as a blendstock for motor gasoline, denaturant for ethanol and dilute for heavy crude oil.
Our NGL business encounters competition from fully integrated oil companies and independent NGL market participants. Each of our competitors has varying levels of financial and personnel resources and competition generally revolves around price, service and location. The majority of our NGL processing and fractionation activities are processing mixed NGL streams for third-party customers and to support our NGL marketing activities under contractual and fee-based arrangements. These fees (typically in cents per gallon) are subject to adjustment for changes in certain fractionation expenses, including natural gas fuel costs. Our integrated midstream energy asset system affords us flexibility in meeting our customers’ needs. While many companies participate in the natural gas processing business, few have a presence in significant downstream activities such as NGL fractionation and transportation and NGL marketing as we do. Our competitive position and presence in these downstream businesses allow us to extract incremental value while offering our customers enhanced services, including comprehensive service packages.
Salt Mining
According to the Salt Institute, a North American based non-profit salt industry trade association, more than 250 million metric tons of salt were produced in the world in 2007. China is the single largest producer of salt, with 59.8 million metric tons, followed by the United States, with 44.5 million metric tons. Salt is generally categorized into four types based upon the method of production: evaporated salt, solar salt, rock salt and salt in brine. Dry salt is produced through the following methods: solution mining and mechanical evaporation, solar evaporation or deep-shaft mining. Our US Salt facility, located in Schuyler County, New York, produces salt using solution mining and mechanical evaporation. The facility produces and sells over 300,000 tons of salt each year.
In solution mining, wells are drilled into salt beds or domes and then water is injected into the formation and circulated to dissolve the salt. The salt solution, or brine, is then pumped out and taken to a plant for evaporation. At the plant, the brine is treated to remove minerals and pumped into vacuum pans, sealed containers in which the brine is boiled and then evaporated until the salt is left behind. Then it is dried and refined. Depending on the type of salt to be produced, iodine and an anti-clumping agent may be added to the salt. Most food grade table salt is produced in this manner.
After the salt is removed from a solution-mined salt deposit, the empty cavern can be used to store other substances, like natural gas, LPG or compressed air.
Our US Salt facility has existing cavern space that we are currently developing into a 5 million barrel LPG storage facility that we expect to place into service in the spring of 2010. There is also existing cavern space that we intend to convert to approximately 10 bcf of natural gas storage. With each new brine well that we drill we create additional potential storage capacity.
Business Strategy
Our primary objective is to increase distributable cash flow for our unitholders, while maintaining the highest level of commitment and service to our customers. We have engaged and will continue to engage in objectives of further growth through acquisitions both in our propane and midstream operations, internally generated expansion and measures aimed at increasing the profitability of existing operations.
Competitive Strengths
We intend to pursue this objective by capitalizing on what we believe are our competitive strengths as follows:
Proven Acquisition Expertise
Since our predecessor’s inception and through September 30, 2009, we have acquired and successfully integrated 84 companies-78 propane companies and 6 midstream businesses. Our executive officers and key employees, who together average more than 15 years experience in the propane and midstream energy-related industries, have developed business relationships with retail propane owners and businesses as well as other midstream industry participants throughout the United States. These significant industry contacts have enabled us to negotiate most of our acquisitions on an exclusive basis. We believe that this acquisition expertise should allow us to continue to grow through strategic and accretive acquisitions. Our acquisition program will continue to seek:
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businesses that generate distributable cash flow that is accretive to common unitholders on a per unit basis;
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propane and midstream businesses in attractive market areas;
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propane businesses with established names and reputations for customer service and reliability;
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propane businesses with high concentration of propane sales to residential customers;
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midstream businesses that generate predictable, stable fee-based cash flow streams;
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midstream businesses with organic expansion opportunities or strategic regional enhancement; and
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retention of key employees in acquired businesses.
Management Experience
Our senior management team has extensive experience in the propane and midstream energy industry. Our management team has a proven track record of enhancing the value of our partnership, through the acquisition, integration and optimization of the businesses we own and operate.
Flexible Financial Structure
We have a $350 million revolving credit facility for acquisitions and a $75 million revolving working capital facility. These facilities include a provision which allows us to utilize up to $200 million of combined borrowing capacity for working capital as needed during the winter heating season. We believe our available capacity under these facilities combined with our ability to fund acquisitions and organic expansion projects through the issuance of additional partnership interests will provide us with a flexible financial structure that will facilitate our acquisition and organic expansion effort.
As discussed in Item 1, we now have a $450 million general partnership revolving credit facility for acquisitions, capital expenditures and general partnership purposes and a $75 million revolving working capital facility.
Propane Business Strengths
Focus on High Percentage of Retail Sales to Residential Customers
Our retail propane operations concentrate on sales to residential customers. Residential customers tend to generate higher margins and are generally more stable purchasers than other customers. For the fiscal year ended September 30, 2009, sales to residential customers represented approximately 70% of our retail propane gallons sold. Although overall demand for propane is affected by weather and other factors, we believe that residential propane consumption is not materially affected by general economic conditions because most residential customers consider home space heating to be an essential purchase. In addition, we own nearly 90% of the propane tanks located at our customers’ homes. In many states, fire safety regulations restrict the refilling of a leased tank solely to the propane supplier that owns the tank. These regulations, which require customers to switch propane tanks when they switch suppliers, help enhance the stability of our customer base because of the inconvenience and costs involved with switching tanks and suppliers.
Regionally Branded Operating Structure
We believe that our success in maintaining customer stability and our low cost operating structure at our customer service centers results from our decentralized operation under established, locally recognized trade names. We attempt to capitalize on the reputation of the companies we acquire by retaining their local brand names and employees, thereby preserving the goodwill of the acquired business and fostering employee loyalty and customer retention. We expect our local branch management to continue to manage the marketing programs, new business development, customer service and customer billing and collections. We believe that our employee incentive programs encourage efficiency and allow us to control costs at the corporate and field levels.
Operations in Attractive Propane Markets
A majority of our propane operations are concentrated in attractive propane market areas, where natural gas distribution is not cost-effective, margins are relatively stable and tank control is relatively high. We intend to pursue acquisitions in similar attractive markets.
Comprehensive Propane Logistics and Distribution Business
One of our distinguishing strengths is our propane procurement and distribution expertise and capabilities. For the fiscal year ended September 30, 2009, we delivered 380.6 million gallons of propane on a wholesale basis to our various customers. These operations are significantly larger on a relative basis than the wholesale operations of most publicly-traded propane businesses. We also provide transportation services to these distributors through our fleet of transport vehicles, and price risk management services to our customers through a variety of financial and other instruments. The presence of our trucks serving our wholesale customers allows us to take advantage of various pricing and distribution inefficiencies that exist in the market from time to time. We believe our wholesale business enables us to obtain valuable market intelligence and awareness of potential acquisition opportunities. Because we sell on a wholesale basis to many residential and commercial retailers, we have an ongoing relationship with a large number of businesses that may be attractive acquisition opportunities for us. We believe that we will have an adequate supply of propane to support our growing retail operations at prices that are generally available only to large wholesale purchasers. This purchasing scale and resulting expertise also helps us avoid shortages during periods of tight supply to an extent not generally available to other retail propane distributors.
Midstream Business Strengths
Strategically Located Assets
Our assets are situated close to or within demand based market areas, which positions us well to leverage the services we offer to our customers relative to our competitors. We own and operate natural gas storage operations approximately 200 miles northwest of New York City. These assets are among the closest natural gas storage facilities to the New York City market and have the capability of delivering gas to this market as well as other Northeast and Mid-Atlantic market centers. We also own and operate US Salt, a salt production company located in Schuyler County, New York, between our Stagecoach and Steuben natural gas storage facilities, which we believe may add additional gas storage capacity to our operations in the Northeast. We also own and operate an NGL operation near Bakersfield, California, strategically situated between the major refining centers of Los Angeles and San Francisco. We believe there are opportunities to further leverage our geographic location, expand our current asset base and to enhance the platform of services we offer to our customers that will further enhance the value and profitability of these assets.
Ability to Leverage Industry Relationships
Our management team has extensive industry relationships and they have been successful in leveraging these relationships with both new and existing customers of our midstream operations into profitable opportunities to further grow our operations.
Stable Cash Flows
Our midstream operations consist predominantly of fee-based services that generate stable cash flows. Our Stagecoach operations are 100% fee-based with a weighted average contract maturity which extends to September 2014. Steuben and Bath operations are also 100% fee-based with contracted maturities extending out several years. These contracts are with investment-grade rated customers such as large east coast utilities and major gas marketing firms. In addition, our West Coast NGL operations include fee-based services and have relatively little exposure to fluctuations in commodity prices. We believe that this further adds to our stable cash flow and enhances our access to the capital markets.
Operations
Our operations reflect our two reportable segments: propane operations and midstream operations.
Propane Operations
Retail Propane
Customer Service Centers
At October 30, 2009, we distributed propane to approximately 700,000 retail customers from 312 customer service centers in 28 states. We market propane primarily in rural areas, but also have a significant number of customers in suburban areas where energy alternatives to propane such as natural gas are generally not available. We market our propane primarily in the eastern half of the United States through our customer service centers using multiple regional brand names. The following table shows our customer service centers by state:
From our customer service centers, we also sell, install and service equipment related to our propane distribution business, including heating and cooking appliances. Typical customer service centers consist of an office and service facilities, with one or more 12,000 to 30,000 gallon bulk storage tanks. Some of our customer service centers also have an appliance showroom. We have several satellite facilities that typically contain only large capacity storage tanks.
Customer Deliveries
Retail deliveries of propane are usually made to customers by means of our fleet of bobtail and rack trucks. Propane is pumped from the bobtail truck, which generally holds 2,500 to 3,000 gallons, into a stationary storage tank at the customer’s premises. The capacity of these tanks range from 100 gallons to 1,200 gallons, with a typical tank having a capacity of 100 to 300 gallons in milder climates and 500 to 1,000 gallons in colder climates. We also deliver propane to retail customers in portable cylinders, which typically have a capacity of five to thirty-five gallons. These cylinders typically are picked up by us and replenished at our distribution locations, then returned to the retail customer. To a limited extent, we also deliver propane to certain customers in larger trucks known as transports, which have an average capacity of 10,000 gallons. These customers include industrial customers, large-scale heating accounts and large agricultural accounts.
During the fiscal year ended September 30, 2009, we delivered approximately 45% of our propane volume to retail customers and 55% to wholesale customers. Our retail volume sold to residential, industrial and commercial and agricultural customers were as follows:
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70% to residential customers;
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23% to industrial and commercial customers; and
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7% to agricultural customers.
No single retail customer accounted for more than 1% of our revenue during the fiscal year ended September 30, 2009.
Approximately half of our residential customers receive their propane supply under an automatic delivery program. Under the automatic delivery program, we deliver propane to our heating customers approximately six times during the year. We determine the amount of propane delivered based on weather conditions and historical consumption patterns. Our automatic delivery program eliminates the customer’s need to make an affirmative purchase decision, promotes customer retention by ensuring an uninterrupted supply and enables us to efficiently route deliveries on a regular basis. We promote this program by offering level payment billing, discounts, fixed price options and price caps. In addition, we generally provide emergency service 24 hours a day, seven days a week, 52 weeks a year.
Seasonality
The retail propane business is seasonal with weather conditions significantly affecting demand for propane. We believe that the geographic diversity of our areas of operations helps to minimize our exposure to regional weather. Although overall demand for propane is affected by climate, changes in price and other factors, we believe our residential and commercial business to be relatively stable due to the following characteristics:
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residential and commercial demand for propane has not been significantly affected by general economic conditions due to the largely non-discretionary nature of most propane purchases by our customers;
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loss of customers to competing energy sources has been low;
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the tendency of our customers to remain with us due to the product being delivered pursuant to a regular delivery schedule and to our ownership of approximately 90% of the storage tanks utilized by our customers; and
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our ability to offset customer losses through a combination of acquisitions and to a lesser extent, sales to new customers in existing markets.
Since home heating usage is the most sensitive to temperature, residential customers account for the greatest usage variation due to weather. Variations in the weather in one or more regions in which we operate can significantly affect the total volumes of propane we sell and the margins we realize and, consequently, our results of operations. We believe that sales to the commercial and industrial markets, while affected by economic patterns, are not as sensitive to variations in weather conditions as sales to residential and agricultural markets.
Transportation Assets and Truck Maintenance
Our transportation assets are operated by L&L Transportation, LLC, a wholly-owned subsidiary of Inergy Propane. The transportation of propane requires specialized equipment. Propane trucks carry specialized steel tanks that maintain the propane in a liquefied state. As of September 30, 2009, we owned a fleet of 191 tractors, 571 transports, 1,330 bobtail and rack trucks and 884 other service vehicles. In addition to supporting our retail and wholesale propane operations, our fleet is also used to deliver butane and ammonia for third parties and to distribute natural gas for various processors and refiners.
We own truck maintenance facilities located in Indiana, Ohio and Mississippi. We also have a trucking operation located in California as part of our NGL business. We believe that our ability to maintain the trucks we use in our propane operations significantly reduces the costs we would otherwise incur with third parties in maintaining our fleet of trucks.
Pricing Policy
Our pricing policy is an essential element in our successful marketing of propane. We base our pricing decisions on, among other things, prevailing supply costs, local market conditions and local management input. We rely on our regional management to set prices based on these factors. Our local managers are advised regularly of any changes in the posted prices of our propane suppliers. We believe our propane pricing methods allow us to respond to changes in supply costs in a manner that protects our customer base and gross margins. In some cases, however, our ability to respond quickly to cost increases could cause our retail prices to rise more rapidly than those of our competitors, possibly resulting in a loss of customers.
Billing and Collection Procedures
We retain our customer billing and account collection responsibilities at the local level. We believe that this decentralized approach is beneficial for a number of reasons:
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customers are billed on a timely basis;
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customers are more likely to pay a local business;
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cash payments are received faster; and
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local personnel have current account information available to them at all times in order to answer customer inquiries.
Trademarks and Trade Names
We use a variety of trademarks and trade names which we own, including “Inergy” and “Inergy Services.” We believe that our strategy of retaining the names of the companies we acquire has maintained the local identification of such companies and has been important to the continued success of the acquired businesses. We regard our trademarks, trade names and other proprietary rights as valuable assets and believe that they have significant value in the marketing of our products.
Wholesale Supply, Marketing and Distribution Operations
We currently provide wholesale supply, marketing and distribution services to independent dealers, multi-state marketers, petrochemical companies, refinery and gas processors and a number of other NGL marketing and distribution companies, primarily in the Midwest and Southeast. While our wholesale supply, marketing and distribution operations accounted for 25% of total revenue, this business represented 4% of our gross profit during the fiscal year ended September 30, 2009.
Marketing and Distribution
Because of the size of our wholesale operations one of our distinguishing strengths is our procurement and distribution expertise and capabilities. This is partly the result of the unique background of our management team, which has significant experience in the procurement aspects of the propane business. We also offer transportation services to these distributors through our fleet of transport trucks and price risk management services to our customers through a variety of financial and other instruments. Our wholesale supply, marketing and distribution business provides us with an additional income stream as well as extensive market intelligence and acquisition opportunities. In addition, these operations provide us with more secure supplies and better pricing for our customer service centers. Moreover, the presence of our trucks across the Midwest and Southeast allows us to take advantage of various pricing and distribution inefficiencies that exist in the market from time to time.
Supply
We obtain a substantial majority of our propane from domestic suppliers, with our remaining propane requirements provided by Canadian suppliers. During the fiscal year ended September 30, 2009, a majority of our sales volume was purchased pursuant to contracts that have a term of one year or less; the balance of our sales volume was purchased on the spot market. The percentage of our contract purchases varies from year to year. 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 such market prices. Some of these agreements provide maximum and minimum seasonal purchase guidelines.
Two suppliers, BP Amoco Corp. (12%) and Sunoco, Inc. (11%), accounted for 23% of propane purchases during the past fiscal year. We believe that contracts with these suppliers will enable us to purchase most of our supply needs at market prices and ensure adequate supply. No other single supplier accounted for more than 10% of propane purchases in the current year.
Propane generally is transported from refineries, pipeline terminals, storage facilities and marine terminals to our approximate 650 bulk storage tank facilities. We accomplish this by using our transports and contracting with common carriers, owner-operators and railroad tank cars. Our customer service centers and satellite locations typically have one or more 12,000 to 30,000 gallon storage tanks, which are generally adequate to meet customer usage requirements for seven days during normal winter demand. Additionally, we lease underground storage facilities from third parties under annual lease agreements.
We engage in risk management activities in order to reduce the effect of 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 propane forward and option contracts with various third parties to purchase and sell propane at fixed prices in the future. We monitor these activities through enforcement of our risk management policy.
Midstream Operations
Natural Gas Storage Operations
Stagecoach was acquired on August 9, 2005, and is a high performance, multi-cycle natural gas storage facility with 26.25 bcf of working storage capacity of natural gas, maximum withdrawal capability of 500 MMcf/day and maximum injection capability of 250 MMcf/day. Located approximately 150 miles northwest of New York City, the Stagecoach facility is currently connected to Tennessee Gas Pipeline Company’s 300 Line and the Millennium Pipeline and is a significant participant in the northeast United States natural gas distribution system. The Stagecoach facility is 100% contracted with predominantly investment-grade rated customers such as large east coast utility companies and major gas marketing firms.
ASC was acquired in October 2007 and is the majority owner and operator of Steuben, which owns a natural gas storage facility located in Steuben County, New York, with 6.2 bcf of working gas capacity, maximum withdrawal capability of 60 MMcf/day and maximum injection capability of 30 MMcf/day. The facility was developed and placed in commercial service in 1991. The storage capacity at Steuben is fully contracted under long-term agreements with investment-grade rated customers. Located approximately 30 miles northwest of Corning, New York, the Steuben facility is currently connected to Dominion Gas Transmission’s Woodhull line and is a critical component of the northeast United States natural gas market.
Thomas Corners, a 7 bcf (working) natural gas storage facility located in Steuben County, New York, was placed into service in November 2009. Beginning in April 2010, the storage capacity at Thomas Corners will be fully contracted under long-term agreements with investment-grade rated customers. We expect Thomas Corners to generate revenue from interruptible storage contracts during the period November 2009 through March 2010. This facility has maximum withdrawal and injection capabilities of 140 MMcf/day and 70 MMcf/day, respectively. Thomas Corners is connected with the Tennessee Gas Pipeline Company’s Line 400 and Columbia Gas Transmission’s A-5 line (which was acquired by the Millennium Pipeline and as such the Thomas Corners facility is also connected with the Millennium Pipeline).
LPG Storage Operations
Our Bath LPG Storage Facility, acquired in October 2006, is a 1.7 million barrel salt cavern storage facility located near Bath, New York, approximately 210 miles northwest of New York City and approximately 60 miles from our Stagecoach facility. The facility is supported by both rail and truck terminals capable of loading and unloading 20-23 rail cars per day and 17 truck transports per day. The facility is currently fully contracted under long-term agreements for butane and propane storage.
NGL Operations
Our NGL business, acquired in 2003, is located near Bakersfield, California. The facility includes a 25.0 MMcf/day natural gas processing plant, a 12,000 bpd NGL fractionation plant, an 8,000 bpd butane isomerization plant, NGL rail and truck terminals, a 24.0 million gallon NGL storage facility and NGL transportation/marketing operations.
Salt Operations
Our US Salt facility, acquired in August 2008, is located in Schuyler County, New York, and produces salt using solution mining and mechanical evaporation. The facility is strategically located between our Stagecoach and Steuben facilities. The facility produces and sells over 300,000 tons of salt each year. The US Salt facility has existing cavern space that we are currently developing into a 5 million barrel LPG storage facility that we expect to place into service in the spring of 2010. There is also existing cavern space that we intend to convert to approximately 10 bcf of natural gas storage. With each new brine well that we drill we create additional potential storage capacity.
For more information on our reportable business segments, see Note 13 to our consolidated financial statements.
Employees
As of October 30, 2009, we had 2,822 full-time employees and 88 part-time employees. Of the 2,910 employees, 125 were general and administrative and 2,785 were operational. Of the operational employees, 230 were members of labor unions. We believe that our relationship with our employees is satisfactory.
Government Regulation
National Fire Protection Association Pamphlets No. 54 and No. 58, which establish rules and procedures governing the safe handling of propane, or comparable regulations, have been adopted as the law in substantially 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 county or municipal level. Regarding the transportation of propane, ammonia and butane by truck, we are subject to regulations promulgated under the Federal Motor Carrier Safety Act. These regulations cover the transportation of hazardous materials and are administered by the United States Department of Transportation. We conduct ongoing training programs to help ensure that our operations are in compliance with applicable regulations. We maintain various permits that are necessary to operate some of our facilities, some of which may be material to our operations. We believe that the procedures currently in effect at all of our facilities for the handling, storage and distribution of propane and the transportation of ammonia and butane are consistent with industry standards and are in compliance in all material respects with applicable laws and regulations.
Our midstream operations are subject to federal, state and local regulatory authorities. Specifically, the Stagecoach, Steuben and Thomas Corners natural gas storage facilities are subject to the regulation of the Federal Energy Regulatory Commission (“FERC”).
Under the Natural Gas Act of 1938 (“NGA”), FERC has authority to regulate gas transportation services in interstate commerce, including storage services. FERC’s authority to regulate those services includes the rates charged for the services, terms and conditions of service, certification and construction of new facilities, the extension or abandonment of services and facilities, the maintenance of accounts and records, the acquisition and disposition of facilities, the initiation and discontinuation of services, relationships with affiliated entities and various other matters. Natural gas companies may not charge rates that, upon review by FERC, are found to be unjust, unreasonable, or unduly discriminatory. In addition, FERC prohibits natural gas companies from unduly preferring or unreasonably discriminating against any person with respect to pipeline transportation rates or terms and conditions of service. The rates and terms and conditions for such services are found in the FERC-approved tariff of Central New York Oil and Gas Company, LLC (“CNYOG”), the owner of the Stagecoach facility, the FERC-approved tariff of Steuben Gas Storage Company, the owner of the Steuben facility and the FERC-approved tariff of ASC, the owner of the Thomas Corners facility. Pursuant to the NGA, existing interstate transportation and storage rates may be challenged by complaint and are subject to prospective change by FERC. Additionally, rate increases proposed by the regulated pipeline or storage provider may be challenged by protest and such proposed increases may ultimately be rejected by FERC. CNYOG and ASC currently hold authority from FERC to charge and collect market-based rates for services provided at the Stagecoach facility and Thomas Corners facility, respectively. Steuben Gas Storage Company currently holds authority from FERC to charge and collect cost of service rates at the Steuben facility. There can be no guarantee that CNYOG and ASC will be allowed to continue to operate under such a rate structure for the remainder of the Stagecoach and Thomas Corners facilities’ operating lives. Any successful complaint or protest against rates charged for CNYOG’s or ASC’s storage and related services, or CNYOG’s or ASC’s loss of market-based rate authority, could have an adverse impact on our revenues.
In addition, CNYOG’s or ASC’s market-based rate authority would be subject to further review if we acquire transportation facilities or additional storage capacity, if we or one of our affiliates provides storage or transportation services in the same market area or acquires an interest in another storage field that can link our facilities to the market area or if we or one of our affiliates acquire an interest in or is acquired by an interstate pipeline.
There can be no assurance that FERC will continue to pursue its approach of pro-competitive policies as it considers matters such as pipeline rates and rules and policies that may affect rights of access to natural gas transportation capacity, transportation and storage facilities. Any successful complaint or protest against such rates or loss of market-based rate authority could have an adverse impact on our revenues associated with providing storage services.
In August, 2005, Congress enacted legislation that, among other matters, amends the NGA to make it unlawful for “any entity” to use any deceptive or manipulative device or contrivance in connection with the purchase or sale of natural gas or the purchase or sale of transportation services, including storage services such as those provided by the Stagecoach facility, subject to FERC regulation, in contravention of rules prescribed by FERC. On January 20, 2006, FERC issued rules implementing this provision. The rules make it unlawful for any entity, in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of FERC-regulated transportation services, directly or indirectly, to use or employ any device, scheme or artifice to defraud; to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or to engage in any act or practice that operates as a fraud or deceit upon any entity. The new legislation also amends the NGA to give FERC authority to impose civil penalties for violations of the NGA up to $1,000,000 per day per violation. The new anti-manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales, gas processing, or gathering, but does apply to activities of interstate gas pipelines and storage providers, as well as otherwise non-jurisdictional entities, such as gas processors, to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction. It therefore reflects an expansion of FERC’s NGA enforcement authority.
Certain aspects of our midstream operations are also subject to the Pipeline Safety Act of 2002, as amended by the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006, which provides guidelines in the area of testing, education, training and communication. In addition to pipeline integrity tests, pipeline and storage companies are required to implement a qualification program to make certain that employees are properly trained. The United States Department of Transportation has approved our qualification program. We believe that we are in substantial compliance with these requirements and have integrated appropriate aspects of the law into our Operator Qualification Program, which is in place and functioning.
Additionally, we are subject to stringent federal, state and local environmental, health and safety laws and environmental regulations governing our operations. These laws and regulations impose limitations on the discharge and emission of pollutants and establish standards for the handling of solid and hazardous wastes. Applicable 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 or local 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. While propane is not a hazardous substance within the meaning of CERCLA, other chemicals used in our operations may be classified as hazardous substances. Failure to comply with these laws and regulations may result in the assessment of administrative, civil or criminal penalties, the imposition of remedial liabilities and the issuance of injunctions restricting or prohibiting our activities. We have not received any notices that we have violated these environmental laws and regulations in any material respect and we have not otherwise incurred any material liability or capital expenditure thereunder.
For acquisitions that involve the purchase of real estate, we conduct due diligence investigations to assess whether any material or waste has been sold from, or stored on, or released or spilled from any of that real estate prior to its purchase. This due diligence includes questioning the seller, obtaining representations and warranties concerning the seller’s compliance with environmental laws and performing site assessments. During these due diligence investigations, our employees, and, in certain cases, independent environmental consulting firms, review historical records and databases and conduct physical investigations of the property to look for evidence of contamination, compliance violations and the existence of underground storage tanks.
Recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gas” and including methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of fuels such as propane and natural gas, may be contributing to warming of the Earth’s atmosphere. In response
to such studies, the U.S. Congress is actively considering legislation to reduce emissions of greenhouse gases. In addition, at least 17 states have already taken legal measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Also, as a result of the U.S. Supreme Court’s decision on April 2, 2007 in Massachusetts, et al. v. EPA, the U.S. Environmental Protection Agency or “EPA” may be required to regulate greenhouse gas emissions from mobile sources (e.g., cars and trucks) even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. The Court’s holding in Massachusetts that greenhouse gases fall under the federal Clean Air Act’s definition of “air pollutant” may also result in future regulation of greenhouse gas emissions from stationary sources under certain Clean Air Act programs. Passage of climate control legislation or other regulatory initiatives by Congress or various states of the U.S. or the adoption of regulations by the EPA or analogous state agencies that restrict emissions of greenhouse gases in areas in which we conduct business could have an adverse affect on our operations and demand for our services.
In addition, the Department of Homeland Security Appropriations Act of 2007 requires the Department of Homeland Security or “DHS” to issue regulations establishing risk-based performance standards for the security of chemical and industrial facilities, including oil and gas facilities that are deemed to present “high levels of security risk.” The DHS issued an interim final rule in April 2007 regarding risk-based performance standards to be attained pursuant to the act and the DHS has adopted an Appendix A to the interim rules that establish the chemicals of concern and their respective threshold quantities that will trigger compliance with the interim rules.
Future developments, such as stricter environmental, health or safety laws and regulations, or more stringent enforcement of existing requirements could affect our operations. We do not anticipate that our compliance with or liabilities under environmental, health and safety laws and regulations, including CERCLA, will require any material increase in our capital expenditures or otherwise have a material adverse effect on us. To the extent that any environmental liabilities, or environmental, health or safety laws, or regulations are made more stringent, there can be no assurance that our results of operations will not be materially and adversely affected.
Item 1A.
Item 1A. Risk Factors
Risks Inherent in Our Business
Future acquisitions and completion of expansion projects will require significant amounts of debt and equity financing which may not be available to us on acceptable terms, or at all.
We plan to fund our acquisitions and expansion capital expenditures, including any future expansions we may undertake, with proceeds from sales of our debt and equity securities and borrowings under our revolving credit facility; however, we cannot be certain that we will be able to issue our debt and equity securities on terms or in the proportions that we expect, or at all, and we may be unable refinance our revolving credit facility when it expires. In addition, we may be unable to obtain adequate funding under our current revolving credit facility because our lending counterparties may be unable to meet their funding obligations.
Global financial markets and economic conditions have been, and continue to be, disrupted and volatile. The debt and equity capital markets have been distressed. These issues, along with significant write-offs in the financial services sector, the re-pricing of credit risk and the current weak economic conditions may make it difficult to obtain funding.
The cost of raising money in the debt and equity capital markets has increased while the availability of funds from those markets generally has diminished. Also, as a result of concerns about the stability of financial markets generally and the solvency of counterparties specifically, the cost of obtaining money from the credit markets generally has increased as many lenders and institutional investors have increased interest rates, enacted tighter lending standards, refused to refinance existing debt at maturity or on terms similar to our current debt and reduced and, in some cases, ceased to provide funding to borrowers.
A significant increase in our indebtedness, or an increase in our indebtedness that is proportionately greater than our issuances of equity, as well as the credit market and debt and equity capital market conditions discussed above could negatively impact our credit ratings or our ability to remain in compliance with the financial covenants under our revolving credit agreement which could have a material adverse effect on our financial condition, results of operations and cash flows. If we are unable to finance acquisitions or our expansion projects as expected, we could be required to seek alternative financing, the terms of which may not be attractive to us, or to revise or cancel our expansion plans.
If we do not continue to make acquisitions on economically acceptable terms, our future financial performance may be limited.
Due to increased competition from alternative energy sources the propane industry is not a growth industry. In addition, as a result of long-standing customer relationships that are typical in the retail home propane industry, the inconvenience of switching tanks and suppliers and propane’s higher cost as compared to other energy sources, we may have difficulty in increasing our retail customer base other than through acquisitions. Therefore, while our operating objectives include promoting internal growth, our ability to grow depends principally on acquisitions. Our future financial performance depends on our ability to continue to make acquisitions at attractive prices. There is no assurance that we will be able to continue to identify attractive acquisition candidates in the future or that we will be able to acquire businesses on economically acceptable terms. In particular, competition for acquisitions in the propane business has intensified and become more costly. We may not be able to grow as rapidly as we expect through our acquisition of additional businesses for various reasons, including the following:
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We will use our cash from operations primarily to service our debt and for distributions to unitholders and reinvestment in our business. Consequently, the extent to which we are unable to use cash or access capital to pay for additional acquisitions may limit our growth and impair our operating results. Further, we are subject to certain debt incurrence covenants under our bank credit agreement and the indentures that govern our senior notes that may restrict our ability to incur additional debt to finance acquisitions.
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Although we intend to use our securities as acquisition currency, some prospective sellers may not be willing to accept our securities as consideration.
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We will use cash for capital expenditures related to expansion projects, which will reduce our cash available to pay for additional acquisitions.
Moreover, acquisitions involve potential risks, including:
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our inability to integrate the operations of recently acquired businesses;
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the diversion of management’s attention from other business concerns;
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customer or key employee loss from the acquired businesses; and
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a significant increase in our indebtedness.
Our growth strategy includes acquiring entities with lines of business that are distinct and separate from our existing operations which could subject us to additional business and operating risks.
Consistent with our announced growth strategy and our acquisition of the US Salt facility and related assets, we may acquire assets that have operations in new and distinct lines of business from our existing operations. Integration of new business segments is a complex, costly and time-consuming process and may involve assets in which we have limited operating experience. Failure to timely and successfully integrate acquired entities’ new lines of business with our existing operations may have a material adverse effect on our business, financial condition or results of operations. The difficulties of integrating new business segments with existing operations include, among other things:
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operating distinct business segments that require different operating strategies and different managerial expertise;
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the necessity of coordinating organizations, systems and facilities in different locations;
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integrating personnel with diverse business backgrounds and organizational cultures; and
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consolidating corporate and administrative functions.
In addition, the diversion of our attention and any delays or difficulties encountered in connection with the integration of the new business segments, such as unanticipated liabilities or costs, could harm our existing business, results of operations, financial condition or prospects. Furthermore, new lines of business will subject us to additional business and operating risks which could have a material adverse effect on our financial condition or results of operations.
We may be unable to successfully integrate our recent acquisitions.
One of our primary business strategies is to grow through acquisitions. There is no assurance that we will successfully integrate acquisitions into our operations, or that we will achieve the desired profitability from our acquisitions. Failure to successfully integrate these substantial acquisitions could adversely affect our operations. The difficulties of combining the acquired operations include, among other things:
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operating a significantly larger combined organization and integrating additional retail and wholesale distribution operations to our existing supply, marketing and distribution operations;
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coordinating geographically disparate organizations, systems and facilities;
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integrating personnel from diverse business backgrounds and organizational cultures;
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consolidating corporate, technological and administrative functions;
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integrating internal controls, compliance under the Sarbanes-Oxley Act of 2002 and other corporate governance matters;
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the diversion of management’s attention from other business concerns;
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customer or key employee loss from the acquired businesses;
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a significant increase in our indebtedness; and
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potential environmental or regulatory liabilities and title problems.
In addition, we may not realize all of the anticipated benefits from our acquisitions, such as cost-savings and revenue enhancements, for various reasons, including difficulties integrating operations and personnel, higher costs, unknown liabilities and fluctuations in markets.
Our indebtedness may limit our ability to borrow additional funds, make distributions to our unitholders, or capitalize on acquisition or other business opportunities, in addition to impairing our ability to fulfill our debt obligation under our senior notes.
As of September 30, 2009, we had $1.1 billion of total outstanding indebtedness. Our leverage, various limitations in our credit facility, other restrictions governing our indebtedness and the indentures governing our senior notes may reduce our ability to incur additional indebtedness, to engage in some transactions and to capitalize on acquisition or other business opportunities.
Our indebtedness and other financial obligations could have important consequences. For example, they could:
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make it more difficult for us to make distributions to our unitholders;
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impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general partnership purposes or other purposes;
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result in higher interest expense in the event of increases in interest rates since some of our debt is, and will continue to be, at variable rates of interest;
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have a material adverse effect on us if we fail to comply with financial and restrictive covenants in our debt agreements and an event of default occurs as a result of that failure that is not cured or waived;
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require us to dedicate a substantial portion of our cash flow to payments of our indebtedness and other financial obligations, thereby reducing the availability of our cash flow to fund working capital, capital expenditures and other general partnership requirements;
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limit our flexibility in planning for, or reacting to, changes in our business and the propane industry; and
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place us at a competitive disadvantage compared to our competitors that have proportionately less debt.
If we are unable to meet our debt service obligations and other financial obligations, we could be forced to restructure or refinance our indebtedness and other financial transactions, seek additional equity capital or sell our assets. We may then be unable to obtain such financing or capital or sell our assets on satisfactory terms, if at all.
A change of control could result in us facing substantial repayment obligations under our credit facility and our senior notes.
Our bank credit agreement and the indentures governing our senior notes contain provisions relating to change of control of our managing general partner, our partnership and our operating company. If these provisions are triggered, our outstanding bank indebtedness may become due. In such an event, there is no assurance that we would be able to pay the indebtedness, in which case the lenders under our credit facility would have the right to foreclose on our assets, which would have a material adverse effect on us. There is no restriction on the ability of our general partners to enter into a transaction which would trigger the change of control provisions.
Restrictive covenants in the agreements governing our indebtedness may reduce our operating flexibility.
The indentures governing our outstanding senior notes and agreements governing our revolving credit facilities and other future indebtedness contain or may contain various covenants limiting our ability and the ability of our specified subsidiaries to, among other things:
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pay distributions on, redeem or repurchase our equity interests or redeem or repurchase our subordinated debt;
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make investments;
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incur or guarantee additional indebtedness or issue preferred securities;
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create or incur certain liens;
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enter into agreements that restrict distributions or other payments from our restricted subsidiaries to us;
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consolidate, merge or transfer all or substantially all of our assets;
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engage in transactions with affiliates;
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create unrestricted subsidiaries; and
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create non-guarantor subsidiaries.
These restrictions could limit our ability and the ability of our subsidiaries to obtain future financings, make needed capital expenditures, withstand a future downturn in our business or the economy in general, conduct operations or otherwise take advantage of business opportunities that may arise. Our bank credit agreement contains covenants requiring us to maintain specified financial ratios and satisfy other financial conditions. We may be unable to meet those ratios and conditions. Any future breach of these covenants and our failure to meet
any of those ratios and conditions could result in a default under the terms of our bank credit agreement, which could result in the acceleration of our debt and other financial obligations. If we were unable to repay these amounts, the lenders could initiate a bankruptcy proceeding or liquidation proceeding or proceed against the collateral.
We are subject to operating 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 incident to handling, storing, transporting and providing customers with combustible products such as propane and natural gas. As a result, we have been, and likely will be, a defendant in legal proceedings and litigation arising in the ordinary course of business. We maintain insurance policies with insurers in such amounts and with such coverages and deductibles as we believe are reasonable and prudent. However, our insurance may not be adequate to protect us from all material expenses related to potential future claims for personal injury and property damage. In addition, the occurrence of a serious accident, whether or not we are involved, may have an adverse effect on the public’s desire to use our products.
Our operations are subject to compliance with environmental laws and regulations that can adversely affect our results of operations and financial condition.
Our operations are subject to stringent environmental laws and regulations of federal, state and local authorities. Such environmental laws and regulations impose numerous obligations, including the acquisition of permits to conduct regulated activities, the incurrence of capital expenditures to comply with applicable laws and restrictions on the generation, handling, treatment, storage, disposal and transportation of certain materials and wastes. Failure to comply with such environmental laws and regulations can result in the assessment of substantial administrative, civil and criminal penalties, the imposition of remedial liabilities and even the issuance of injunctions restricting or prohibiting our activities. Certain environmental laws impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances have been disposed or otherwise released. In the course of our operations, materials or wastes may have been spilled or released from properties owned or leased by us or on or under other locations where these materials or wastes have been taken for disposal. In addition, many of the properties owned or leased by us were previously operated by third parties whose management, disposal or release of materials and wastes was not under our control. Accordingly, we may be liable for the costs of cleaning up or remediating contamination arising out of our operations or as a result of activities by others who previously occupied or operated on properties now owned or leased by us. It is also possible that adoption of stricter environmental laws and regulations or more stringent interpretation of existing environmental laws and regulations in the future could result in additional costs or liabilities to us as well as the industry in general.
Cost reimbursements due our managing general partner may be substantial and will reduce the cash available for principal and interest on our outstanding indebtedness.
We reimburse our managing general partner and its affiliates, including officers and directors of our managing general partner, for all expenses they incur on our behalf. The reimbursement of expenses could adversely affect our ability to make payments of principal and interest on our outstanding indebtedness. Our managing general partner has sole discretion to determine the amount of these expenses. In addition, our managing general partner and its affiliates provide us with services for which we are charged reasonable fees as determined by our managing general partner in its sole discretion.
Failure to maintain effective internal controls in accordance with Section 404 of the Sarbanes-Oxley Act could cause us to incur additional expenditures of time and financial resources.
We have completed the process of documenting and testing our internal control procedures in order to satisfy the requirements of Section 404 of the Sarbanes-Oxley Act, which requires annual management assessments of the effectiveness of our internal controls over financial reporting and a report by our independent registered public
accounting firm on our controls over financial reporting. If, in the future, we fail to maintain the adequacy of our internal controls, as such standards are modified, supplemented or amended from time to time, we may not be able to ensure that we can conclude on an ongoing basis that we have effective internal controls over financial reporting in accordance with Section 404 of the Sarbanes-Oxley Act. Failure to achieve and maintain an effective internal control environment could cause us to incur substantial expenditures of management time and financial resources to identify and correct any such failure.
Climate change legislation, regulatory initiatives and litigation may adversely affect our operations.
On April 17, 2009, the EPA issued a notice of its proposed finding and determination that emissions of carbon dioxide, methane and other “greenhouse gases” presented an endangerment to human health and the environment because emissions of such gases are, according to EPA, contributing to warming of the earth’s atmosphere and other climatic changes. Once finalized, EPA’s finding and determination would allow the agency to begin regulating emissions of greenhouse gases under existing provisions of the federal Clean Air Act. In late September 2009, EPA proposed two sets of regulations in anticipation of finalizing its findings and determination, one rule to reduce emissions of greenhouse gases from motor vehicles and the other to control emissions of greenhouse gases from stationary sources. Although the motor vehicle rules are expected to be adopted in March 2010, it may take EPA several years to adopt and impose regulations limiting emissions of greenhouse gases from stationary sources. Any limitation on emissions of greenhouse gases from our equipment and operations could require us to incur costs to reduce emissions of greenhouse gases associated with our operations.
Also, on June 26, 2009, the U.S. House of Representatives passed the “American Clean Energy and Security Act of 2009,” or “ACESA,” which would establish an economy-wide cap-and-trade program to reduce U.S. emissions of “greenhouse gases” including carbon dioxide and methane that may contribute to warming of the Earth’s atmosphere and other climatic changes. ACESA would require a 17% reduction in greenhouse gas emissions from 2005 levels by 2020 and just over an 80% reduction of such emissions by 2050. Under this legislation, the EPA would issue a capped and steadily declining number of tradable emissions allowances to major sources of greenhouse gas emissions, including producers of NGLs (i.e., natural gas fractionators), local distribution companies and certain industrial facilities, so that such sources could continue to emit greenhouse gases into the atmosphere. These allowances would be expected to escalate significantly in cost over time. The U.S. Senate has begun work on its own legislation for restricting domestic greenhouse gas emissions and President Obama has indicated his support of legislation to reduce greenhouse gas emissions through an emission allowance system. Although it is not possible at this time to predict when the Senate may act on climate change legislation or how any bill passed by the Senate would be reconciled with ACESA, any future federal laws or implementing regulations that may be adopted to address greenhouse gas emissions could require us to incur increased operating costs and could adversely affect demand for the natural gas and NGL products and services we provide.
Risks Related to Our Propane Operations
Since weather conditions may adversely affect the demand for propane, our financial condition and results of operations are vulnerable to, and will be adversely affected by, warm winters.
Weather conditions have a significant impact on the demand for propane because many of our customers depend on propane principally for heating purposes. As a result, warm weather conditions will adversely impact our operating results and financial condition. Actual weather conditions can substantially change from one year to the next. Furthermore, warmer than normal temperatures in one or more regions in which we operate can significantly decrease the total volume of propane we sell. Consequently, our operating results may vary significantly due to actual changes in temperature. During seven of the last ten fiscal years temperatures were significantly warmer than normal in our areas of operation (based on the 30-year average consisting of years 1976 through 2005 published by the National Oceanic and Atmospheric Administration). We believe that our results of operations during these periods were adversely affected as a result of this warm weather.
Sudden and sharp propane price increases that cannot be passed on to customers may adversely affect our profit margins.
The propane industry is a “margin-based” business in which gross profits depend on the excess of sales prices over supply costs. As a result, our profitability is sensitive to changes in wholesale prices of propane caused by changes in supply or other market conditions. When there are sudden and sharp increases in the wholesale cost of propane, we may not be able to pass on these increases to our customers through retail or wholesale prices. Propane is a commodity and the price we pay for it can fluctuate significantly in response to changes in supply or other market conditions. We have no control over supply or market conditions. In addition, the timing of cost pass-throughs can significantly affect margins. Sudden and extended wholesale price increases could reduce our gross profits and could, if continued over an extended period of time, reduce demand by encouraging our retail customers to conserve or convert to alternative energy sources.
The highly competitive nature of the retail propane business could cause us to lose customers or affect our ability to acquire new customers, thereby reducing our revenues.
We have competitors and potential competitors who are larger and have substantially greater financial resources than we do. Also, because of relatively low barriers to entry into the retail propane business, numerous small retail propane distributors, as well as companies not engaged in retail propane distribution, may enter our markets and compete with us. Most of our propane retail branch locations compete with several marketers or distributors. The principal factors influencing competition with other retail marketers are:
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price;
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reliability and quality of service;
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responsiveness to customer needs;
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safety concerns;
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long-standing customer relationships;
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the inconvenience of switching tanks and suppliers; and
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the lack of growth in the industry.
We can make no assurances that we will be able to compete successfully on the basis of these factors. If a competitor attempts to increase market share by reducing prices, we may lose customers, which would reduce our revenues.
If we are not able to purchase propane from our principal suppliers, our results of operations would be adversely affected.
Most of our total volume purchases are made under supply contracts that have a term of one year, are subject to annual renewal, and provide various pricing formulas. Two of our suppliers, BP Amoco Corp. (12%) and Sunoco, Inc. (11%), accounted for 23% of propane purchases during the fiscal year ended September 30, 2009. In the event that we are unable to purchase propane from our significant suppliers, our failure to obtain alternate sources of supply at competitive prices and on a timely basis may hurt our ability to satisfy customer demand, reduce our revenues and adversely affect our results of operations.
Competition from other energy sources may cause us to lose customers, thereby reducing our revenues.
Competition from other energy sources, including natural gas and electricity, has been increasing as a result of reduced regulation of many utilities, including natural gas and electricity. Propane is generally not competitive with natural gas in areas where natural gas pipelines already exist because natural gas is a less expensive source of energy than propane. The gradual expansion of natural gas distribution systems and availability of natural gas in many areas that previously depended upon propane could cause us to lose customers, thereby reducing our revenues.
Our business would be adversely affected if service at our principal storage facilities or on the common carrier pipelines we use is interrupted.
Historically, a substantial portion of the propane purchased to support our operations has originated at Conway, Kansas, Hattiesburg, Mississippi and Mont Belvieu, Texas and has been shipped to us through major common carrier pipelines. Any significant interruption in the service at these storage facilities or on the common carrier pipelines we use would adversely affect our ability to obtain propane.
If we are not able to sell propane that we have purchased through wholesale supply agreements to either our own retail propane customers or to other retailers and wholesalers, the results of our operations would be adversely affected.
We currently are party to propane supply contracts and expect to enter into additional propane supply contracts which require us to purchase substantially all the propane production from certain refineries. Our inability to sell the propane supply in our own propane distribution business, to other retail propane distributors or to other propane wholesalers would have a substantial adverse impact on our operating results and could adversely impact our capital liquidity. We are also a party to fixed price sale contracts with certain customers that are backed-up by propane supply contracts. If a significant number of our customers default under these fixed price contracts the results of our operations would be adversely affected.
Energy efficiency and new technology may reduce the demand for propane and adversely affect our operating results.
Increased conservation and technological advances, including installation of improved insulation and the development of more efficient furnaces and other heating devices, have adversely affected the demand for propane by retail customers. Future conservation measures or technological advances in heating, conservation, energy generation or other devices might reduce demand for propane and adversely affect our operating results.
Due to our limited asset diversification, adverse developments in our propane business could adversely affect our operating results and reduce our ability to make distributions to our unitholders.
We rely substantially on the revenues generated from our propane business. Due to our limited asset diversification, an adverse development in this business would have a significantly greater impact on our financial condition and results of operations than if we maintained more diverse assets.
Risks Related to Our Midstream Operations
Federal, state or local regulatory measures could adversely affect our business.
Our operations are subject to federal, state and local regulatory authorities. Specifically, our natural gas storage facilities are subject to the regulation of the Federal Energy Regulatory Commission, or FERC.
Under the Natural Gas Act of 1938 (“NGA”), FERC has authority to regulate our natural gas facilities that provide natural gas transportation services in interstate commerce, including storage services. FERC’s authority to regulate those services includes the rates charged for the services, terms and conditions of service, certification and construction of new facilities, the extension or abandonment of services and facilities, the maintenance of accounts and records, the acquisition and disposition of facilities, the initiation and discontinuation of services, relationships with affiliated entities and various other matters. Natural gas companies may not charge rates that, upon review by FERC, are found to be unjust and unreasonable or unduly discriminatory. In addition, FERC prohibits natural gas companies from unduly preferring or unreasonably discriminating against any person with respect to pipeline transportation rates or terms and conditions of service. The rates and terms and conditions for interstate services provided by the Steuben facility are found in the FERC-approved tariff of Steuben Gas Storage Company. The rates and terms and conditions for interstate services provided by Stagecoach are found in the
FERC-approved tariff of Central New York Oil and Gas Company, LLC (“CNYOG”), our subsidiary and owner of the Stagecoach facility. The rates and terms and conditions for interstate services provided by the Thomas Corners facility are found in the FERC-approved tariff of Arlington Storage Company, LLC (“ASC”), our subsidiary and owner of the Thomas Corners facility.
Pursuant to the NGA, existing interstate transportation and storage rates may be challenged by complaint and are subject to prospective change by FERC. Additionally, rate increases proposed by the regulated pipeline or storage provider may be challenged by protest and such increases may ultimately be rejected by FERC. CNYOG and ASC currently hold authority from FERC to charge and collect market-based rates for services provided at the Stagecoach facility and the Thomas Corners facility, respectively. There can be no guarantee that CNYOG and ASC will be allowed to continue to operate under such a rate structure for the remainder of the Stagecoach and Thomas Corners facilities’ operating lives. Any successful complaint or protest against rates charged for CNYOG’s and ASC’s storage and related services, or CNYOG’s or ASC’s loss of market-based rate authority, could have an adverse impact on our revenues.
In addition, CNYOG or ASC’s market-based rate authority would be subject to further review if we acquire transportation facilities or additional storage capacity, if we or one of our affiliates provides storage or transportation services in the same market area or acquires an interest in another storage field that can link our facilities to the market area or if we or one of our affiliates acquire an interest in or is acquired by an interstate pipeline.
There can be no assurance that FERC will continue to pursue its approach of pro-competitive policies as it considers matters such as pipeline rates and rules and policies that may affect rights of access to natural gas transportation capacity, transportation and storage facilities. Any successful complaint or protest against our rates or loss of our market-based rate authority could have an adverse impact on our revenues associated with providing storage services. Failure to comply with applicable regulations under the NGA, Natural Gas Policy Act of 1978, Pipeline Safety Act of 1968 and certain other laws, and with implementing regulations associated with these laws, could result in the imposition of administrative and criminal remedies and civil penalties of up to $1,000,000 per day, per violation.
Our storage business depends on neighboring pipelines to transport natural gas.
Our Stagecoach natural gas storage business depends on Tennessee Gas Pipeline Company’s 300-Line and the Millennium Pipeline, currently the only pipelines to which it is interconnected, the Steuben natural gas storage facility depends on the Dominion Transmission System and the Thomas Corners natural gas storage facility depends on Tennessee Gas Pipeline Company’s 400-Line and the Millennium Pipeline. These pipelines are owned by parties not affiliated with us. Any interruption of service on the pipeline or lateral connections or adverse change in the terms and conditions of service could have a material adverse effect on our ability, and the ability of our customers, to transport natural gas to and from our facilities and have a corresponding material adverse effect on our storage revenues. In addition, the rates charged by the interconnected pipelines for transportation to and from our facilities affect the utilization and value of our storage services. Significant changes in the rates charged by these pipelines or the rates charged by other pipelines with which the interconnected pipelines compete could also have a material adverse effect on our storage revenues.
We expect to derive a significant portion of our revenues from our natural gas and LPG storage operations from a limited number of customers, and the loss of one or more of these customers could result in a significant loss of revenues and cash flow.
We expect to derive a significant portion of our revenues and cash flow in connection with our natural gas and LPG storage operations from a limited number of customers. The loss, nonpayment, nonperformance or impaired creditworthiness of one of these customers could have a material adverse effect on our business, results of operations and financial condition.
We compete with other natural gas storage companies and services that can substitute for storage services.
Our principal competitors in our natural gas storage market include other storage providers including among others Dominion Resources, Inc., NiSource Inc. and El Paso Corporation. These major pipeline natural gas transmission companies have existing storage facilities connected to their systems that compete with certain of our facilities. FERC has adopted policy that favors authorization of new storage projects, and there are numerous natural gas storage options in the New York/Pennsylvania geographic market. Pending and future construction projects, if and when brought on line, may also compete with our natural gas storage operations. Such projects may include FERC-certificated storage expansions and greenfield construction projects. We also compete with the numerous alternatives to storage available to customers, including pipeline balancing/no-notice services, seasonal/swing services provided by pipelines and marketers and on-system LNG facilities.
Expanding our business by constructing new midstream assets subjects us to risks.
One of the ways we may grow our business is through the expansion of our existing assets, such as the Thomas Corners development, the West Coast expansion project and the Watkins Glenn LPG storage facility. The construction of additional storage facilities or new pipeline interconnects involves numerous regulatory, environmental, political and legal uncertainties beyond our control and may require the expenditure of significant amounts of capital. If we undertake these projects, they may not be completed on schedule or at all or at the budgeted cost. Moreover, our revenues may not increase immediately upon the expenditure of funds on a particular project. For instance, if we build a new midstream asset, the construction will occur over an extended period of time, and we will not receive material increases in revenues until the project is placed in service. Moreover, we may construct facilities to capture anticipated future growth in production and/or demand in a region in which such growth does not materialize. As a result, new facilities may not be able to attract enough throughput to achieve our expected investment return, which could adversely affect our results of operations and financial condition.
We may not be able to retain existing customers or acquire new customers, which would reduce our revenues and limit our future profitability.
The renewal or replacement of existing contracts with our customers at rates sufficient to maintain current revenues and cash flows depends on a number of factors beyond our control, including competition from other pipelines and storage providers, and the price of, and demand for, natural gas in the markets we serve. The inability to renew or replace our current contracts as they expire and to respond appropriately to changing market conditions could have a negative effect on our profitability.
The fees charged by us to third parties under transmission, transportation and storage agreements may not escalate sufficiently to cover increases in costs and the agreements may not be renewed or may be suspended in some circumstances.
Our costs may increase at a rate greater than the rate that the fees we charge to third parties increase pursuant to our contracts with them. Furthermore, third parties may not renew their contracts with us. Additionally, some third parties’ obligations under their agreements with us may be permanently or temporarily reduced upon the occurrence of certain events, some of which are beyond our control, including force majeure events wherein the supply of either natural gas are curtailed or cut off. Force majeure events include (but are not limited to) revolutions, wars, acts of enemies, embargoes, import or export restrictions, strikes, lockouts, fires, storms, floods, acts of God, explosions, mechanical or physical failures of our equipment or facilities or those of third parties. If the escalation of fees is insufficient to cover increased costs, if third parties do not renew or extend their contracts with us or if any third party suspends or terminates its contracts with us, our financial results would be negatively impacted.
Our business would be adversely affected if operations at any of our facilities were interrupted.
Our operations are dependent upon the infrastructure that we have developed, including, storage facilities and various means of transportation. Any significant interruption at these facilities or pipelines or our customers’ inability to transmit natural gas to or from these facilities or pipelines for any reason would adversely affect our results of operations.
Risks Inherent in an Investment in Us
Unitholders have less ability to elect or remove management than holders of common stock in a corporation.
Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business, and therefore limited ability to influence management’s decisions regarding our business. Unitholders did not elect our managing general partner or its board of directors and will have no right to elect our managing general partner or its board of directors on an annual or other continuing basis. The board of directors of our managing general partner is chosen by the sole member of our managing general partner, Inergy Holdings, L.P. Although our managing general partner has a fiduciary duty to manage our partnership in a manner beneficial to Inergy, L.P. and our unitholders, the directors of our managing general partner also have a fiduciary duty to manage our managing general partner in a manner beneficial to its member, Inergy Holdings, L.P.
If unitholders are dissatisfied with the performance of our managing general partner, they will have little ability to remove our managing general partner. Our managing general partner generally may not be removed except upon the vote of the holders of 66 2/3% of the outstanding units voting together as a single class.
Our unitholders’ voting rights are further restricted by a provision in our partnership agreement providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partners and their affiliates, cannot be voted on any matter.
The control of our managing general partner may be transferred to a third party without unitholder consent.
Our managing general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of our unitholders. Furthermore, there is no restriction in our partnership agreement on the ability of the owner of our managing general partner, Inergy Holdings, L.P., from transferring its ownership interest in our managing general partner to a third party. The new owner of our managing general partner would then be in a position to replace the board of directors and officers of our managing general partner with its own choices and to control the decisions taken by our board of directors and officers.
Cost reimbursements due our managing general partner may be substantial and reduce our ability to pay the minimum quarterly distribution.
Before making any distributions on our units, we will reimburse our managing general partner for all expenses it has incurred on our behalf. In addition, our general partners and their affiliates may provide us with services for which we will be charged reasonable fees as determined by our managing general partner. The reimbursement of these expenses and the payment of these fees could adversely affect our ability to make distributions to you. Our managing general partner has sole discretion to determine the amount of these expenses and fees.
We may issue additional common units without unitholder approval, which would dilute our unitholders’ existing ownership interests.
We may issue an unlimited number of limited partner interests of any type without the approval of unitholders. The issuance of additional common units or other equity securities of equal rank will have the following effects:
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the proportionate ownership interest of our existing unitholders in us will decrease;
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the amount of cash available for distribution on each common unit or partnership security may decrease;
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the relative voting strength of each previously outstanding common unit will be diminished; and
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the market price of the common units or partnership securities may decline.
Our general partners have conflicts of interest and limited fiduciary responsibilities, which may permit our general partners to favor their own interests to the detriment of unitholders.
Inergy Holdings, L.P. and its affiliates directly and indirectly own an aggregate limited partner interest of 7.8% in us, own and control our managing general partner and own and control our non-managing general partner, which owns a 0.8% general partner interest. Inergy Holdings, L.P. also owns the incentive distribution rights under our partnership agreement. Conflicts of interest could arise in the future as a result of relationships between Inergy Holdings, L.P., our general partners and their affiliates, on the one hand, and the partnership or any of the limited partners, on the other hand. As a result of these conflicts our general partners may favor their own interests and those of their affiliates over the interests of our unitholders. The nature of these conflicts includes the following considerations:
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Our general partners may limit their liability and reduce their fiduciary duties, while also restricting the remedies available to unitholders for actions that might, without the limitations, constitute breaches of fiduciary duty. Unitholders are deemed to have consented to some actions and conflicts of interest that might otherwise be deemed a breach of fiduciary or other duties under applicable state law.
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Our general partners are allowed to take into account the interests of parties in addition to the partnership in resolving conflicts of interest, thereby limiting their fiduciary duties to our unitholders.
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Our managing general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings and reserves, each of which can affect the amount of cash that is distributed to unitholders.
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Our managing general partner determines whether to issue additional units or other equity securities of the partnership.
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Our managing general partner determines which costs are reimbursable by us.
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Our managing general partner controls the enforcement of obligations owed to us by it.
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Our managing general partner decides whether to retain separate counsel, accountants or others to perform services for us.
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Our managing general partner is not restricted from causing us to pay it or its affiliates for any services rendered on terms that are fair and reasonable to us or entering into additional contractual arrangements with any of these entities on our behalf.
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In some instances our managing general partner may borrow funds in order to permit the payment of distributions, even if the purpose or effect of the borrowing is to make incentive distributions.
The president and chief executive officer of our managing general partner effectively controls us through his control of the general partner of Inergy Holdings and our managing general partner.
The president and chief executive officer of both the general partner of Inergy Holdings and our managing general partner owns an economic interest of 57.0% in the general partner of Inergy Holdings and has voting control of the general partner of Inergy Holdings. He therefore controls the general partner of Inergy Holdings and through it, our managing general partner and may be able to influence unitholder votes. Control over these entities gives our president and chief executive officer substantial control over our and Inergy Holdings’ business and operations.
Our cash distribution policy limits our ability to grow.
Because we distribute all of our available cash, our growth may not be as rapid as businesses that reinvest their available cash to expand ongoing operations. If we issue additional units or incur debt to fund acquisitions and growth capital expenditures, the payment of distributions on those additional units or interest on that debt could increase the risk that we will be unable to maintain or increase our per unit distribution level.
Tax Risks to Common Unitholders
The tax treatment of publicly traded partnerships is subject to potential legislative, judicial or administrative changes. If we were treated as a corporation for federal income tax purposes, or if legislation is passed that may preclude us from qualifying for treatment as a partnership, or if we were to become subject to a material amount of entity level taxation for state tax purposes, then our cash available for distribution to our unitholders would be substantially reduced.
The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes. The present federal income tax treatment of publicly traded partnerships may be modified by administrative, legislative or judicial interpretation at any time. For example, Congress is considering changes to the existing federal income tax laws that may affect certain publicly traded partnerships.
If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum rate of 35%, and would likely pay state income tax at varying rates. Distributions would generally be taxed again as corporate distributions, and no income, gain, loss, deduction or credit would flow through to our unitholders. Because a tax would be imposed upon us as a corporation, our cash available for distribution would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our common units.
Current law or our business may change so as to cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity level taxation. In addition, because of widespread state budget deficits, several states are evaluating ways to subject partnerships to entity level taxation through the imposition of state income, franchise or other forms of taxation. If any state were to impose a tax upon us as an entity, the cash available to pay distributions would be reduced. Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity level taxation for federal, state or local income tax purposes, then the minimum quarterly distribution amount and the target distribution amount will be adjusted to reflect the impact of that law on us.
Our unitholders may be required to pay taxes even if they do not receive cash distributions from us.
Because our unitholders will be treated as partners to whom we will allocate taxable income which could be different in amount than the cash we distribute, they will be required to pay any federal income taxes and, in some cases, state and local income taxes on their share of our taxable income even if they do not receive any cash distributions from us. Unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that result from their share of our taxable income.
Tax gain or loss on disposition of our common units could be more or less than expected.
A unitholder who sells common units will recognize a gain or loss equal to the difference between the amount realized and his adjusted tax basis in those common units. Prior distributions to a unitholder in excess of the total net taxable income allocated to that unitholder, which decreased the tax basis in that unitholder’s common unit, will, in effect, become taxable income to that unitholder if the common unit is sold at a price greater than that unitholder’s tax basis in that common unit, even if the price is less than the original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income to that unitholder. In addition, if a unitholder sells units, the unitholder may incur a tax liability in excess of the amount of cash received from the sale.
Tax-exempt entities, regulated investment companies and foreign persons face unique tax issues from owning common units that may result in adverse tax consequences to them.
Investment in common units by tax-exempt entities, including employee benefit plans and individual retirement accounts (known as IRAs), and non-U.S. persons raises issues unique to them. For example, virtually all of our
income allocated to organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes imposed at the highest effective applicable tax rate, and non-U.S. persons will be required to file United States federal income tax returns and pay tax on their share of our taxable income.
The sale or exchange of 50% or more of our capital and profits interests within a twelve-month period will result in the termination of our partnership for federal income tax purposes.
We will be considered to have terminated our partnership for 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 for the year in which the termination occurs. Thus, if this occurs our unitholders will be allocated an increased amount of federal taxable income for the year in which we are considered to be terminated as a percentage of the cash distributed to unitholders with respect to that period. Although the amount of increase cannot be estimated because it depends upon numerous factors including the timing of the termination, the amount could be material. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead, we would be treated as a new partnership for 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.
Our unitholders will likely be subject to state and local taxes and return filing requirements in states where they do not live as a result of investing in our common units.
In addition to federal income taxes, our unitholders will likely be subject to other taxes, including foreign taxes, 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 and in which they do not reside. We own property and conduct business in numerous states in the United States. Unitholders may be required to file state and local income tax returns and pay state and local income taxes in many or all of the jurisdictions in which we do business or own property. Further, unitholders may be subject to penalties for failure to comply with those requirements. It is our unitholders’ responsibility to file all United States federal, state, local and foreign tax returns.
If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contest will reduce our cash available for distribution to you.
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 and our managing general partner because the costs will reduce our cash available for distribution.
We have adopted certain valuation methodologies and monthly conventions that may result in a shift of income, gain, loss and deduction between the general partner and the unitholders. The IRS may challenge this treatment, which could adversely affect the value of the common units.
When we issue additional units or engage in certain other transactions, we determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. The adopted methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and the general partner, which may be unfavorable to such unitholders. Moreover, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets
and a lesser portion allocated to our intangible assets. The IRS may challenge the adopted valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain, loss and deduction between the general partner and certain of our unitholders.
A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.
We treat each purchaser of common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could result in a unitholder owing more tax and may adversely affect the value of the common units.
To maintain the uniformity of the economic and tax characteristics of our common units, we have adopted certain depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. These positions may result in an understatement of deductions and an overstatement of income to our unitholders. For example, we do not amortize certain goodwill assets, the value of which has been attributed to certain of our outstanding units. A subsequent holder of those units may be entitled to an amortization deduction attributable to that goodwill under Internal Revenue Code Section 743(b). But, because we cannot identify these units once they are traded by the initial holder, we do not allocate any subsequent holder of a unit any such amortization deduction. This approach may understate deductions available to those unitholders who own those units and may result in those unitholders believing that they have a higher tax basis in their units than would be the case if the IRS strictly applied certain Treasury Regulations. This, in turn, may result in those unitholders reporting less gain or more loss on a sale of their units than would be the case if the IRS strictly applied certain Treasury Regulations.
The IRS may challenge the manner in which we calculate our unitholder’s basis adjustment under Section 743(b). If so, because neither we nor a unitholder can identify the units to which this issue relates once the initial holder has traded them, the IRS may assert adjustments to all unitholders selling units within the period under audit as if all unitholders owned such units.
A successful IRS challenge to this position or other positions we may take could adversely affect the amount of taxable income or loss allocated to our unitholders. It also could affect the gain from a unitholder’s sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.
We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular 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.
Under the terms of our Partnership Agreement, we prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under Treasury Regulations. If the IRS were to challenge this method or new Treasury regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.
Item 1B.
Item 1B. Unresolved Staff Comments.
None.
Item 2.
Item 2. Properties.
As of October 30, 2009, we owned 204 of our 312 retail propane customer service centers and leased the remaining centers. For more information concerning the location of our customer service centers see “Retail
Propane” under Item 1. We lease our Kansas City, Missouri headquarters. We lease underground storage facilities with an aggregate capacity of 19.4 million gallons of propane at nine locations under annual lease agreements. In addition, we own two underground storage facilities with an aggregate capacity of 23.4 million gallons of propane and butane. We also lease capacity in several pipelines pursuant to annual lease agreements.
Tank ownership and control at customer locations are important components to our retail propane operations and customer retention. As of September 30, 2009, we owned the following:
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1,250 bulk storage tanks at approximately 650 locations with typical capacities of 12,000 to 30,000 gallons;
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600,000 stationary customer storage tanks with typical capacities of 100 to 1,200 gallons; and
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170,000 portable propane cylinders with typical capacities of up to 35 gallons.
We believe that we have satisfactory title or valid rights to use all of our material properties. Although some of these properties are subject to liabilities and leases, liens for taxes not yet due and payable, encumbrances securing payment obligations under non-competition agreements entered in connection with acquisitions and immaterial encumbrances, easements and restrictions, we do not believe that any of these burdens will materially interfere with our continued use of these properties in our business, taken as a whole. Our obligations under our credit facility are secured by liens and mortgages on our real and personal property.
In addition, we believe that we have, or are in the process of obtaining, all required material approvals, authorizations, orders, licenses, permits, franchises and consents of, and have obtained or made all required material registrations, qualifications and filings with, the various state and local governmental and regulatory authorities that relate to ownership of our properties or the operation of our business.
Item 3.
Item 3. Legal Proceedings.
Our operations are subject to all operating hazards and risks normally incidental to handling, storing, transporting and otherwise providing for use by consumers of combustible liquids such as propane. As a result, at any given time we are a defendant in various legal proceedings and litigation arising in the ordinary course of business. We maintain insurance policies with insurers in amounts and with coverages and deductibles as the managing general partner believes are reasonable and prudent. However, we cannot assure you that this insurance will be adequate to protect us from all material expenses related to potential future claims for personal and property damage or that these levels of insurance will be available in the future at economical prices.
On September 26, 2008, we executed a Consent Agreement and Final Order (“CAFO”) that was filed by the United States Environmental Protection Agency, Region 1 (New England Region), in November 2008. The CAFO relates to violations of the Clean Water Act and the Oil Pollution Prevention regulations (i.e., the Spill Prevention Control and Countermeasure requirements for bulk oil storage facilities). Specifically, the CAFO relates to four facilities in New Hampshire (two of which we no longer operate). Although there were no significant releases or actual environmental damages alleged by EPA, a standard civil penalty of $157,500 was assessed for the various non-compliance issues at the facilities. Compliance strategies, including revised SPCC Plans, replacement and locking of valves, installation of fencing, lighting and upgraded alarms and secondary containment, have been developed and are being implemented. The initial compliance deadline was July 1, 2009. While some of the facilities were brought into full compliance by that date, other facilities required additional time due to various issues ranging from the unavailability of certain uniquely qualified media-specific contractors to difficulty negotiating with the facility owner to improve the facility, and in some situations we made the decision to terminate operations at a specific facility. Upon receipt of our request for extension, EPA agreed to extend the CAFO compliance schedules until December 31, 2009.
Item 4.
Item 4. Submission of Matters to a Vote of Security Holders.
No matter was submitted to a vote of the holders of our company’s common units during the fourth quarter of the fiscal year ended September 30, 2009.
PART II
Item 5.
Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities.
Since July 31, 2001 our company’s common units representing limited partner interests have been traded on NASDAQ’s Global Select National Market under the symbol “NRGY.” The following table sets forth the range of high and low bid prices of the common units, as reported by NASDAQ, as well as the amount of cash distributions declared per common unit for the periods indicated.
As of November 16, 2009, our company had issued and outstanding 59,817,087 common units, which were held by 41,988 unitholders of record.
Our company makes quarterly distributions to the partners within approximately 45 days after the end of each fiscal quarter in an aggregate amount equal to our available cash (as defined) for such quarter. Available cash generally means, with respect to each fiscal quarter, all cash on hand at the end of the quarter less the amount of cash that the managing general partner determines in its reasonable discretion is necessary or appropriate to:
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provide for the proper conduct of our business;
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comply with applicable law, any of our debt instruments, or other agreements; or
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provide funds for distributions to unitholders and to our non-managing general partner for any one or more of the next four quarters;
plus all cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter. Working capital borrowings are generally borrowings that are made under our working capital facility and in all cases are used solely for working capital purposes or to pay distributions to partners. The full definition of available cash is set forth in our partnership agreement (as amended), which is incorporated by reference herein as an exhibit to this report. For a discussion of restrictions on our ability to distribute cash, please see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
In August 2008, we issued 809,389 common units in conjunction with the acquisition of US Salt and in October 2008, we issued 309,194 common units to Blu-Gas in a private placement as a portion of the purchase price.
On March 23, 2006, our shelf registration statement (File No. 333-132287) was declared effective by the Securities and Exchange Commission for the periodic sale of up to $1.0 billion of common units, partnership securities and debt securities, or any combination thereof. Pursuant to the shelf registration statement, we are permitted to issue these securities from time to time for general business purposes, including debt repayment, future acquisitions, capital expenditures and working capital, or for other potential uses identified in a prospectus supplement. In June 2006 and February 2007, we issued 4,312,500 common units (which included 562,500 common units issued as result of the underwriters exercising their over-allotment provision) and 3,450,000 common units (which included 450,000 common units issued as result of the underwriters exercising their over-allotment provision), respectively. In March 2009 we issued 4,000,000 common units and in April 2009 we issued an additional 418,000 common units as result of the underwriters exercising their over-allotment provision. In August 2009 we issued 3,500,000 common units and in September 2009 we issued an additional 525,000 common units as result of the underwriters exercising their over-allotment provision. The proceeds from these issuances were utilized to pay down borrowings under our credit facility. No further partnership securities or debt securities have been offered under the shelf registration except as described above. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Liquidity and Sources of Capital” under Item 7.
On September 10, 2009, our new shelf registration statement (File No. 333-158066) was declared effective by the Securities and Exchange Commission for the periodic sale of up to $1.0 billion of common units, partnership securities and debt securities, or any combination thereof. No securities have been issued under this registration statement, thus the full amount is available.
The following table sets forth in tabular format, a summary of our company’s equity compensation plan information as of September 30, 2009:
Equity Compensation Plan Information
Item 6.
Item 6. Selected Financial Data.
The following table sets forth selected consolidated financial data and other operating data of Inergy, L.P. The selected historical consolidated financial data of Inergy, L.P. as of and for the years ended September 30, 2009, 2008, 2007, 2006 and 2005 are derived from the audited consolidated financial statements of Inergy, L.P and Inergy Partners, LLC. The historical consolidated financial data of Inergy, L.P. and Inergy Partners, LLC include the results of operations of its acquisitions from the effective date of the respective acquisitions.
“EBITDA” shown in the table below is defined as income before taxes, plus net interest expense (inclusive of write-off of deferred financing costs) and depreciation and amortization expense. Adjusted EBITDA represents EBITDA excluding the gain or loss on derivative contracts associated with retail propane fixed price sales contracts, the gain or loss on the disposal of assets and non-cash compensation expenses. EBITDA and Adjusted
EBITDA should not be considered an alternative to net income, income before income taxes, cash flows from operating activities, or any other measure of financial performance calculated in accordance with generally accepted accounting principles as those items are used to measure operating performance, liquidity or ability to service debt obligations. We believe that EBITDA and Adjusted EBITDA provide additional information for evaluating our financial performance without regard to our financing methods, capital structure and historical cost basis. Further, we believe that EBITDA and Adjusted EBITDA provide additional information for evaluating our ability to make the minimum quarterly distribution and are presented solely as a supplemental measure. EBITDA and Adjusted EBITDA, as we define it, may not be comparable to EBITDA and Adjusted EBITDA or similarly titled measures used by other corporations or partnerships.
The data in the following tables should be read together with and is qualified in its entirety by reference to, the historical consolidated financial statements and the accompanying notes included in this report. The tables should be read together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” under Item 7.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
Forward-Looking Statements
This report, including information included or incorporated by reference in this report, contains forward-looking statements concerning the financial condition, results of operations, plans, objectives, future performance and business of our company and its subsidiaries. These forward-looking statements include:
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statements that are not historical in nature, but not limited to, our belief that our acquisition expertise should allow us to continue to grow through acquisitions; our belief that we will have adequate propane supply to support our retail operations; and our belief that our diversification of suppliers will enable us to meet supply needs; and
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statements preceded by, followed by or that contain forward-looking terminology including the words “believe,” “expect,” “may,” “will,” “should,” “could,” “anticipate,” “estimate,” “intend” or similar expressions.
Forward-looking statements are not guarantees of future performance or results. They involve risks, uncertainties and assumptions. Actual results may differ materially from those contemplated by the forward-looking statements due to, among others, the following factors:
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weather conditions;
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price and availability of propane, and the capacity to transport to market areas;
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the ability to pass the wholesale cost of propane through to our customers;
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costs or difficulties related to the integration of the business of our company and its acquisition targets may be greater than expected;
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governmental legislation and regulations;
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local economic conditions;
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the demand for high deliverability natural gas storage capacity in the Northeast;
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the availability of natural gas and the price of natural gas to the consumer compared to the price of alternative and competing fuels;
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our ability to successfully implement our business plan for our natural gas storage facilities;
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labor relations;
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environmental claims;
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competition from the same and alternative energy sources;
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operating hazards and other risks incidental to transporting, storing and distributing propane;
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energy efficiency and technology trends;
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interest rates;
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the price and availability of debt and equity financing; and
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large customer defaults.
We have described under “Factors That May Affect Future Results of Operations, Financial Condition or Business” additional factors that could cause actual results to be materially different from those described in the forward-looking statements. Other factors that we have not identified in this report could also have this effect. You are cautioned not to put undue reliance on any forward-looking statement, which speaks only as of the date it was made.
General
We are a Delaware limited partnership formed to own and operate a growing retail and wholesale propane supply, marketing and distribution business. We also own and operate a growing midstream business that includes three natural gas storage facilities (“Stagecoach”, “Steuben” and “Thomas Corners”), a liquefied petroleum gas (“LPG”) storage facility (“Bath”), a natural gas liquids (“NGL”) business and a solution-mining and salt production company (“US Salt”). We further intend to pursue our growth objectives in the propane business through, among other things, future acquisitions. Our acquisition strategy focuses on propane companies that meet our acquisition criteria, including targeting acquisition prospects that maintain a high percentage of retail sales to residential customers, operating in attractive markets and focusing our operations under established and locally recognized trade names. Our midstream growth objectives focus both on organically expanding our existing assets and acquiring future operations that leverage our existing operating platform, produce predominantly fee-based cash flow characteristics and have future organic or commercial expansion characteristics.
Both of our operating segments, propane and midstream, are supported by business development personnel groups employed by the Partnership. These groups’ daily responsibilities include research, sourcing, financial analysis and due diligence of potential acquisition targets and organic growth opportunities. These employees work closely with the operators of both of our segments in the course of their work to ensure the appropriate growth opportunities are pursued. During fiscal 2009, they evaluated approximately 100 potential acquisitions.
We have grown primarily through acquisitions. Since the inception of our predecessor in November 1996 through September 30, 2009, we have acquired 84 companies, 78 propane companies and 6 midstream businesses, for an aggregate purchase price of approximately $1.8 billion, including working capital, assumed liabilities and acquisition costs.
In October 2008, we acquired the assets of the Blu-Gas group of companies (“Blu-Gas”), in April 2009, we acquired the assets of Newton’s Gas Service, Inc. (“Newton’s Gas”) and on June 30, 2009, we acquired the assets of F.G. White Company, Inc. (“F.G. White”). The aggregate purchase price of these acquisitions, net of cash acquired, was $11.8 million. The purchase price allocation for these acquisitions has been prepared on a preliminary basis pending final asset valuation and asset rationalization, and changes are expected when additional information becomes available. Changes to final asset valuation of prior fiscal year acquisitions have been included in our consolidated financial statements but are not material.
For the fiscal year ended September 30, 2009, we sold 310.0 million gallons of propane to retail customers and sold 380.6 million gallons of propane to wholesale customers.
The results of operations discussed below are those of Inergy, L.P. Audited financial statements for Inergy, L.P. are included elsewhere in this Form 10-K.
The retail propane distribution business is largely seasonal due to propane’s primary use as a heating source in residential and commercial buildings. As a result, cash flows from operations are generally highest from November through April when customers pay for propane purchased during the six-month peak heating season of October through March. Our propane operations generally experience net losses in the six-month, off season of April through September.
Because a substantial portion of our propane is used in the weather-sensitive residential markets, the temperatures realized in our areas of operations, particularly during the six-month peak heating season, have a significant effect on our financial performance. In any given area, warmer-than-normal temperatures will tend to result in reduced propane use, while sustained colder-than-normal temperatures will tend to result in greater propane use. Therefore, we use information on normal temperatures in understanding how historical results of operations are affected by temperatures that are colder or warmer than normal and in preparing forecasts of
future operations, which are based on the assumption that normal weather will prevail in each of our operating regions. “Heating degree days” are a general indicator of how weather impacts propane usage and are calculated for any given period by adding the difference between 65 degrees and the average temperature of each day in the period (if less than 65 degrees). While a substantial portion of our propane is used by our customers for heating needs, our propane operations are geographically diversified and not all of our propane sales are weather sensitive. Together, these factors may make it difficult to draw definitive conclusions as to the correlation of our gallon sales to weather calculations comparing weather in a year to normal or to the prior year.
In determining actual and normal weather for a given period of time, we compare the actual number of heating degree days for the period to the average number of heating degree days for a longer, historical time period assumed to more accurately reflect the average normal weather, in each case as such information is published by the National Oceanic and Atmospheric Administration, for each measuring point in each of our regions. When we discuss “normal” weather in our results of operations presented below we are referring to a 30-year average consisting of the years 1979 through 2009. We then calculate weighted averages, based on retail volumes attributable to each measuring point, of actual and normal heating degree days within each region. Based on this information, we calculate a ratio of actual heating degree days to normal heating degree days, first on a regional basis consistent with our operational structure and then on a partnership-wide basis.
The retail propane business is a “margin-based” business where the level of profitability is largely dependent on the difference between sales prices and product costs. Propane prices have continued to be volatile during 2009. At the main pricing hub of Mount Belvieu Texas during the fiscal year ended September 30, 2009, propane prices ranged from a low of $0.53 per gallon to a high of $1.41 per gallon and a price of $0.94 per gallon at September 30, 2009. Our ability to pass on price increases to our customers and our hedging program limits the impact that such volatility has had on our results from operations. In the future, we will continue to hedge virtually 100% of our exposure from fixed price sales. While we have historically been successful in passing on any price increases to our customers, there can be no guarantees that this trend will continue in the future. In periods of increasing costs, we have experienced a decline in our gross profit as a percentage of revenues. In addition, during those periods we have historically experienced conservation of propane gallons used by our customers which has resulted in a decline in gross profit. In periods of decreasing costs, we have experienced an increase in our gross profit as a percentage of revenues. There is no assurance that because propane prices decline customers will use more propane and thus historical gallon sales declines we have attributed to customer conservation will reverse. The prices of crude oil and natural gas had maintained historically high costs in calendar year 2007 and 2008 before falling in late 2008 and somewhat leveling off in early 2009 and, since propane is a by-product of these commodities, it too has been at historically high levels over this same time frame. As such, our selling prices of propane have been at higher levels in order to attempt to maintain our historical gross margin per gallon. We do not attempt to predict or control the underlying commodity prices; however, we monitor these prices daily and adjust our operations and retail prices to maintain expected margins by passing on the wholesale costs to end users of our product. We believe that volatility in commodity prices will continue, and our ability to adjust to and manage our operations in response to this volatility may impact our operations and financial results.
We believe that the economic downturn that began in the second half of 2008 has caused certain of our retail propane customers to conserve and thereby purchase less propane. This trend is expected to continue throughout the life of the economic downturn. In addition, although we believe the economic downturn has not currently had a material impact on our cash collections, it is possible that a prolonged economic downturn could have a negative impact on our future cash collections.
We believe our wholesale supply, marketing and distribution business complements our retail distribution business. Through our wholesale operations, we distribute propane and also offer price risk management services to propane retailers, resellers and other related businesses as well as energy marketers and dealers, through a variety of financial and other instruments, including:
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forward contracts involving the physical delivery of propane;
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swap agreements which require payments to (or receipt of payments from) counterparties based on the differential between a fixed and variable price for propane; and
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options, futures contracts on the New York Mercantile Exchange and other contractual arrangements.
We engage in derivative transactions to reduce the effect of price volatility on our product costs and to help ensure the availability of propane during periods of short supply. We attempt to balance our contractual portfolio by purchasing volumes only when we have a matching purchase commitment from our wholesale customers. However, we may experience net unbalanced positions from time to time.
Our midstream operations primarily include the storage, processing, fractionation and sale of natural gas and NGLs and, to a lesser extent, the wholesale distribution of salt from solution mining operations of US Salt, which was acquired in August 2008. The cash flows from these operations are predominantly fee-based under one to ten year contracts with substantial, creditworthy counterparties and, therefore, are generally economically stable and not significantly affected in the short term by changing commodity prices, seasonality or weather fluctuations.
We believe our midstream operations could be negatively affected in the long-term by sustained downturns or sluggishness in the economy, which could affect long-term demand and market prices for natural gas and NGLs, all of which are beyond our control and could impair our ability to meet our long-term goals. However, we also believe that the predominately contractual fee-based nature of our midstream operations may serve to mitigate this potential risk.
The majority of our operating cash flows in our midstream operations are generated by our natural gas storage operations. Most of our natural gas storage revenues are based on regulated market-based tariff rates, which are driven in large part by competition and demand for our storage capacity and deliverability. Demand for storage in our key midstream market in the northeastern United States is projected to continue to be strong, driven by a shortage in storage capacity and a higher than average annual growth in natural gas demand. This demand growth is primarily driven by the natural gas-fired electric generation sector. The natural gas industry is currently experiencing a significant shift in the sources of supply, and this dramatic change could affect our operations. Traditionally, supply to our markets has come from the Gulf Coast region, onshore and offshore, as well as from Canada. The national supply profile is shifting to new sources of natural gas from basins in the Rockies, Mid-Continent, Appalachia and East Texas. In addition, the natural gas supply outlook includes new LNG regasification facilities under various stages of development in multiple locations. LNG can be a new source of potential supply, but the timing and extent of incremental supply ultimately realized from LNG is yet to be determined and, at present, LNG remains a small percentage of the overall supply to the markets we serve. These supply shifts and other changes to the natural gas market may have an impact on our storage operations and our development plans in the northeastern United States and may ultimately drive the need for more domestic capacity for natural gas storage. Currently, we have committed to capital expansion projects at our Finger Lakes LPG storage expansion. The Finger Lakes LPG storage expansion project relates to the development of certain caverns acquired in the acquisition of US Salt in August 2008. The solution mining process creates caverns that can be developed into LPG or Natural Gas storage after the salt has been extracted. The Finger Lakes LPG expansion project is expected to convert certain of the caverns at US Salt into LPG storage with a capacity of up to 5 million barrels. This project is expected to be completed in spring 2010.
As we execute on our strategic objectives, capital expansion projects will continue to be an important part of our growth plan. We have committed capital and investment expenditures at September 30, 2009, of $10.4 million in our midstream operations. These capital requirements, along with the refinancings of normal maturities of existing debt, will require us to continue long-term borrowings. An inability to access capital at competitive rates could adversely affect our ability to implement our strategy. Market disruptions or a downgrade in our credit ratings may increase the cost of borrowing or adversely affect our ability to access one or more sources of liquidity. During the past several years, capital expansion projects have been exposed to cost pressures associated with the availability of skilled labor and the pricing of materials. Although certain costs have begun to decrease, there will be continual focus on project management activities to address these pressures as we move forward with planned expansion opportunities. Significant cost increases could negatively affect the returns ultimately earned on current and future expansions.
Our midstream operations in the United States are subject to regulations at the federal and state level. Regulations applicable to the gas storage industry have a significant effect on the nature of our midstream operations and the manner in which they operate. Changes to regulations are ongoing and we cannot predict the future course of changes in the regulatory environment or the ultimate effect that any future changes will have on our midstream operations.
Results of Operations
Fiscal Year Ended September 30, 2009 Compared to Fiscal Year Ended September 30, 2008
The following table summarizes the consolidated income statement components for the fiscal years ended September 30, 2009 and 2008, respectively (in millions):
The following table summarizes revenues, including associated volume of gallons sold, for the years ended September 30, 2009 and 2008, respectively (in millions):
Volume. During fiscal 2009, we sold 310.0 million retail gallons of propane, a decrease of 21.9 million gallons or 6.6% from the 331.9 million retail gallons of propane sold during fiscal 2008. Gallons sold during fiscal 2009 declined compared to fiscal 2008 as a result of lower volumes sold at our existing locations of 35.1 million gallons partially offset by a 13.2 million gallon increase from acquisition-related volume. Although the weather
in our areas of operations was 7% colder than the prior year period when compared to our calculations using degree day data provided by NOAA, the increase in gallon sales associated with this colder weather was more than offset by (1) continued customer conservation, which we believe resulted primarily from the lingering effects of the higher cost of propane that existed at the end of our fiscal year 2008, as well as the overall weak United States economic environment, and (2) volume declines from net customer losses during the periods of high propane costs, including low margin and less profitable customers.
Wholesale gallons delivered increased 22.1 million gallons, or 6.2%, to 380.6 million gallons in fiscal 2009 from 358.5 million gallons in fiscal 2008. The increase was due primarily to greater volumes sold to existing customers and addition of new customers.
The total natural gas liquid gallons sold or processed by our West Coast NGL operations increased 10.8 million gallons, or 4.2%, to 269.9 million gallons in fiscal 2009 from 259.1 million gallons in fiscal 2008. This increase was primarily attributable to renewal of certain customer contracts and the addition of new contracts.
During fiscal 2009 and 2008, our Northeast natural gas and LPG storage facilities were 100% contracted.
Revenues. Revenues in fiscal 2009 were $1,570.6 million, a decrease of $308.3 million, or 16.4% from $1,878.9 million in fiscal 2008.
Revenues from retail propane sales were $736.7 million for the year ended September 30, 2009, a decrease of $104.0 million, or 12.4%, compared to $840.7 million for the year ended September 30, 2008. This decrease resulted primarily from a combination of a lower overall average selling price of propane due to a reduction in the wholesale cost of propane and a decline in gallons sold to existing customers as described above, which together contributed to a $136.3 million revenue decline, partially offset by acquisition-related sales, which resulted in higher revenues of $32.3 million.
Revenues from wholesale propane sales were $387.7 million in fiscal 2009, a decrease of $158.4 million or 29.0%, from $546.1 million in fiscal 2008. This decrease resulted primarily from the lower average selling price of propane, which contributed $192.0 million to the decrease in revenues. The lower selling price for our wholesale propane sales in fiscal 2009 compared to fiscal 2008 was the result of the lower cost of propane. This decrease was partially offset by increases in volume sold to existing and new customers.
Revenues from other retail sales, which primarily include distillates, service, rental, appliance sales and transportation services, were $209.2 million in fiscal 2009, a decrease of $13.8 million, or 6.2% from $223.0 million in fiscal 2008. Revenues from other retail sales decreased $56.0 million due to lower distillate sales from existing locations and a decline in other revenues of $5.9 million, partially offset by higher revenues of $48.1 million attributable to acquisitions. The decrease in distillate revenues at existing locations was the result of lower volume sold coupled with a decline in the comparable average selling price of the distillates resulting from a lower wholesale cost.
Revenues from storage, fractionation and other midstream activities were $237.0 million in fiscal 2009, a decrease of $32.1 million or 11.9% from $269.1 million in fiscal 2008. Revenues from our West Coast NGL operations decreased $81.3 million primarily as a result of decreases in commodity cost and expected changes in the variety of natural gas liquid products sold. Partially offsetting this decrease was a $44.2 million increase due to the acquisition of US Salt. In addition, revenues at our Bath LPG Storage Facility and Stagecoach Storage Facility increased due to an increase in contractual rates and the commencement of operations on the Stagecoach North Lateral connecting to Millennium Pipeline in December 2008.
Cost of Product Sold. Cost of product sold for fiscal 2009 was $996.9 million, a decrease of $379.8 million, or 27.6%, from $1,376.7 million in fiscal 2008.
Retail propane cost of product sold was $373.6 million for the year ended September 30, 2009, compared to $527.9 million for the year ended September 30, 2008. This $154.3 million, or 29.2%, decrease in retail propane cost of product sold was driven by an approximate 25% decline in the average per gallon cost of propane along with lower volume sales at our existing locations as discussed above, which together reduced costs $169.7 million. These factors were partially offset by a $14.1 million increase in the cost of product sold associated with acquisition-related volume and a $1.3 million increase in cost of product sold related to changes in non-cash charges on derivative contracts associated with retail propane fixed price sales contracts.
Wholesale propane cost of product sold in fiscal 2009 was $363.8 million, a decrease of $161.3 million or 30.7%, from wholesale cost of product sold of $525.1 million in fiscal 2008. These lower costs were primarily a result of a $193.6 million decrease due to the lower average cost of propane. This decrease was partially offset by increases in volume sold to existing and new customers.
Other retail cost of product sold was $124.8 million for the year ended September 30, 2009, compared to $146.6 million for the year ended September 30, 2008. This $21.8 million, or 14.9%, decrease was primarily due to a $57.1 million reduction in cost of product sold related to distillate sales at existing locations due to both declines in volumes sold and the average cost of product. Also contributing to the decline in other retail cost of product sold was a reduction in costs related to other products and services of $1.9 million. These factors were partially offset by higher costs associated with acquisitions of $37.2 million.
Storage, fractionation and other midstream cost of product sold was $134.7 million, a decrease of $42.4 million, or 23.9%, from $177.1 million in fiscal 2008. Costs from our West Coast NGL operations were $76.0 million lower primarily as a result of decreases in commodity cost and expected changes in the variety of natural gas liquid products sold. Partially offsetting this decrease was a $28.2 million increase in cost due to the acquisition of US Salt.
Our retail and wholesale cost of product sold consists primarily of tangible products sold including all propane, distillates and other natural gas liquids sold and all propane-related appliances sold. Other costs incurred in conjunction with the distribution of these products are included in operating and administrative expenses and consist primarily of wages to delivery personnel, delivery vehicle costs consisting of fuel costs, repair and maintenance and lease expense. Costs associated with delivery vehicles amounted to $62.0 million and $67.0 million for fiscal 2009 and 2008, respectively. In addition, the depreciation expense associated with the delivery vehicles and customer tanks is reported within depreciation and amortization expense and amounted to $33.0 million in fiscal 2009 and 2008. Since we include these costs in our operating and administrative expense and depreciation and amortization expense rather than in cost of product sold, our results may not be comparable to other entities in our lines of business if they include these costs in cost of product sold.
Our storage, fractionation and other midstream cost of product sold consists primarily of commodity and transportation costs. Other costs incurred in conjunction with these services are included in operating and administrative expense and depreciation and amortization expense and consist primarily of depreciation, vehicle costs consisting of fuel costs and repair and maintenance and wages. Depreciation expense for storage, fractionation and other midstream amounted to $36.9 million and $27.7 million for fiscal 2009 and 2008, respectively. Vehicle costs combined with wages for personnel directly involved in providing midstream services amounted to $2.7 million and $3.3 million for fiscal 2009 and 2008, respectively. Since we include these costs in our operating and administrative expense and depreciation and amortization expense rather than in cost of product sold, our results may not be comparable to other entities in our lines of business if they include these costs in cost of product sold.
Gross Profit. Gross profit for fiscal 2009 was $573.7 million, an increase of $71.5 million, or 14.2%, from $502.2 million during fiscal 2008.
Retail propane gross profit was $363.1 million in fiscal 2009, an increase of $50.3 million, or 16.1%, compared to $312.8 million in fiscal 2008. This increase in retail propane gross profit was mostly attributable to a higher cash margin per gallon, which contributed an increase to gross profit of $66.5 million, and an increase of $18.2 million associated with acquisitions, partially offset by a $33.1 million decline in gross profit resulting from lower retail gallon sales at existing locations as discussed above and a $1.3 million decline related to changes in non-cash charges on derivative contracts associated with retail propane fixed price sales contracts. The increase in cash margin per gallon was primarily the result of our selling price of propane declining at a slower rate in certain markets than the underlying cost of propane declined.
Wholesale propane gross profit was $23.9 million in fiscal 2009 compared to $21.0 million in fiscal 2008, an increase of $2.9 million or 13.8%. This increase was primarily the result of both increased volumes sold and higher margins that we were able to attain in certain regions where supply disruption occurred in 2009.
Other retail gross profit was $84.4 million for the year ended September 30, 2009, compared to $76.4 million for the year ended September 30, 2008. This $8.0 million, or 10.5%, increase was due primarily to a $10.9 million increase from acquisitions and a $1.1 million increase in distillate gross profit, partially offset by a $4.0 million decline in gross profit for other products and services.
Storage, fractionation and other midstream gross profit was $102.3 million in fiscal 2009 compared to $92.0 million in fiscal 2008, an increase of $10.3 million, or 11.2%. Approximately $16.0 million of this increase was due to the acquisition of US Salt, which was partially offset by a decrease in gross profit from our West Coast NGL operations. The decrease in West Coast gross profit is partially attributable to losses taken on certain commodity contracts due to a brief delay in our butane isomerization unit being placed in service. The aforementioned isomerization unit was placed in service in July 2009. The decrease is also attributable to the non-renewal of certain customer contracts.
Operating and Administrative Expenses. Operating and administrative expenses were $279.6 million in fiscal 2009 compared to $265.6 million in fiscal 2008. This $14.0 million, or 5.3%, increase in operating expenses was due primarily to acquisitions and incentive compensation, which increased $16.1 million and $8.5 million, respectively. Offsetting these increases were lower operating expenses from existing operations of $10.6 million comprised predominantly of lower salaries, vehicle expenses and other operating expenses.
Depreciation and Amortization. Depreciation and amortization increased to $115.8 million in fiscal 2009 from $98.0 million in fiscal 2008. This $17.8 million, or 18.2%, increase was primarily the result of acquisitions and completed expansion projects being placed into service in our midstream segment.
Loss on Disposal of Assets. Loss on disposal of assets decreased $6.3 million, or 54.8%, to $5.2 million in fiscal 2009 compared to $11.5 million in fiscal 2008. The losses recognized in fiscal 2009 and 2008 include losses of $4.9 million and $11.5 million, respectively, related to assets held for sale, which have been written down to their estimated selling price. In addition, we had other losses in fiscal 2009 of $0.3 million. These assets, both those sold and those held for sale, consist primarily of vehicles, tanks and real estate deemed to be excess, redundant or underperforming assets. In fiscal 2009 and 2008, these assets were identified primarily as a result of losses due to disconnecting customer installations of unprofitable accounts due to low margins, poor payment history or low volume usage.
Interest Expense. Interest expense increased to $69.7 million in fiscal 2009 compared to $60.9 million in fiscal 2008. This $8.8 million, or 14.4%, increase was due to a $220.1 million increase in average debt outstanding associated with acquisitions and capital improvement projects, partially offset by lower average interest rates associated with our floating rate debt and benefits from our interest rate swap agreements. Additionally, during fiscal 2009 and 2008, we capitalized $14.8 million and $5.5 million, respectively, of interest related to certain capital improvement projects in our midstream segment as further described below in the “Liquidity and Sources of Capital-Capital Resource Activities” section.
Interest of non-controlling partners in ASC’s consolidated net income. We acquired a majority interest in the operations of Steuben when we acquired 100% of the membership interest in ASC in October 2007. ASC holds a majority interest in the operations of Steuben.
Net Income. Net income for fiscal 2009 was $101.4 million compared to net income for fiscal 2008 of $65.1 million. The $36.3 million, or 55.8%, increase in net income is primarily attributable to higher gross profit, partially offset by higher operating expenses, depreciation and amortization and interest expense in fiscal 2009.
EBITDA and Adjusted EBITDA. The following tables summarize EBITDA and Adjusted EBITDA for the fiscal years ended September 30, 2009 and 2008, respectively (in millions):
(a) ITDA-Interest, taxes, depreciation and amortization.
EBITDA is defined as income before taxes, plus net interest expense and depreciation and amortization expense. For the years ended September 30, 2009 and 2008, EBITDA was $287.1 million and $223.9 million, respectively. This $63.2 million improvement in EBITDA was primarily attributable to net higher gross profit,
which more than offset the increase in cash operating expenses in 2009. As indicated in the table, Adjusted EBITDA represents EBITDA excluding the gain or loss on derivative contracts associated with retail propane fixed price sales contracts, the gain or loss on the disposal of assets and non-cash compensation expenses. Adjusted EBITDA was $296.8 million for fiscal 2009 compared to $239.0 million in fiscal 2008. EBITDA and Adjusted EBITDA should not be considered an alternative to net income, income before income taxes, cash flows from operating activities, or any other measure of financial performance calculated in accordance with generally accepted accounting principles as those items are used to measure operating performance, liquidity or the ability to service debt obligations. We believe that EBITDA and Adjusted EBITDA provide additional information for evaluating our financial performance without regard to our financing methods, capital structure and historical cost basis. Further, we believe that EBITDA and Adjusted EBITDA provide additional information for evaluating our ability to make the minimum quarterly distribution and are presented solely as supplemental measures. EBITDA and Adjusted EBITDA, as we define them, may not be comparable to EBITDA and Adjusted EBITDA or similarly titled measures used by other corporations or partnerships.
Fiscal Year Ended September 30, 2008 Compared to Fiscal Year Ended September 30, 2007
The following table summarizes the consolidated income statement components for the fiscal years ended September 30, 2008 and 2007, respectively (in millions):
* not meaningful
The following table summarizes revenues, including associated volume of gallons sold, for the years ended September 30, 2008 and 2007, respectively (in millions):
Volume. During fiscal 2008, we sold 331.9 million retail gallons of propane compared to 362.2 million retail gallons of propane during fiscal 2007. This 30.3 million gallon, or 8.4%, net decline was due primarily to customer conservation, which we believe has resulted, in large part, from the higher average cost of Mt. Belvieu propane. The average cost of Mt. Belvieu propane increased 49% during fiscal 2008 as compared to fiscal 2007. To a lesser extent, volume declines arising from a loss of less profitable customers and fewer gallon sales to lower margin customers, including agricultural sales, contributed to the decline in gallons sold during the year. Also contributing to the decline was the warmer weather during fiscal 2008, which, on average for our operating areas, was slightly warmer than fiscal 2007 and 7% warmer than normal. These factors that resulted in a decrease in comparable gallon sales were partially offset by acquisition-related volume, which resulted in an increase of 12.2 million gallons during fiscal 2008 compared to fiscal 2007.
Wholesale gallons delivered decreased 25.4 million gallons, or 6.6%, to 358.5 million gallons in fiscal 2008 from 383.9 million gallons in fiscal 2007. This change was primarily attributable to decreased sales volumes to existing customers.
The total natural gas liquid gallons sold or processed by our West Coast NGL operations increased 68.8 million gallons, or 36.2%, to 259.1 million gallons in fiscal 2008 from 190.3 million gallons in fiscal 2007. This increase was attributable to the addition of natural gas liquid marketing and processing contracts in fiscal 2008.
Stagecoach had 26.25 bcf of working gas storage capacity during fiscal year 2008. Stagecoach had 13.25 bcf of working gas storage capacity for the first six months in fiscal 2007, 17.45 bcf of working gas storage capacity for the following five months and 26.25 bcf of working gas storage capacity during September 2007. Stagecoach’s storage services were 100% contracted during each of the periods noted above. Steuben, which we acquired a controlling interest in October 2007, had 6.2 bcf of working gas storage capacity and the storage services were 100% contracted during fiscal 2008. The Bath LPG Storage Facility had a storage capacity of 1.7 million barrels and storage services were 100% contracted during fiscal 2008 and fiscal 2007.
Revenues. Revenues in fiscal 2008 were $1,878.9 million, an increase of $395.8 million, or 26.7% from $1,483.1 million in fiscal 2007.
Revenues from retail propane sales were $840.7 million for the year ended September 30, 2008, an increase of $107.5 million, or 14.7%, compared to $733.2 million for the year ended September 30, 2007. These higher retail propane revenues were primarily the result of the higher average selling price of propane and acquisition-related sales, which contributed $162.8 million and $30.8 million, respectively, to the year over year increase. These factors were partially offset by an $86.1 million reduction in retail propane revenues arising from lower retail volume sales at our existing locations as discussed above.
Revenues from wholesale propane sales were $546.1 million in fiscal 2008, an increase of $128.9 million or 30.9%, from $417.2 million in fiscal 2007. Approximately $156.4 million of this increase was attributable to the higher sales price of propane partially offset by lower sales volumes to existing customers. The higher selling price in our wholesale division in 2008 compared to 2007 is the result of the increased cost of propane.
Revenues from other retail sales, which primarily include distillates, service, rental, appliance sales and transportation services, were $223.0 million in fiscal 2008, an increase of $54.2 million, or 32.1% from $168.8 million in fiscal 2007. This increase was primarily related to $39.3 million of acquisition-related sales, a $13.3 million increase in distillate revenues from existing locations and a $4.1 million increase in transportation revenues. Distillate revenues increased during fiscal 2008 due primarily to a 35% increase in the average selling price. These increases were partially offset by a $2.5 million decline related to other products and services, primarily appliances and retail services.
Revenues from storage, fractionation and other midstream activities were $269.1 million in fiscal 2008, an increase of $105.2 million or 64.2% from $163.9 million in fiscal 2007. Revenues from our West Coast NGL
operations were $67.1 million higher as a result of increases in commodity cost and expected changes in the variety of natural gas liquid products sold due to additional contracts and $7.8 million was due to increased transportation and processing activities. Additionally, $30.3 million of this increase was due to the acquisitions of US Salt and ASC, the Stagecoach Phase II expansion being placed into partial service in April 2007 and full service in September 2007, and increased contractual rates on the Stagecoach Storage Facility and Bath LPG Storage Facility.
Cost of Product Sold. Cost of product sold for fiscal 2008 was $1,376.7 million, an increase of $350.6 million, or 34.2%, from $1,026.1 million in fiscal 2007.
Retail propane cost of product sold was $527.9 million for the year ended September 30, 2008 compared to $419.3 million for the year ended September 30, 2007. This $108.6 million, or 25.9%, increase in retail propane cost of product sold was driven by a 37% higher average per gallon cost of propane, which resulted in a $137.1 million increase in cost. Also contributing to the higher cost of product sold during fiscal 2008 was an increase of $20.1 million associated with acquisition-related volume and a $0.7 million increase due to changes in non-cash charges related to derivative contracts associated with retail propane fixed price sales contracts. These factors, which increased retail propane cost of product sold, were partially offset by lower volume sales at our existing locations as discussed above, which reduced costs by $49.3 million.
Wholesale propane cost of product sold in fiscal 2008 was $525.1 million, an increase of $124.4 million or 31.0%, from wholesale cost of product sold of $400.7 million in fiscal 2007. Contributing to these higher costs was a $150.9 million increase due to the higher average cost of propane partially offset by lower volumes sold to existing customers.
Other retail cost of product sold was $146.6 million for the year ended September 30, 2008 compared to $100.0 million for the year ended September 30, 2007. This $46.6 million, or 46.6% increase was primarily due to higher costs of $31.9 million related to acquisitions, an increase of $13.4 million associated with distillate sales from existing locations and a $3.0 million increase in transportation costs. These increases to cost of product sold were partially offset by a $1.7 million decline in costs for other products and services, primarily appliances sales.
Storage, fractionation and other midstream cost of product sold was $177.1 million, an increase of $71.0 million, or 66.9%, from $106.1 million in fiscal 2007. Costs from our West Coast NGL operations were $64.4 million higher as a result of increases in commodity cost and expected changes in the variety of natural gas liquid products sold due to additional contracts and $5.6 million was due to increased transportation and processing activities. The remaining increase resulted from the acquisitions of ASC and US Salt, partially offset by lower power and transportation costs at our Stagecoach facility.
Our retail cost of product sold consists primarily of tangible products sold including all propane, distillates and other natural gas liquids sold and all propane-related appliances sold. Other costs incurred in conjunction with the distribution of these products are included in operating and administrative expense and consist primarily of wages to delivery personnel, delivery vehicle costs consisting of fuel costs, repair and maintenance and lease expense. Costs associated with delivery vehicles amounted to $67.0 million and $63.1 million in 2008 and 2007, respectively. In addition, the depreciation expense associated with the delivery vehicles and customer tanks is reported within depreciation and amortization expense and amounted to $33.0 million and $32.3 million in 2008 and 2007, respectively. Since we include these costs in our operating and administrative expenses and depreciation and amortization expenses rather than in cost of product sold, our results may not be comparable to other entities in our lines of business if they include these costs in cost of product sold.
Our storage, fractionation and other midstream cost of product sold consists primarily of commodity and transportation costs. Other costs incurred in conjunction with these services consist primarily of depreciation, vehicle costs consisting of fuel costs and repair and maintenance and wages are included in operating and administrative expense and depreciation and amortization expense. Depreciation expense for storage,
fractionation and other midstream amounted to $27.7 million and $17.4 million in 2008 and 2007, respectively. Vehicle costs combined with wages for personnel directly involved in providing midstream services amounted to $3.3 million and $1.9 million in 2008 and 2007, respectively. Since we include these costs in our operating and administrative expenses and depreciation and amortization expenses rather than in cost of product sold, our results may not be comparable to other entities in our lines of business if they include these costs in cost of product sold.
Gross Profit. Gross profit for fiscal 2008 was $502.2 million, an increase of $45.2 million, or 9.9%, from $457.0 million during fiscal 2007.
Retail propane gross profit was $312.8 million in fiscal 2008, a decline of $1.1 million, or 0.4%, compared to $313.9 million in fiscal 2007. During fiscal 2008, gross profit declined by $36.8 million primarily as a result of lower retail gallon sales at existing locations as discussed above. This decline in gross profit was partially offset by an increase in gross profit of $25.7 million relating to a higher cash margin per gallon and an increase of $10.7 million due to acquisitions. The increase in cash margin per gallon was primarily the result of our ability to raise selling prices in certain markets in excess of the increased cost of propane.
Wholesale propane gross profit was $21.0 million in fiscal 2008 compared to $16.5 million in fiscal 2007, an increase of $4.5 million or 27.3%. Approximately $5.5 million of this increase was the result of a higher margin per gallon from our existing business partially offset by decreased wholesale volumes from our existing business. The improved margin per gallon is primarily the result of a higher average selling price in excess of our increased cost of propane.
Other retail gross profit was $76.4 million for the year ended September 30, 2008 compared to $68.8 million for the year ended September 30, 2007. This $7.6 million, or 11.0%, increase was due primarily to acquisitions and higher transportation sales, which together resulted in an increase to other retail gross profit of $8.5 million. These increases were partially offset by a combined decrease in gross profit for distillate sales, appliance sales and other retail services of $0.9 million.
Storage, fractionation and other midstream gross profit was $92.0 million in fiscal 2008 compared to $57.8 million in fiscal 2007, an increase of $34.2 million, or 59.2%. Approximately $29.3 million of this increase was due to the acquisitions of US Salt and ASC, the Stagecoach Phase II expansion being placed into partial service in April 2007 and full service in September 2007, and increased contractual rates on the Stagecoach Storage Facility and Bath LPG Storage Facility. The remaining $4.9 million increase relates to increases in transportation, processing activities and natural gas liquids gross profit at our West Coast NGL operations.
Operating and Administrative Expenses. Operating and administrative expenses were $265.6 million in fiscal 2008 compared to $247.8 million in fiscal 2007. This $17.8 million, or 7.2%, increase in operating expenses was primarily the result of higher expenses of $15.7 million arising from acquisitions. The remaining increase resulted from higher vehicle, insurance and other operating expenses, partially offset by lower wages and other personnel expenses due to integration efficiencies and lower expenses as a result of lesser volumes sold at existing locations.
Depreciation and Amortization. Depreciation and amortization increased to $98.0 million in fiscal 2008 from $83.4 million in fiscal 2007. This $14.6 million, or 17.5%, increase was primarily the result of acquisitions and the completion of the Stagecoach Phase II expansion project in our midstream segment.
Loss on Disposal of Assets. Loss on disposal of assets increased $3.5 million, or 43.8%, to $11.5 million in fiscal 2008 compared to $8.0 million in fiscal 2007. The losses recognized in fiscal 2008 and 2007 include losses of $11.5 million and $6.2 million, respectively, related to assets held for sale, which have been written down to their estimated selling price. In addition, we had other losses in fiscal 2007 of $1.8 million. These assets, both those sold and those held for sale, consist primarily of vehicles, tanks and real estate deemed to be excess, redundant or
underperforming assets. In fiscal 2008, these assets were identified primarily as a result of losses due to disconnecting customer installations of unprofitable accounts due to low margins, poor payment history or low volume usage. In fiscal 2007, these assets were identified primarily as the result of the integration of the larger retail propane acquisitions closed since November 2004 as we focused on eliminating duplicity in vehicles, operations, tanks and real estate.
Interest Expense. Interest expense increased to $60.9 million in fiscal 2008 compared to $52.0 million in fiscal 2007. This $8.9 million, or 17.1%, increase was due to a $211.7 million increase in average debt outstanding associated with acquisitions and capital improvement projects, partially offset by a lower average interest rate in 2008 (7.03%) compared to 2007 (7.73%). Additionally, during fiscal 2008 and 2007, we capitalized $5.5 million and $3.1 million, respectively, of interest related to certain capital improvement projects in our midstream segment as further described below in the “Liquidity and Sources of Capital-Capital Resource Activities” section.
Interest of non-controlling partners in ASC’s consolidated net income. We acquired a majority interest in the operations of Steuben when we acquired 100% of the membership interest in ASC in October 2007. ASC holds a majority interest in the operations of Steuben.
Net Income. Net income for fiscal 2008 was $65.1 million compared to net income for fiscal 2007 of $67.0 million. The $1.9 million, or 2.8%, decrease in net income is primarily attributable to higher gross profit, offset by increased operating and administrative expenses, increased depreciation and amortization expenses and certain non-cash expenses.
EBITDA and Adjusted EBITDA. The following tables summarize EBITDA and Adjusted EBITDA for the fiscal years ended September 30, 2008 and 2007, respectively (in millions):
(a) ITDA-Interest, taxes, depreciation and amortization.
EBITDA is defined as income before taxes, plus net interest expense and depreciation and amortization expense. For the years ended September 30, 2008 and 2007, EBITDA was $223.9 million and $203.1 million, respectively. This $20.8 million improvement in EBITDA was primarily attributable to net higher gross profit, which more than offset the increase in cash operating expenses in 2008. As indicated in the table, Adjusted EBITDA represents EBITDA excluding the gain or loss on derivative contracts associated with retail propane fixed price sales contracts, the gain or loss on the disposal of assets and non-cash compensation expenses. Adjusted EBITDA was $239.0 million for fiscal 2008 compared to $211.2 million in fiscal 2007. EBITDA and Adjusted EBITDA should not be considered an alternative to net income, income before income taxes, cash flows from operating activities, or any other measure of financial performance calculated in accordance with generally accepted accounting principles as those items are used to measure operating performance, liquidity or the ability to service debt obligations. We believe that EBITDA and Adjusted EBITDA provide additional information for evaluating our financial performance without regard to our financing methods, capital structure and historical cost basis. Further, we believe that EBITDA and Adjusted EBITDA provide additional information for evaluating our ability to make the minimum quarterly distribution and are presented solely as supplemental measures. EBITDA and Adjusted EBITDA, as we define them, may not be comparable to EBITDA and Adjusted EBITDA or similarly titled measures used by other corporations or partnerships.
Liquidity and Sources of Capital
Capital Resource Activities
On March 23, 2006, our shelf registration statement (File No. 333-132287) was declared effective by the Securities and Exchange Commission for the periodic sale of up to $1.0 billion of common units, partnership securities and debt securities, or any combination thereof. Pursuant to the shelf registration statement, we are permitted to issue these securities from time to time for general business purposes, including debt repayment, future acquisitions, capital expenditures and working capital, or for other potential uses identified in a prospectus supplement. In June 2006 and February 2007, we issued 4,312,500 common units (which included 562,500 common units issued as a result of the underwriters exercising their over-allotment provision) and 3,450,000 common units (which included 450,000 common units issued as result of the underwriters exercising their over-allotment provision), respectively. In March 2009 we issued 4,000,000 common units and in April 2009 we issued an additional 418,000 common units as a result of the underwriters exercising their over-allotment provision. In August 2009 we issued 3,500,000 common units and in September 2009 we issued an additional 525,000 common units as a result of the underwriters exercising their over-allotment provision. The proceeds from these issuances were primarily utilized to pay down borrowings under our credit facility.
On September 10, 2009, our new shelf registration statement (File No. 333-158066) was declared effective by the Securities and Exchange Commission for the periodic sale of up to $1.0 billion of common units, partnership securities and debt securities, or any combination thereof.
Cash Flows and Contractual Obligations
Net operating cash inflows were $239.4 million and $183.8 million for fiscal years ending September 30, 2009 and 2008, respectively. The $55.6 million increase in operating cash flows was primarily attributable to increases in cash components of net income as well as net changes in working capital balances.
Net investing cash outflows were $230.6 million and $386.7 million for the fiscal years ending September 30, 2009 and 2008, respectively. Net cash outflows were primarily impacted by a $203.0 million decrease in cash outlays related to acquisitions, partially offset by a $22.3 million decrease in proceeds from the sale of assets and a $24.7 million increase in capital expenditures.
Net financing cash inflows (outflows) were $(14.5) million and $212.5 million for the fiscal years ending September 30, 2009 and 2008, respectively. The net change was primarily impacted by a $397.5 million decrease in proceeds related to the issuance of long-term debt, net of payments on long-term debt, and a $28.3 million increase in total distributions paid, partially offset by a $201.2 million increase in proceeds from the issuance of common units.
Net operating cash inflows were $183.8 million and $167.9 million for fiscal years ending September 30, 2008 and 2007, respectively. The $15.9 million increase in operating cash flows was primarily attributable to increases in cash components of net income as well as net changes in working capital balances.
Net investing cash outflows were $386.7 million and $187.8 million for the fiscal years ending September 30, 2008 and 2007, respectively. Net cash outflows were primarily impacted by a $115.5 million increase in cash outlays related to acquisitions and a $99.2 million increase in capital expenditures, partially offset by a $16.2 million increase in proceeds from the sale of assets.
Net financing cash inflows were $212.5 million and $15.6 million for the fiscal years ending September 30, 2008 and 2007, respectively. Net cash inflows were primarily impacted by a $330.4 million increase in proceeds related to the issuance of long-term debt, net of payments on long-term debt, a $104.5 million decrease in the proceeds from issuance of common units, a $3.5 million increase in payments for deferred financing costs, a $2.6 million decrease in proceeds from unit option exercises and a $22.9 million increase in total distributions paid.
At September 30, 2009 and 2008, we had goodwill of $374.3 million and $443.0 million, respectively, representing 18% and 21% of total assets in each year, respectively. This goodwill is attributable to our acquisitions. The net decrease in goodwill is attributable to certain purchase accounting adjustments made during 2009.
At September 30, 2009, we were in compliance with all debt covenants to our credit facilities.
The following table summarizes our contractual obligations as of September 30, 2009 (in millions):
(a) $181.4 million of our long-term debt, including interest rate swaps, is variable interest rate debt at prime rate or LIBOR plus an applicable spread. These rates plus their applicable spreads were between 2.0% and 3.5% at September 30, 2009. These rates have been applied for each period presented in the table.
(b) Identified growth projects related to the Thomas Corners and Finger Lakes midstream assets.
(c) Fixed price purchase commitments are offset by sales contracts that are included in our cash flow hedging program as discussed in Note 2, and the remainder are offset volumetrically with fixed price sale contracts.
We believe that anticipated cash from operations and borrowing capacity under our Credit Agreement described below will be sufficient to meet our liquidity needs for the foreseeable future. If our plans or assumptions change or are inaccurate, or we make acquisitions, we may need to raise additional capital. We give no assurance that we can raise additional capital to meet these needs. Global financial markets and economic conditions have been, and continue to be, disrupted and volatile. The debt and equity capital markets have been distressed, but we have successfully raised over $200 million in long-term unsecured debt and over $200 million in two separate equity transactions during 2009. We have identified capital expansion project opportunities in our midstream operations. Additional commitments or expenditures, if any, we may make toward any one or more of these projects is at the discretion of the Partnership. Any discontinuation of the construction of these projects will likely result in less future cash flow and earnings than we have previously indicated.
Description of Credit Facility
On December 17, 2004, we entered into a 5-Year Credit Agreement (the “Credit Agreement”) with our existing lenders in addition to others. The Credit Agreement consists of a $75 million revolving working capital facility (“Working Capital Facility”) and a $350 million revolving acquisition facility (“Acquisition Facility”). The effective amount of working capital borrowing capacity available to us under the two facilities is $200 million utilizing capacity under the acquisition credit facility for working capital needed during the winter heating season. Lehman Commercial Paper, Inc. (“Lehman CP”), a subsidiary of Lehman Brothers Holdings, Inc., holds a $25 million lender commitment within our Credit Agreement and filed for Chapter 11 Bankruptcy on October 5, 2008. We do not plan for the Lehman lender commitment to be available for the remainder of the term of the Credit Agreement. The Credit Agreement accrues interest at either prime rate or LIBOR plus applicable spreads, resulting in interest rates between 2.0% and 3.5% at September 30, 2009. At September 30, 2009, borrowings outstanding under the Credit Agreement were $27.2 million, with the entire balance borrowed for working capital purposes. The Credit Agreement is guaranteed by each of our wholly-owned domestic subsidiaries.
During each fiscal year beginning October 1, the outstanding balance of the Working Capital Facility must be reduced to $10.0 million or less for a minimum of 30 consecutive days during the period commencing March 1 and ending September 30 of each calendar year. We met this provision of our Credit Agreement in May 2009.
At our option, loans under the Credit Agreement bear interest at either the prime rate or LIBOR (preadjusted for reserves), plus, in each case, an applicable margin. The applicable margin varies quarterly based on its leverage ratio. We also pay a fee based on the average daily unused commitments under the Credit Agreement.
We are required to use 50% of the net cash proceeds (that are not applied to purchase replacement assets) from asset dispositions (other than the sale of inventory and motor vehicles in the ordinary course of business, sales of assets among us and our domestic subsidiaries and the sale or disposition of obsolete or worn-out equipment) to reduce borrowings under the Credit Agreement during any fiscal year in which unapplied net cash proceeds are in excess of $50 million. Any such mandatory prepayments are first applied to reduce borrowings under the Acquisition Facility and then under the Working Capital Facility.
In addition, the Credit Agreement contains various covenants limiting our ability to (subject to various exceptions), among other things:
•
grant or incur liens;
•
incur other indebtedness (other than permitted debt as defined in the Credit Agreement);
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make investments, loans and acquisitions;
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enter into a merger, consolidation or sale of assets;
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enter into any sale-leaseback transaction or enter into any new business;
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enter into any agreement that conflicts with the credit facility or ancillary agreements;
•
make any change in its principles and methods of accounting as currently in effect, except as such changes are permitted by GAAP;
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enter into certain affiliate transactions;
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pay dividends or make distributions if we are in default under the Credit Agreement or in excess of available cash;
•
permit operating lease obligations to exceed $20 million in any fiscal year ($40 million under the new facility discussed in Item 1);
•
enter into any debt (other than permitted junior debt) that contains covenants more restrictive than those of the Credit Agreement or enter into any permitted junior debt that contains negative covenants more restrictive than those of the Credit Agreement;
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enter into hedge agreements that do not hedge or mitigate risks to which we have actual exposure;
•
enter into put agreements granting put rights with respect to equity interests of us or our subsidiaries;
•
prepay, redeem, defease or otherwise acquire any permitted junior debt or make certain amendments to permitted junior debt; and
•
modify organizational documents.
“Permitted junior debt” consists of:
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our $425 million 6.875% senior notes due December 15, 2014 that were issued on December 22, 2004;
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our $200 million 8.25% senior notes due March 1, 2016 that were issued on January 11, 2006;
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our $200 million 8.25% senior notes due March 1, 2016 that were issued on April 29, 2008;
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our $225 million 8.75% senior notes due March 1, 2015 that were issued on February 2, 2009;
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other debt that is substantially similar to the 6.875% senior notes; and
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other debt of ours and our subsidiaries that is either unsecured debt, or second lien debt that is subordinated to the obligations under the Credit Agreement.
Permitted junior debt may be incurred under the Credit Agreement so long as:
•
there is no default under the Credit Agreement;
•
the ratio of our total funded debt to consolidated EBITDA is less than 5.0 to 1.0 on a pro forma basis;
•
the debt does not mature, and no installments of principal are due and payable on the debt, prior to the maturity date of the Credit Agreement; and
•
other than in connection with the 6.875%, 8.25% and 8.75% senior notes and other substantially similar debt, the debt does not contain covenants more restrictive than those in the Credit Agreement.
The Credit Agreement contains the following financial covenants:
•
the ratio of our total funded debt (as defined in the Credit Agreement) to consolidated EBITDA (as defined in the Credit Agreement) for the four fiscal quarters most recently ended must be no greater than 5.25 to 1.0 for any period of two consecutive fiscal quarters immediately following an acquisition with a purchase price in excess of $100 million and 4.75 to 1.0 at all other times; and
•
the ratio of our consolidated EBITDA to consolidated interest expense (as defined in the Credit Agreement), for the four fiscal quarters then most recently ended, must not be less than 2.5 to 1.0.
At September 30, 2009, our ratio of total funded debt to consolidated EBITDA was 3.60 to 1.0, and our ratio of consolidated EBITDA to consolidated interest expense was 4.59 to 1.0.
Each of the following is an event of default under the Credit Agreement:
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default in payment of principal when due;
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default in payment of interest, fees or other amounts within three days of their due date;
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violation of specified affirmative and negative covenants;
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default in performance or observance of any term, covenant, condition or agreement contained in the Credit Agreement or any ancillary document related to the credit facility for 30 days;
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specified cross-defaults;
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bankruptcy and other insolvency events of us or our material subsidiaries;
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impairment of the enforceability or the validity of agreements relating to the Credit Agreement;
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judgments exceeding $2.5 million (to the extent not covered by insurance) against us or any of our subsidiaries are undischarged or unstayed for 30 consecutive days;
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certain defaults under ERISA that could reasonably be expected to result in a material adverse effect on us; or
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the occurrence of certain change of control events with respect to us.
As discussed in Item 1, we now have a $450 million general partnership revolving credit facility for acquisitions, capital expenditures and general partnership purposes and a $75 million revolving working capital facility.
Senior Unsecured Notes
2014 Senior Notes
On December 22, 2004, we and our wholly-owned subsidiary, Inergy Finance Corp (“Finance Corp.” and together with us, the “Issuers”) completed a private placement of $425 million in aggregate principal amount of our 6.875% senior unsecured notes due 2014 (the “2014 Senior Notes”). We used the net proceeds from the 2014 Senior Notes to repay all amounts drawn under a 364-day credit facility which was entered into in order to fund the acquisition of Star Gas and is no longer available to us, with the $39.9 million remaining balance of the net proceeds applied to the Acquisition Facility.
The 2014 Senior Notes represent senior unsecured obligations of ours and rank pari passu in right of payment with all other present and future senior indebtedness of ours. The 2014 Senior Notes are effectively subordinated to all of our secured indebtedness to the extent of the value of the assets securing the indebtedness and to all existing and future indebtedness and liabilities, including trade payables, of our non-guarantor subsidiaries. The 2014 Senior Notes rank senior in right of payment to all of our future subordinated indebtedness.
The 2014 Senior Notes are fully, unconditionally, jointly and severally guaranteed by all of our wholly-owned domestic subsidiaries. The subsidiaries guarantees rank equally in right of payment with all of the existing and future senior indebtedness of our guarantor subsidiaries. The subsidiaries guarantees are effectively subordinated to all existing and future secured indebtedness of our guarantor subsidiaries to the extent of the value of the
assets securing that indebtedness and to all existing and future indebtedness and other liabilities, including trade payables, of our non-guarantor subsidiaries (other than indebtedness and other liabilities owed to us). The subsidiaries guarantees rank senior in right of payment to all of our future subordinated indebtedness.
In October 2005, we completed an offer to exchange our existing 2014 Senior Notes for $425 million of 6.875% senior notes due 2014 (the “2014 Exchange Notes”) that are registered and do not carry transfer restrictions, registration rights and provisions for additional interest. The 2014 Exchange Notes did not provide us with any additional proceeds and satisfied our obligations under the registration rights agreement.
The 2014 Senior Notes are redeemable, at our option, in whole or in part, at any time on or after December 15, 2009, 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.
2016 Senior Notes
On January 11, 2006, we and our wholly-owned subsidiary, Inergy Finance Corp, issued $200 million aggregate principal amount of 8.25% senior unsecured notes due 2016 (the “2016 Senior Notes”) in a private placement to eligible purchasers.
The 2016 Senior Notes contain covenants similar to our existing senior unsecured notes due 2014. We used the net proceeds of the offering to repay outstanding indebtedness under our revolving acquisition credit facility. The 2016 Senior Notes represent senior unsecured obligations of ours and rank pari passu in right of payment with all other present and future senior indebtedness of ours. The 2016 Senior Notes are fully, unconditionally, jointly and severally guaranteed by all of our wholly-owned domestic subsidiaries.
On May 18, 2006, we completed an offer to exchange our existing 8.25% 2016 Senior Notes for $200 million of 8.25% senior notes due 2016 (the “2016 Exchange Notes”) that are registered and do not carry transfer restrictions, registration rights and provisions for additional interest. The 2016 Exchange Notes did not provide us with any additional proceeds and satisfied our obligations under the registration rights agreement.
The 2016 Senior Notes are redeemable, at our option, in whole or in part, at any time on or after March 1, 2011, 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.
In April 2008, we issued an additional $200 million of senior unsecured notes as an add-on to our existing 8.25% Senior Unsecured Notes due 2016 under Rule 144A to eligible purchasers. The notes mature on March 1, 2016. The proceeds from the bond issuance were $204 million, representing a 2% premium to par value. On September 16, 2008, we completed an offer to exchange the additional $200 million of 8.25% senior notes due 2016 for $200 million of 8.25% senior notes due 2016 (the “Additional 2016 Exchange Notes”) that are registered and do not carry transfer restrictions, registration rights and provisions for additional interest. The Additional 2016 Exchange Notes did not provide us with any additional proceeds and satisfied our obligations under the registration rights agreement.
2015 Senior Notes
On February 2, 2009, we and our wholly-owned subsidiary, Inergy Finance Corp, issued $225 million aggregate principal amount of 8.75% senior unsecured notes due 2015 (the “2015 Senior Notes”) under Rule 144A to eligible purchasers. The 8.75% notes mature on March 1, 2015, and were issued at 90.191% of the principle amount to yield 11%.
The 2015 Senior Notes contain covenants similar to our existing senior unsecured notes due 2014 and 2016. We used the net proceeds of the offering to repay outstanding indebtedness under our revolving acquisition credit facility. The 2015 Senior Notes represent senior unsecured obligations of ours and rank pari passu in right of payment with all other present and future senior indebtedness of ours. The 2015 Senior Notes are fully, unconditionally, jointly and severally guaranteed by all of our wholly-owned domestic subsidiaries.
On October 7, 2009, we completed an offer to exchange our existing 8.75% 2015 Senior Notes for $225 million of 8.75% senior notes due 2015 (the “2015 Exchange Notes”) that are registered and do not carry transfer restrictions, registration rights and provisions for additional interest. The 2015 Exchange Notes did not provide us with any additional proceeds and satisfied our obligations under the registration rights agreement.
The 2015 Senior Notes are redeemable, at our option, in whole or in part, at any time on or after March 1, 2013, 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.
The indentures governing our senior unsecured notes discussed above are substantially similar and contain covenants that, among other things, will limit our ability and the ability of our restricted subsidiaries to:
•
sell assets;
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pay distributions on, redeem or repurchase our units or redeem or repurchase our subordinated debt;
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make investments;
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incur or guarantee additional indebtedness or issue preferred units;
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create or incur certain liens;
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enter into agreements that restrict distributions or other payments from our restricted subsidiaries to us;
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consolidate, merge or transfer all or substantially all of our assets;
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engage in transactions with affiliates; and
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create unrestricted subsidiaries.
These covenants are subject to important exceptions and qualifications, and if the notes achieve an investment grade rating from either Moody’s or Standard & Poor’s, many of these covenants will terminate.
In addition, the indentures governing our senior notes restrict our ability to pay cash distributions. Before we can pay a distribution to our unitholders, we must demonstrate that the fixed charge coverage ratio (as defined in the senior notes indentures) is at least 1.75 to 1.0.
Recent Accounting Pronouncements
FASB Accounting Standards Codification Subtopic 825-10 (“825-10”), originally issued as SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities”, was issued in February 2007 to permit entities
to choose to measure many financial instruments and certain other items at fair value at specified election dates. A business entity is required to report unrealized gains and losses on items for which the fair value option has been elected in earnings at each subsequent reporting date. We adopted 825-10 on October 1, 2008. The adoption of 825-10 did not have an impact on our financial statements.
FASB Accounting Standards Codification Subtopic 820-10 (“820-10”), originally issued as SFAS No. 157, “Fair Value Measurements”, was issued in September 2006 to define fair value, establish a framework for measuring fair value according to generally accepted accounting principles and expand disclosures about fair value measurements. We adopted 820-10 on October 1, 2008. The adoption of 820-10 required certain additional footnote disclosures, however, it did not have a significant impact on any amounts comprising the consolidated balance sheets, consolidated statements of operations, consolidated statements of partners’ capital or the consolidated statements of cash flows.
FASB Accounting Standards Codification Subtopic 210-20 (“210-20”), originally issued as FASB Staff Position No. FIN 39-1, “Amendment of FASB Interpretation No. 39”, was issued in April 2007 to permit companies to offset fair value amounts recognized for the right to reclaim cash collateral (a receivable), or the obligation to return cash collateral (a payable), against fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting agreement. In addition, upon the adoption, companies are permitted to change their accounting policy to offset or not offset fair value amounts recognized for derivative instruments under master netting arrangements. We adopted 210-20 on October 1, 2008 and elected to change our accounting policy for derivative instruments executed with the same counterparty under a master netting agreement. Our policy is to offset fair value amounts of derivative instruments and cash collateral paid or received with the same counterparty under a master netting arrangement. This change in accounting policy has been presented retroactively. The adoption of 210-20 had the following impact on the September 30, 2008 consolidated balance sheet (in millions):
FASB Accounting Standards Codification Subtopic 815-10 (“815-10”), originally issued as SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities-an amendment of FASB Statement No. 133” was issued in March 2008 and applies to all derivative instruments and related hedged items. 815-10 requires entities to provide greater transparency about (a) how and why an entity uses derivative instruments, (b) how derivative instruments and related hedged items are accounted for, and (c) how derivative instruments and related hedged items affect an entity’s financial position, results of operations and cash flows. We adopted 815-10 on March 31, 2009. The adoption of 815-10 required certain additional disclosures, however, it did not impact any amounts comprising the consolidated balance sheets, consolidated statements of operations, consolidated statements of partners’ capital or the consolidated statements of cash flows.
FASB Accounting Standards Codification Subtopic 805-10 (“805-10”), originally issued as SFAS No. 141 (revised 2007), “Business Combinations”, was issued in December 2007 and establishes principles and requirements for how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, any non- controlling interest in the acquiree and the goodwill acquired. 805-10 also establishes disclosure requirements designed to enable users to evaluate the nature and financial effects of the business combination. 805-10 is required to be adopted by us for business combinations for which the acquisition date is on or after October 1, 2009.
FASB Accounting Standards Codification Subtopic 810-10 (“810-10”), originally issued as SFAS No. 160, “Non-controlling Interests in Consolidated Financial Statements-an amendment of ARB No. 51”, was issued in December 2007 and requires that accounting and reporting for minority interests will be recharacterized as non-controlling interests and classified as a component of equity. 810-10 also establishes reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the non-controlling owners. 810-10 applies to all entities that prepare consolidated financial statements, except not-for-profit organizations, but will affect only those entities that have an outstanding non-controlling interest in one or more subsidiaries or that deconsolidate a subsidiary. 810-10 is required to be adopted by us for the fiscal quarter ended December 31, 2009. We are evaluating the potential financial statement impact of 810-10 to our consolidated financial statements.
FASB Accounting Standards Codification Subtopic 260-10 (“260-10”), originally issued as EITF Issue No. 07-4, “Application of the Two-Class Method under FASB Statement No. 128 to Master Limited Partnerships”, was ratified in March 2008 and applies to Master Limited Partnerships (“MLP”) that are required to make incentive distributions when certain thresholds have been met regardless of whether the IDR is a separate limited partner (“LP”) interest or embedded in the general partner interest. 260-10 addresses how the current period earnings of an MLP should be allocated to the general partner, LP’s and, when applicable, IDR’s. 260-10 is required to be adopted by us for the fiscal quarter ended December 31, 2009. We are evaluating the potential financial statement impact of 260-10 to our consolidated financial statements.
FASB Accounting Standards Codification Subtopic 260-10 (“260-10”), originally issued as FSP EITF Issue No. 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions are Participating Securities”, was ratified in June 2008 and applies to the calculation of earnings per share (“EPS”) under FASB Accounting Standards Codification Subtopic 260-10 (“260-10”), originally issued as SFAS 128, “Earnings Per Share”, for share-based payment awards with rights to dividends or dividend equivalents. 260-10 states that unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents are participating securities and shall be included in the computation of EPS pursuant to the two-class method. 260-10 is required to be adopted by us for the fiscal quarter ended December 31, 2009. We are evaluating the potential financial statement impact of 260-10 to our consolidated financial statements.
In May 2009, the FASB issued FASB Accounting Standards Codification Subtopic 855-10 (“855-10”), originally issued as SFAS No. 165, “Subsequent Events”. 855-10 establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. We adopted 855-10 on June 30, 2009. The adoption of 855-10 required us to disclose the date through which subsequent events have been evaluated and the basis for that date. The adoption of 855-10 did not impact any amounts comprising the consolidated balance sheets, consolidated statements of operations, consolidated statements of partners’ capital or the consolidated statements of cash flows.
In June 2009, the FASB issued FASB Accounting Standards Codification Subtopic 105-10 (“105-10”), originally issued as SFAS 168, “The FASB Accounting Standards Codification and Hierarchy of Generally Accepted Accounting Principles”, to supersede FASB Statement No. 162, “The Hierarchy of Generally Accepted Accounting Principles”, and reorganize the standards applicable to financial statements of nongovernmental entities that are presented in conformity with GAAP. The purpose of the codification was to provide a single source of authoritative nongovernmental GAAP literature. The codification was not intended to create new accounting standards or guidance. While the codification includes portions of SEC content related to matters within the basic financial statements for user convenience, it does not contain all SEC guidance on accounting topics, and does not replace any SEC rules or regulations. We adopted 105-10 on September 30, 2009. The adoption of 105-10 did not impact any amounts comprising the consolidated balance sheets, consolidated statements of operations, consolidated statements of partners’ capital or the consolidated statements of cash flows.
Critical Accounting Policies
Accounting for Price Risk Management. We utilize certain derivative financial instruments to (i) manage our exposure to commodity price risk, specifically, the related change in the fair value of inventories, as well as the variability of cash flows related to forecasted transactions; (ii) ensure adequate physical supply of propane and heating oil will be available; and (iii) manage our exposure to interest rate risk. We record all derivative instruments on the balance sheet as either assets or liabilities measured at estimated fair value.
We determine fair value of our derivative financial instruments according to the following hierarchy: (1) comparable market prices to the extent available; (2) internal valuation models that utilize market data (observable inputs) as input variables; and lastly, (3) internal valuation models that use management’s assumptions about the assumptions that market participants would use in pricing the instruments (unobservable inputs) to the extent (1) and (2) are unavailable. Because the majority of the instruments we enter into are traded in liquid markets, we value these instruments based on prices indicative of exiting the position. As a consequence, the majority of the values of our derivative financial instruments are based upon actual prices of like kind trades that are obtained from on-line trading systems and verified with broker quotes. Changes in the fair value of these derivative financial instruments, primarily resulting from variability in supply and demand, are recorded either through current earnings or as other comprehensive income, depending on the type of transaction.
On the date the derivative contract is entered into, we generally designate specific derivatives as either a hedge of the fair value of a recognized asset or liability (fair value hedge), or a hedge of a forecasted transaction (cash flow hedge). We document all relationships between hedging instruments and hedged items, as well as our risk-management objective and strategy for undertaking various hedge transactions. We use regression analysis or the dollar offset method to assess, both at the hedge’s inception and on an ongoing basis, whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in fair value or cash flows of hedged items. When it is determined that a derivative is not highly effective as a hedge or that is has ceased to be a highly effective hedge, we discontinue hedge accounting prospectively. When hedge accounting is discontinued because it is determined that the derivative no longer qualifies as an effective hedge, we continue to carry the derivative on the balance sheet at fair value, and recognize changes in the fair value of the derivative through current-period earnings.
We are party to certain commodity derivative financial instruments that are designated as hedges of selected inventory positions, and qualify as fair value hedges. We are also party to certain interest rate swap agreements designed to manage interest rate risk exposure. Our overall objective for entering into fair value hedges is to manage our exposure to fluctuations in commodity prices and changes in the fair market value of our inventories. These derivatives are recorded at fair value on the balance sheet as price risk management assets or liabilities and the related change in fair value is recorded to earnings in the current period as cost of product sold. Any ineffective portion of the fair value hedges is recognized as cost of product sold in the current period. We recognized a $0.2 million net gain in the year ended September 30, 2009, related to the ineffective portion of our fair value hedging instruments. In addition, for the year ended September 30, 2009, we recognized a net loss of $0.1 million related to the portion of fair value hedging instruments that we excluded from our assessment of hedge effectiveness.
We also enter into derivative financial instruments that qualify as cash flow hedges, which hedge the exposure of variability in expected future cash flows predominantly attributable to forecasted purchases to supply fixed price sale contracts. These derivatives are recorded on the balance sheet at fair value as price risk management assets or liabilities. The effective portion of the gain or loss on these cash flow hedges is recorded in other comprehensive income in partner’s capital and reclassified into earnings in the same period in which the hedge transaction affects earnings. Any ineffective portion of the gain or loss is recognized as cost of product sold in the current period. Accumulated other comprehensive income (loss) was $11.0 million and $(25.3) million at September 30, 2009 and 2008, respectively. Approximately $11.7 million is expected to be reclassified to earnings from other comprehensive income over the next twelve months.
Our policy is to offset fair value amounts of derivative instruments and cash collateral paid or received with the same counterparty under a master netting arrangement.
The cash flow impact of derivative financial instruments is reflected as cash flows from operating activities in the consolidated statements of cash flows.
If management’s assumptions related to unobservable inputs used in the pricing models for our financial instruments, which include swaps, forwards, futures and options, are inaccurate or if we had used an alternative valuation methodology, the estimated fair value may have been different, and we may be exposed to unrealized losses or gains. A hypothetical 10% difference in the assumptions made for our unobservable inputs would have impacted our estimated fair value of these derivatives at September 30, 2009, and would have affected net income by an immaterial amount for the year ended September 30, 2009.
Revenue Recognition. Sales of propane, other liquids and salt are recognized at the time product is shipped or delivered to the customer. Gas processing and fractionation fees are recognized upon delivery of the product. Revenue from the sale of propane appliances and equipment is recognized at the later of the time of sale or installation. Revenue from repairs and maintenance is recognized upon completion of the service. Revenue from storage contracts is recognized during the period in which storage services are provided.
Impairment of Long-Lived Assets. Goodwill is subject to at least an annual assessment for impairment by applying a fair-value-based test. Additionally, an acquired intangible asset should be separately recognized if the benefit of the intangible asset is obtained through contractual or other legal rights, or if the intangible asset can be sold, transferred, licensed, rented or exchanged, regardless of the acquirer’s intent to do so.
We completed the valuation of each of our reporting units and determined no impairment existed as of September 30, 2009. The valuation of our reporting units requires us to make certain assumptions as it relates to future operating performance. When considering operating performance, various factors are considered such as current and changing economic conditions and the commodity price environment, among others. Due to the economic uncertainty, we adjusted our assumptions underlying our discounted cash flow approach to valuing enterprise value. Projected cash flows for 2010 reflect the deteriorating economic conditions that began in the latter half of 2008. The discount rate used in the current year reflects an increase in our cost of capital due to the dislocation of worldwide credit markets. If the growth assumptions embodied in the current year impairment testing prove inaccurate, we could incur an impairment charge. A 10% decrease in the estimated future cash flows and a 1% increase in the discount rate used in our impairment analysis would not have indicated a potential impairment of any of our intangible assets. To date, we have not recognized any impairment on assets we have acquired.
The value of the assets to be disposed of is estimated at the date a commitment to dispose the asset is made. Our estimate of any loss associated with an asset sale is dependent on certain assumptions we make with respect to the net realizable value of the particular asset. A 10% decrease in the estimated net realizable value would have resulted in an additional loss of $0.2 million at September 30, 2009.
Self-Insurance. We are insured by third parties, subject to varying retention levels of self-insurance, which management considers prudent. Such self-insurance relates to losses and liabilities primarily associated with medical claims, workers’ compensation claims, general, product and vehicle liability, and environmental exposures. Losses are accrued based upon management’s estimates of the aggregate liability for claims incurred using certain assumptions followed in the insurance industry and based on past experience. The primary assumption utilized is actuarially determined loss development factors. The loss development factors are based primarily on historical data. Our self insurance reserves could be affected if future claims development differs from the historical trends. We believe changes in health care costs, trends in health care claims of our employee base, accident frequency and severity and other factors could materially affect the estimate for these liabilities. We continually monitor changes in employee demographics, incident and claim type and evaluate our insurance accruals and adjust our accruals based on our evaluation of these qualitative data points. At September 30, 2009 and 2008, our self-insurance reserves were $19.3 million and $17.4 million, respectively.
Factors That May Affect Future Results of Operations, Financial Condition or Business
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We may not be able to generate sufficient cash from operations to allow us to pay the minimum quarterly distribution.
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Our future acquisitions and completion of our expansion projects will require significant amounts of debt and equity financing which may not be available to us on acceptable terms, or at all.
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Since weather conditions may adversely affect the demand for propane, our financial condition and results of operations are vulnerable to, and will be adversely affected by, warm winters.
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If we do not continue to make acquisitions on economically acceptable terms, our future financial performance will be reliant upon internal growth and efficiencies.
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We cannot assure you that we will be successful in integrating our recent acquisitions.
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Sudden and sharp propane price increases that cannot be passed on to customers may adversely affect our profit margins.
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Our indebtedness may limit our ability to borrow additional funds, make distributions to unitholders or capitalize on acquisition or other business opportunities.
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The highly competitive nature of the retail propane business could cause us to lose customers, thereby reducing our revenues.
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If we are not able to purchase propane from our principal suppliers, our results of operations would be adversely affected.
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Competition from alternative energy sources may cause us to lose customers, thereby reducing our revenues.
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Our business would be adversely affected if service at our principal storage facilities or on the common carrier pipelines we use is interrupted.
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We are subject to operating and litigation risks that could adversely affect our operating results to the extent not covered by insurance.
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Our results of operations and financial condition may be adversely affected by governmental regulation and associated environmental regulatory costs.
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Energy efficiency and new technology may reduce the demand for propane.
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Due to our lack of asset diversification, adverse developments in our propane business would reduce our ability to make distributions to our unitholders.
See “Item 1A - “Risk Factors” for further discussion of factors that could impact our business.
Item 7A.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
Interest Rate Risk
We have long-term debt and a revolving line of credit subject to the risk of loss associated with movements in interest rates. At September 30, 2009, we had floating rate obligations totaling $181.4 million including amounts borrowed under our Credit Agreement, the ASC Credit Agreement and interest rate swaps, which convert a portion of our fixed rate senior unsecured notes due 2014 to floating, with aggregate notional amounts of $150 million. The floating rate obligations expose us to the risk of increased interest expense in the event of increases in short-term interest rates.
If the floating rate were to fluctuate by 100 basis points from September 2009 levels, our combined interest expense would change by a total of approximately $1.8 million per year.
Certain counterparties have elected to call their respective interest rate swap positions. The aggregate notional amount associated with these swaps amounts to $125 million. These swaps will be called in December 2009 and we are currently evaluating our options to manage our interest rate risk.
Commodity Price, Market and Credit Risk
Inherent in our contractual portfolio are certain business risks, including market risk and credit risk. Market risk is the risk that the value of the portfolio will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by suppliers, customers or financial counterparties to a contract. We take an active role in managing and controlling market and credit risk and have established control procedures, which are reviewed on an ongoing basis. We monitor market risk through a variety of techniques, including daily reporting of the portfolio’s position to senior management. We attempt to minimize credit risk exposure through credit policies and periodic monitoring procedures as well as through customer deposits, letters of credit and entering into netting agreements that allow for offsetting counterparty receivable and payable balances for certain financial transactions, as deemed appropriate. The counterparties associated with assets from price risk management activities as of September 30, 2009 and 2008, were propane retailers, resellers, energy marketers and dealers.
The propane industry is a “margin-based” business in which gross profits depend on the excess of sales prices over supply costs. As a result, our profitability will be sensitive to changes in wholesale prices of propane caused by changes in supply or other market conditions. When there are sudden and sharp increases in the wholesale cost of propane, we may not be able to pass on these increases to our customers through retail or wholesale prices. Propane is a commodity and the price we pay for it can fluctuate significantly in response to supply or other market conditions. We have no control over supply or market conditions. In addition, the timing of cost pass-throughs can significantly affect margins. Sudden and extended wholesale price increases could reduce our gross profits and could, if continued over an extended period of time, reduce demand by encouraging our retail customers to conserve or convert to alternative energy sources.
We engage in hedging and risk management transactions, including various types of forward contracts, options, swaps and futures contracts, to reduce the effect of price volatility on our product costs, protect the value of our inventory positions and to help ensure the availability of propane during periods of short supply. We attempt to balance our contractual portfolio by purchasing volumes only when we have a matching purchase commitment from our wholesale customers. However, we may experience net unbalanced positions from time to time which we believe to be immaterial in amount. In addition to our ongoing policy to maintain a balanced position, for accounting purposes we are required, on an ongoing basis, to track and report the market value of our derivative portfolio.
Fair Value
The fair value of the derivatives and inventory exchange contracts related to price risk management activities as of September 30, 2009, and September 30, 2008, was assets of $23.8 million and $33.3 million, respectively and liabilities of $29.3 million and $57.0 million, respectively.
We use observable market values for determining the fair value of our trading instruments. In cases where actively quoted prices are not available, other external sources are used which incorporate information about commodity prices in actively quoted markets, quoted prices in less active markets and other market fundamental analysis. Our risk management department regularly compares valuations to independent sources and models on a quarterly basis.
Sensitivity Analysis
A theoretical change of 10% in the underlying commodity value would result in a negligible change in the market value of the contracts as there were (0.1) million gallons of net unbalanced positions at September 30, 2009.
Item 8.
Item 8. Financial Statements and Supplementary Data.
Reference is made to the financial statements and report of independent registered public accounting firm included later in this report under Item 15.
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
None.
Item 9A.
Item 9A. Controls and Procedures.
We maintain controls and procedures designed to provide a reasonable assurance that information required to be disclosed in our reports that we file or submit under the Securities Exchange Act of 1934 are recorded, processed, summarized and reported within the time periods specified by the rules and forms of the SEC, and that information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. An evaluation was performed under the supervision and with the participation of our management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as such terms are defined in Rule 13a-15(e) and 15d-15(e) of the Exchange Act). Based upon that evaluation, management, including the Chief Executive Officer and the Chief Financial Officer, concluded that our disclosure controls and procedures were effective as of September 30, 2009, at the reasonable assurance level. There have been no changes in our internal control over financial reporting (as defined in Rule 13(a)-15(f) or Rule 15d-15(f) of the Exchange Act) or in other factors during the period ended September 30, 2009, that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.
Management’s Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, pursuant to Exchange Act Rules 13a-15(f). Our internal control system was designed to provide reasonable assurance to management and our board of directors regarding the preparation and fair presentation of published financial statements in accordance with generally accepted accounting principles.
Management recognizes that there are inherent limitations in the effectiveness of any system of internal control, and accordingly, even effective internal control can provide only reasonable assurance with respect to financial statement preparation and fair presentation. Further, because of changes in conditions, the effectiveness of internal control may vary over time.
Management’s assessment of and conclusion on the effectiveness of internal control over financial reporting did not include the operations resulting from the three acquisitions (collectively “the Acquisitions”) which were acquired during fiscal 2009 and are included in the 2009 consolidated financial statements. The financial reporting systems of the Acquisitions were integrated into the company’s financial reporting systems throughout 2009. Therefore, the company did not have the practical ability to perform an assessment of their internal controls in time for this current year-end. The company fully expects to include the Acquisitions in next year’s assessment. The Acquisitions constituted $14.4 million and $10.5 million in total assets and revenues, respectively, in the consolidated financial statements.
Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we assessed the effectiveness of the company’s internal control over financial reporting as of September 30, 2009. In making this assessment, we used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control-Integrated Framework. Based upon our assessment, we conclude that, as of September 30, 2009, our internal control over financial reporting is effective, in all material respects, based upon those criteria.
Our independent registered public accounting firm, Ernst & Young LLP, issued an attestation report dated November 30, 2009 on the effectiveness of our internal control over financial reporting, which is included herein.
Item 9B.
Item 9B. Other Information.
None.
PART III
Item 10.
Item 10. Directors, Executive Officers and Corporate Governance.
Our Managing General Partner Manages Inergy, L.P.
Inergy GP, LLC, our managing general partner, manages our operations and activities. Our managing general partner is not elected by our unitholders and will not be subject to re-election on a regular basis in the future. Our managing general partner may not be removed unless that removal is approved by the vote of the holders of not less than 66 2/3% of the outstanding units, including units held by the general partners and their affiliates, and we receive an opinion of counsel regarding limited liability and tax matters. Any removal of the managing general partner is also subject to the approval of a successor managing general partner by the vote of the holders of a majority of the outstanding common units. Unitholders do not directly or indirectly participate in our management or operation. Our managing general partner owes a fiduciary duty to the unitholders. Our managing general partner is liable, as a general partner, for all of our debts (to the extent not paid from our assets), except for specific nonrecourse indebtedness or other obligations. Whenever possible, our managing general partner intends to incur indebtedness or other obligations that are nonrecourse.
As is commonly the case with publicly-traded limited partnerships, we are managed and operated by the officers of our managing general partner and are subject to the oversight of the directors of our managing general partner. The board of directors of our managing general partner is presently composed of five directors.
Inergy Holdings, L.P. owns our non-managing general partner and our managing general partner. As the sole member of our managing general partner, Inergy Holdings has the power to elect our board of directors.
Directors and Executive Officers
The following table sets forth certain information with respect to the executive officers and members of the board of directors of our managing general partner. Executive officers and directors will serve until their successors are duly appointed or elected.
Executive Officers and Directors
Age
Position with our Managing General Partner
John J. Sherman
President, Chief Executive Officer and Director
Phillip L. Elbert
President and Chief Operating Officer-Propane Operations and Director
R. Brooks Sherman, Jr.
Executive Vice President and Chief Financial Officer
Carl A. Hughes
Senior Vice President-Business Development
Laura L. Ozenberger
Senior Vice President-General Counsel and Secretary
Andrew L. Atterbury
Senior Vice President-Corporate Development
William R. Moler
Senior Vice President-Natural Gas Midstream Operations
Warren H. Gfeller
Director
Arthur B. Krause
Director
Robert D. Taylor
Director
John J. Sherman. Mr. Sherman has served as President, Chief Executive Officer and a director since March 2001, and of our predecessor from 1997 until July 2001. Prior to joining our predecessor, he was a vice president with Dynegy Inc. from 1996 through 1997. He was responsible for all downstream propane marketing operations, which at the time were the country’s largest. From 1991 through 1996, Mr. Sherman was the president of LPG Services Group, Inc., a company he co-founded and grew to become one of the nation’s largest wholesale marketers of propane before Dynegy acquired LPG Services in 1996. From 1984 through 1991, Mr. Sherman was a vice president and member of the management committee of Ferrellgas, which is one of the country’s largest retail propane marketers. He also serves as President, Chief Executive Officer and director of Inergy Holdings GP, LLC and a director of Great Plains Energy Inc.
Phillip L. Elbert. Mr. Elbert has served as President and Chief Operating Officer-Propane Operations since September 2007 and Executive Vice President-Propane Operations and director since March 2001. He joined our predecessor as Executive Vice President-Operations in connection with our acquisition of the Hoosier Propane Group in January 2001. Mr. Elbert joined the Hoosier Propane Group in 1992 and was responsible for overall operations, including Hoosier’s retail, wholesale and transportation divisions. From 1987 through 1992, he was employed by Ferrellgas, serving in a number of management positions relating to retail, transportation and supply. Prior to joining Ferrellgas, he was employed by Buckeye Gas Products, a large propane marketer from 1981 to 1987. He also serves as the President and Chief Operating Officer-Propane Operations of Inergy Holdings GP, LLC.
R. Brooks Sherman, Jr. Mr. Brooks Sherman, Jr. (no relation to Mr. John Sherman) has served as Executive Vice President since September 2007, Senior Vice President since September 2002 and Chief Financial Officer since March 2001. Mr. Sherman previously served as Vice President from March 2001 until September 2002. He joined our predecessor in December 2000 as Vice President and Chief Financial Officer. From 1999 until joining our predecessor, he served as Chief Financial Officer of MCM Capital Group. From 1996 through 1999, Mr. Sherman was employed by National Propane Partners, a publicly traded master limited partnership, first as its controller and chief accounting officer and subsequently as its chief financial officer. From 1995 to 1996, Mr. Sherman served as chief financial officer for Berthel Fisher & Co. Leasing Inc. and prior to 1995, Mr. Sherman was in public accounting with Ernst & Young and KPMG Peat Marwick. He also serves as Executive Vice President and Chief Financial Officer of Inergy Holdings GP, LLC.
Carl A. Hughes. Mr. Hughes has served as Senior Vice President of Business Development since September 2007 and Vice President of Business Development since March 2001. He joined our predecessor as Vice President of Business Development in 1998. From 1996 through 1998, he served as a regional manager for Dynegy Inc., responsible for propane activities in 17 midwestern and northeastern states. From 1993 through 1996, Mr. Hughes served as a regional marketing manager for LPG Services Group. From 1985 through 1992, Mr. Hughes was employed by Ferrellgas where he served in a variety of management positions.
Laura L. Ozenberger. Ms. Ozenberger has served as Senior Vice President-General Counsel and Secretary since September 2007 and Vice President-General Counsel and Secretary since February 2003. From 1990 to 2003, Ms. Ozenberger worked for Sprint Corporation. While at Sprint, Ms. Ozenberger served in a number of management roles in the Legal and Finance departments. Prior to 1990, Ms. Ozenberger was in a private legal practice. She also serves as Senior Vice President-General Counsel and Secretary of Inergy Holdings GP, LLC.
Andrew L. Atterbury. Mr. Atterbury has served as Senior Vice President-Corporate Development since September 2007 and Vice President-Corporate Strategy since 2003. Prior to that, Mr. Atterbury served as the Director of Corporate Development from 2002 to 2003. From 1999 to 2001, Mr. Atterbury worked in the Corporate Development Group of Kinder Morgan, Inc. and Kinder Morgan G.P., Inc. From 1996 through 1998, Mr. Atterbury was employed by Lehman Brothers, Inc. in its Real Estate Finance Group.
William R. Moler. Mr. Moler has served as Senior Vice President-Natural Gas Midstream Operations since September 2007, Vice President of Midstream Operations since 2005 and Director of Midstream Operations
since 2004. Prior to joining Inergy, Mr. Moler was with Westport Resources Corporation where he served as both General Manager of Marketing and Transportation Services and General Manager of Westport Field Services, LLC. Prior to Westport, Mr. Moler served in various leadership positions at Kinder Morgan, Inc.
Warren H. Gfeller. Mr. Gfeller has been a member of our managing general partner’s board of directors since March 2001. He was a member of our predecessor’s board of directors from January 2001 until July 2001. He has engaged in private investments since 1991. From 1984 to 1991, Mr. Gfeller served as president and chief executive officer of Ferrellgas, Inc., a retail and wholesale marketer of propane and other natural gas liquids. Mr. Gfeller began his career with Ferrellgas in 1983 as an executive vice president and financial officer. Prior to joining Ferrellgas, Mr. Gfeller was the Chief Financial Officer of Energy Sources, Inc. and a CPA at Arthur Young & Co. He also serves as a director of Inergy Holdings GP, LLC.
Arthur B. Krause. Mr. Krause has been a member of our managing general partner’s board of directors since May 2003. Mr. Krause retired from Sprint Corporation in 2002, where he served as Executive Vice President and Chief Financial Officer from 1988 to 2002. He was President of United Telephone-Eastern Group from 1986 to 1988. From 1980 to 1986, he was Senior Vice President of United Telephone System. He also serves as a director of Inergy Holdings GP, LLC and Westar Energy.
Robert D. Taylor. Mr. Taylor joined our managing general partner’s board of directors in May 2005. Mr. Taylor, a CPA, has served as chief executive officer of Executive AirShare Corporation since November 2001. Mr. Taylor also served as president of Executive AirShare Corporation from November 2001 until November 2007. From August 1998 until September 2001, Mr. Taylor was president of Executive Aircraft Corporation. Mr. Taylor serves as a director of Blue Valley BanCorp. and Elecsys Corporation.
Independent Directors
Messrs. Gfeller, Krause and Taylor qualify as “independent” in accordance with the published listing requirements of the NASDAQ Global Select National Market. The NASDAQ independence definition includes a series of objective tests, such as that the director is not an employee of the company and has not engaged in various types of business dealings with the company. In addition, as further required by the NASDAQ rules, the board of directors has made a subjective determination as to each independent director that no relationships exist which, in the opinion of the board, would interfere with the exercise of independent judgment in carrying out the responsibilities of a director.
Board Committees
Audit Committee
The members of the audit committee must meet the independence standards established by the NASDAQ Global Select National Market. The members of the audit committee are Arthur B. Krause, Warren H. Gfeller and Robert D. Taylor. The board of directors of our managing general partner has determined that Mr. Gfeller is an audit committee financial expert based upon the experience stated in his biography. We believe that he is independent of management. The audit committee’s primary responsibilities are to monitor: (a) the integrity of our financial reporting process and internal control system; (b) the independence and performance of the independent registered public accounting firm; and (c) the disclosure controls and procedures established by management.
Conflicts Committee
Our managing general partner may appoint two independent directors to serve on a conflicts committee to review specific matters which the board of directors believes may involve conflicts of interest. A conflicts committee will determine if the resolution of any conflict of interest submitted to it is fair and reasonable to us. In addition to satisfying certain other requirements, the members of the conflicts committee must meet the independence
standards for service on an audit committee of a board of directors, which standards are established by the NASDAQ Global Select National Market. Any matters approved by the conflicts committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners and not a breach by our managing general partner of any duties it may owe us or our unitholders.
Compensation Committee
Two members of the board of directors also serve on a compensation committee, which oversees compensation decisions for the officers of Inergy GP, LLC, as well as the compensation plans described below. The members of the compensation committee are Warren H. Gfeller and Arthur B. Krause.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Securities Exchange Act of 1934 requires our company’s directors and executive officers, and persons who own more than 10% of any class of equity securities of our company registered under Section 12 of the Exchange Act, to file with the Securities and Exchange Commission initial reports of ownership and reports of changes in ownership in such securities and other equity securities of our company. Securities and Exchange Commission regulations require directors, executive officers and greater than 10% unitholders to furnish our company with copies of all Section 16(a) reports they file. To our knowledge, based solely on review of the reports furnished to us and written representations that no other reports were required, during the fiscal year ended September 30, 2009, all section 16(a) filing requirements applicable to our directors, executive officers and greater than 10% unitholders, were met.
Code of Ethics
We have adopted a code of ethics that applies to our principal executive officer, principal financial officer, principal accounting officer or controller or persons performing similar functions, as well as to all of our other employees. This code of ethics may be found on our website at www.inergypropane.com.
Item 11.
Item 11. Executive Compensation.
Compensation Discussion and Analysis
Introduction
We do not directly employ any of the persons responsible for managing our business. Inergy GP, LLC, our managing general partner, manages our operations and activities, and its board of directors and officers make decisions on our behalf. The compensation of the directors and certain officers of our managing general partner is determined by the compensation committee of the board of directors of our managing general partner. Certain of our named executive officers also serve as executive officers of the general partner of Inergy Holdings, L.P. and the compensation of the named executive officers discussed below reflects total compensation for services to all Inergy entities. These “shared” officers receive no additional salary or cash compensation for their service to Inergy Holdings, L.P. However, as discussed in greater detail below, from time to time they do receive awards of equity in Inergy Holdings, L.P.
Compensation Philosophy and Objectives
We employ a compensation philosophy that emphasizes pay for performance. The primary measure of our performance is our ability to increase sustainable quarterly cash distributions to our unitholders and the related unitholder value realized. We believe that by tying a substantial portion of each named executive officer’s total compensation to financial performance metrics based on such distributions and unitholder value, our pay-for-performance approach aligns the interests of executive officers with that of our unitholders. Accordingly, the objectives of our total compensation program consist of:
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aligning executive compensation incentives with the creation of unitholder value and the growth of cash earnings on behalf of our unitholders;
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balancing short and long-term performance;
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tying short-and long-term compensation to the achievement of performance objectives (company, business unit, department and/or individual); and
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attracting and retaining the best possible executive talent for the benefit of our unitholders.
By accomplishing these objectives, we hope to optimize long-term unitholder value.
Compensation Setting Process
Chief Executive Officer’s Role in the Compensation Setting Process
Our Chief Executive Officer plays a significant role in the compensation setting process. The most significant aspects of his role are:
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assisting in establishing business performance goals and objectives;
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evaluating executive officer and company performance;
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recommending compensation levels and awards for executive officers; and
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implementing the approved compensation plans.
The Chief Executive Officer makes recommendations to the compensation committee with respect to financial metrics to be used for performance-based awards as well as other recommendations regarding non-CEO executive compensation, which may be based on our performance, individual performance and the peer group compensation market analysis. The compensation committee considers this information when establishing the total compensation package of the executive officers. The Chief Executive Officer’s performance and compensation is reviewed, evaluated and established separately by the compensation committee based on criteria similar to those used for non-CEO executive compensation.
Market Analysis
To evaluate the competitiveness of both total executive compensation and the individual compensation components, the compensation committee utilizes compensation data about other companies to assist in assessing executive compensation levels, including the individual base salary and incentive components. The data typically consists of an analysis of total compensation, as well as base salary amounts, annual incentive awards, and long-term incentive awards and is compiled from public filings of similar companies, as well as companies in the Kansas City region. We selected these “peer” companies because, like us, they are: (i) MLPs with significant propane operations, or (ii) MLPs with growing midstream operations. We chose the regional companies because they are public companies with which we compete for talent in the local employment market.
“Peer” MLP Companies
Regional Companies
Amerigas Partners, L.P.
Compass Minerals International, Inc.
Copano Energy, LLC
DST Systems, Inc.
Crosstex Energy, L.P.
Layne Christensen Company
Energy Transfer Partners, L.P.
Kansas City Southern
Ferrellgas Partners, L.P.
Markwest Energy Partners, L.P.
Suburban Propane Partners, L.P.
The compensation committee utilizes the market data as a general guideline in making compensation-related decisions. When determining compensation amounts for our executive officers, the compensation committee uses data from our “peer” group as a reference for determining:
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amount of total compensation;
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individual components of compensation; and
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relative proportion of each component of compensation-base salary, annual incentive award opportunity and long-term incentive award value.
While our general objective for total compensation is at or above the median of the “peer” group data with a significant portion of total compensation at risk, we do not require a strict policy of achieving a specific percentile relationship of actual pay to market pay as some companies do. The compensation committee has the full discretion to disregard the market data and award compensation at a different range if there are factors warranting the adjustment. Such factors may include alignment of the officer’s position within the “peer” group data, experience and value he or she brings to the role, sustained high-level performance, demonstrated success in meeting key financial and other business objectives and the amount of the officer’s pay relative to the pay of his or her peers within our company.
In addition, the actual value delivered to any executive may be above or below that range depending upon our financial results, common unit price performance and the individual’s performance.
The compensation committee may in its discretion retain the services of a third-party compensation consultant, but did not retain any such consultants this fiscal year.
In collecting the peer group data for the compensation committee for fiscal 2009, we compared each officer’s position against like positions for our “peer” group. The data was adjusted for differences in various financial and operating metrics, including revenues, customer base, numbers of employees and scope for each position relative to comparator company positions. Based on the difficulty in assessing appropriate comparisons of relative value for equity awards, no specific comparison of equity awards of our “peer” companies was made for long-term incentive opportunity values although the market value of equity holdings of similarly situated employees at our “peer” companies was generally considered.
Elements of Compensation
The principal elements of compensation for the named executive officers are the following:
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base salary;
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incentive awards;
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long-term incentive plan awards; and
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retirement and health benefits.
Base Salary
Base salary is designed to compensate executives for the responsibility of the level of the position they hold and sustained individual performance (including experience, scope of responsibility, results achieved and future potential). Base salary amounts were initially established in the employment agreements of our named executive officers and we historically have not made annual adjustments to the salaries of our named executive officers. We do, however, review the salaries of our named executive officers on an annual basis, as well as at the time of promotion and may adjust salaries due to changes in responsibilities or market conditions. In determining the amount of any adjustments, the compensation committee uses market data as a tool for assessing the reasonableness of the base salary amounts of the named executive officers as compared to the compensation of executives in similar positions with similar responsibility levels in our industry and in our region. However, the final determination of base salary amounts is within the compensation committee’s subjective discretion.
In fiscal 2008, after two years of no changes to base salary amounts, the compensation committee determined it was appropriate to adjust base salaries. In so doing, the compensation committee primarily considered:
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the increased level of responsibility of each of the named executive officers, which resulted from a number of acquisitions in fiscal years 2005 through 2007, including the acquisition of the Stagecoach facility, resulting in the addition of the midstream segment to our business;
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the increased complexity in the business, which resulted from:
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the initial public offering of Inergy Holdings, L.P. in fiscal 2005; and
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the diversification of business, including the addition of the midstream segment;
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our financial results during fiscal 2007, including:
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Adjusted EBITDA;
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distributable cash flow; and
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distributable cash flow per unit on a fully distributed basis; and
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the general value of the officers to the company based on increased knowledge of the business and the industry as a result of tenure with the company.
As a result of those considerations, the base salaries of each of our named executive officers was increased to $350,000, $225,000, $275,000, $200,000 and $200,000 for John J. Sherman, R. Brooks Sherman, Phillip L. Elbert, Laura L. Ozenberger and William R. Moler, respectively.
For fiscal 2009, consistent with its general policy of not making systematic annual adjustments to base salary, the compensation committee elected not to make any changes to the annual base salaries of our named executive officers.
Incentive Awards
Incentive awards are designed to reward the performance of key employees, including the named executive officers, by providing annual incentive opportunities for the partnership’s achievement of its annual financial performance goals. In particular, these bonus awards are provided to the named executive officers in order to provide competitive incentives to these executives who can significantly impact performance and promote achievement of the our short-term business objectives. Under the terms of their respective employment agreements, each named executive officer is eligible, upon the achievement of certain subjective and objective criteria, to receive a cash bonus amount that is up to 100% of the named executive officer’s base salary.
The bonuses payable to the named executive officers in fiscal 2009 were based upon our achievement of two financial performance metrics: (i) earnings before income taxes, plus net interest expense, depreciation and amortization expense, further adjusted to exclude the gain or loss on derivative contracts, the gain or loss on the disposal of fixed assets and long-term incentive and equity compensation expense (“Adjusted EBITDA”) and (ii) growth in annualized distributions per unit. We have selected these metrics because we believe they closely align the focus of our named executive officers with the increase in unitholder value. In addition, these were the targets we communicated to our unitholders and analysts as guidance at the beginning of the 2009 fiscal year. The financial performance targets were not weighted.
The following table summarizes the incentive award targets and our actual results for the fiscal year ended September 30, 2009 (in millions, except per unit data):
(1) Adjusted EBITDA represents EBITDA excluding (1) non-cash gains or losses on derivative contracts associated with fixed price sales to retail propane customers, (2) non-cash compensation charges and (3) gains or losses on disposals of assets. For a reconciliation of EBITDA to Adjusted EBITDA refer to page 36 of this annual report on Form 10-K.
As reflected in the table above, for fiscal year 2009 we exceeded the targets for Adjusted EBITDA and annualized distribution growth per unit. Accordingly, in accordance with the terms of the employment agreements of the named executive officers, the compensation committee approved the short-term incentive awards for fiscal 2009 at 100% of base salary performance. In approving the awards, the compensation committee also considered that combined annual base salary and annual incentive awards were generally at the median of our peer companies. Additionally, William R. Moler was awarded a discretionary cash bonus of $55,000 for his leadership on certain midstream expansion projects.
Long-Term Incentive Plan Awards
Long-term incentive awards for the named executive officers are granted under the Inergy Long Term Incentive Plan and Inergy Holdings Long Term Incentive Plan in order to promote achievement of our primary long-term strategic business objective of increasing distributable cash flow and increasing unitholder value. These plans are designed to align the economic interests of key employees and directors with those of our common unitholders and the common unitholders of Inergy Holdings, L.P. and to provide an incentive to management for continuous employment with the managing general partner and its affiliates. Long-term incentive compensation is based upon the common units representing limited partnership interests in us or Inergy Holdings, L.P. and may consist of unit options or restricted units. We have no policy regarding the allocation of different types of equity awards; rather, we determine which type of award will be granted due to a number of different factors, including, cost to the company, perceived value to the employee and economic conditions.
We do not make systematic annual awards to the named executive officers. Generally, we believe that a two- to five-year grant cycle (and complete vesting over five years) provides a balance between a meaningful retention period for us and a visible, reachable reward for the executive officers. New awards are generally synchronized with the remaining time-vesting requirements of outstanding awards in a manner designed to encourage extended retention of the named executive officers.
In determining the size of the equity awards, the compensation committee primarily considers the grant date value and vesting schedule of the awards as both a retention tool and performance incentive, the experience and skills of the executive officers as well as their contributions to our operational and financial performance, the economic and retention value of outstanding equity awards held by the executives for both our company and for Inergy Holdings, the amount of cash distributions that would be received by the executives and cost to our company. These factors were not given any specific weight; rather, they were subjectively evaluated by the compensation committee. The value of the equity was also compared to the equity awards of our “peer” companies to assess reasonableness of the awards without imposing specific targets.
Prior equity awards were made in fiscal 2002, fiscal 2005 and fiscal 2008. Consistent with our general policy of not making systematic annual awards, no equity awards were made to the named executive officers in fiscal 2009. However, in connection with an amendment to Mr. Moler’s employment agreement, on November 25, 2009, the compensation committee awarded Mr. Moler 37,500 Inergy, L.P. restricted units and 37,500 Inergy Holdings, L.P. restricted units, which are subject to forfeiture if certain company financial performance metrics are not met.
Inergy Long Term Incentive Plan
Our managing general partner sponsors the Inergy Long Term Incentive Plan for its directors, consultants and employees and the employees and consultants of its affiliates who perform services for us. The plan is administered by the compensation committee of the managing general partner’s board of directors.
Unit Options
The Inergy Long Term Incentive Plan currently permits, and our managing general partner has made, grants of options covering common units. Unit options will have an exercise price equal to the fair market value of the units on the date of grant. In general, unit options will become exercisable over a five-year period. In addition, the unit options will become exercisable upon a change of control of the managing general partner or us. Generally, unit options will expire after 10 years.
Upon exercise of a unit option, our managing general partner will acquire common units in the open market, or directly from us or any other person, or use common units already owned by the managing general partner, or any combination of the foregoing. The managing general partner will be entitled to reimbursement by us for the difference between the cost incurred by the managing general partner in acquiring these common units and the proceeds received by the managing general partner from an optionee at the time of exercise. Thus, the cost of the unit options will be borne by us. If we issue new common units upon exercise of the unit options, the total number of common units outstanding will increase and the managing general partner will pay us the proceeds it received from the optionee upon exercise of the unit options. The unit option plan has been designed to furnish additional compensation to employees and directors and to align their economic interests with those of common unitholders.
Restricted Units
The Inergy Long Term Incentive Plan currently permits, and our managing general partner has made, grants of restricted units. Restricted units are subject to a restricted period the terms of which are set forth in a restricted unit award agreement. In general, restricted units vest over a five-year period. The individual award agreement also sets forth the conditions under which the restricted units may become vested or forfeited, which may include, without limitation, the accelerated vesting upon the achievement of specified performance goals, or the forfeiture for failing to achieve specified performance goals and such other terms and conditions as the committee may establish. Unless otherwise specifically provided for in an award agreement, distributions are paid to the holder of the restricted units without restriction. Restricted units are designed to furnish additional compensation to employees and directors and to align their economic interests with those of common unitholders.
Termination and Amendment
The managing general partner’s board of directors in its discretion may terminate the Inergy Long Term Incentive Plan at any time with respect to any common units for which a grant has not yet been made. The managing general partner’s board of directors also has the right to alter or amend Inergy Long Term Incentive Plan from time to time, including increasing the number of common units with respect to which awards may be granted subject to unitholder approval as required by the exchange upon which the common units are listed at that time. However, no change in any outstanding grant may be made that would materially impair the rights of the participant without the consent of the participant.
Inergy Holdings Long Term Incentive Plan
Inergy Holdings GP, LLC, the general partner of Inergy Holdings, L.P., sponsors the Inergy Holdings Long Term Incentive Plan for its directors, consultants and employees and the employees and consultants of its affiliates who perform services for us. The plan is administered by the compensation committee of the general partner’s board of directors of Inergy Holdings GP, LLC.
Unit Options
The Inergy Holdings Long Term Incentive Plan currently permits, and its general partner has made, grants of options covering common units. Unit options will have an exercise price equal to the fair market value of the units on the date of grant. In general, unit options granted will become exercisable over a five-year period. In addition, the unit options will become exercisable upon a change of control of Holdings’ general partner. Generally, unit options will expire after 10 years.
Upon exercise of a unit option, Holdings’ general partner will acquire common units in the open market, or directly from Holdings or any other person, or use common units already owned by the general partner, or any combination of the foregoing. The general partner will be entitled to reimbursement by Holdings for the difference between the cost incurred by the general partner in acquiring these common units and the proceeds received by the general partner from an optionee at the time of exercise. If Holdings issues new common units upon exercise of the unit options, the total number of common units outstanding will increase and the general partner will pay Holdings the proceeds it received from the optionee upon exercise of the unit options. The unit option plan has been designed to furnish additional compensation to employees and directors and to align their economic interests with those of common unitholders.
Restricted Units
The Inergy Holdings Long Term Incentive Plan currently permits, and its general partner has made, grants of restricted units. Restricted units are subject to a restricted period the terms of which are set forth in a restricted unit award agreement. In general, restricted units vest over a five-year period. The individual award agreement also sets forth the conditions under which the restricted units may become vested or forfeited, which may include, without limitation, the accelerated vesting upon the achievement of specified performance goals, or the forfeiture for failing to achieve specified performance goals and such other terms and conditions as the committee may establish. Unless otherwise specifically provided for in an award agreement, distributions are paid to the holder of the restricted units without restriction. Restricted units are designed to furnish additional compensation to employees and directors and to align their economic interests with those of common unitholders.
Termination and Amendment
Holdings’ general partner’s board of directors in its discretion may terminate the Inergy Holdings Long Term Incentive Plan at any time with respect to any common units for which a grant has not yet been made. Holdings’ general partner’s board of directors also has the right to alter or amend the Inergy Holdings Long Term Incentive Plan from time to time, including increasing the number of common units with respect to which awards may be granted subject to unitholder approval as required by the exchange upon which the common units are listed at that time. However, no change in any outstanding grant may be made that would materially impair the rights of the participant without the consent of the participant.
Other Compensation Related Matters
Retirement and Health Benefits
We offer a variety of health and welfare and retirement programs to all eligible employees. The named executive officers are eligible for the same programs on the same basis as other employees. We maintain a 401(k) retirement plan that provides eligible employees with an opportunity to save for retirement on a tax advantages basis. We match 50% of the first 6% of the deferral to the retirement plan (not to exceed the maximum amount permitted by law) made by eligible participants. Our executive officers are also eligible to participate in additional employee benefits available to our other employees.
Perquisites and Other Compensation
We do not provide perquisites or other personal benefits to any of the named executive officers.
Severance Benefits
We maintain employment agreements with all our named executive officers to ensure they will perform their roles for an extended period of time and not compete with us upon termination of employment. These agreements are described in more detail elsewhere in this Annual report. Please read “Narrative Disclosure to Summary Compensation Table and Grants of Plan-Based Awards Table-Employment Agreements.” These agreements do not provide any form of severance payment upon a change in control. However, the agreements do provide for continued salary payments following termination of employment without cause (as defined in the employment agreements). Thus, the continued salary provisions only become operative in the event of a change in control if such change in control is accompanied by a change in employment status (such as the termination of employment). We believe this arrangement is appropriate because it provides assurance to the executive, but does not offer a windfall to the executive when there has been no real change in employment status. In addition, both the Inergy Long Term Incentive Plan and Inergy Holdings Long Term Incentive Plan provide for accelerated vesting triggered upon a change of control.
Tax Deductibility of Compensation
With respect to the deduction limitations under Section 162(m) of the Code, we are a limited partnership and do not meet the definition of a “corporation” under Section 162(m). Nonetheless, the salaries for each of the named executive officers are substantially less than the Section 162(m) threshold of $1,000,000 and we believe the bonus compensation and long-term incentive compensation would qualify for performance-based compensation under Reg. 1.162-27(e) and therefore would not be additive to salaries for purposes of measuring the $1,000,000 tax limitation.
Compensation Committee Report
We have reviewed and discussed the foregoing Compensation Discussion and Analysis with management. Based on our review and discussion with management, we have recommended that the Compensation Discussion and Analysis be included in this Annual Report on Form 10-K for the year ended September 30, 2009.
Warren H. Gfeller
Arthur B. Krause
Members of the Compensation Committee
Summary Compensation Table
The following table sets forth the cash and non-cash compensation earned for the years ended September 30, 2009, September 30, 2008, and September 30, 2007 by each person who served as the Chief Executive Officer, Chief Financial Officer and the three other highest paid executive officers (the “named executive officers”) during fiscal 2009.
(1) The amounts included in the “Stock Awards” and “Option Awards” columns reflect the dollar amount of compensation expense we recognized with respect to these awards for the fiscal year ended September 30, 2009, and include amounts attributable to awards granted in and prior to fiscal 2009. Assumptions used in the calculation of these amounts are discussed in Note 9 to our consolidated financial statements. These amounts reflect our accounting expense for these awards, and do not correspond to the actual value that will be recognized by the named executive officers. The material terms of our outstanding LTIP awards to our executive officers are described in “Compensation Discussion and Analysis-Long-Term Incentive Plans.”
(2) John J. Sherman, R. Brooks Sherman, Jr., Phillip L. Elbert and William R. Moler were awarded Inergy, L.P. restricted units in an amount equal to $350,000, $225,000,$275,000 and $200,000, respectively, for their fiscal 2008 annual incentive. The restricted units were granted on December 1, 2008, with the actual number of restricted units granted based on the closing price of an Inergy, L.P common unit on such date. The restricted units fully vested on February 4, 2009 (60 days from the grant date).
(3) Consists of: (i) distributions paid on restricted units granted under the Long-Term Incentive Plans (R. Brooks Sherman, Jr.-$99,925, Phillip L. Elbert-$142,750, Laura L. Ozenberger-$71,375 and William R. Moler-$94,075); (ii) matching contributions to the partnership’s 401(k) Plan for each named executive officer; and (iii) the partnership’s payment for the benefit of the named executive officers under the partnership’s group term life insurance policy. The partnership does not provide perquisites and other personal benefits exceeding a total value of $10,000 to any named executive officer.
(4) As discussed in the Compensation Discussion & Analysis, William R. Moler was awarded a discretionary cash bonus of $55,000 for his leadership on certain midstream expansion projects.
Grants of Plan Based Awards Table
The following table provides information concerning each grant of an award made to our named executive officers in the last completed fiscal year under any plan, including awards that have been transferred.
(1) The “Maximum” amount may be increased by the discretion of the Compensation Committee as described above in the “Compensation Discussion and Analysis-Incentive Awards.”
(2)
The compensation committee awarded John J. Sherman, R. Brooks Sherman, Jr., Phillip L. Elbert and William R. Moler their fiscal 2008 incentive award in Inergy, L.P. restricted units. Although granted in fiscal 2009, these awards are reported in the Summary Compensation Table in fiscal 2008 because they are part of the named executive officers’ fiscal 2008 incentive compensation.
Narrative Disclosure to Summary Compensation Table and Grants of Plan-Based Awards Table
A discussion of fiscal 2009 salaries and bonuses is included above in “Compensation Discussion and Analysis.” The following is a discussion of other material factors necessary to an understanding of the information disclosed in the Summary Compensation Table.
Employment Agreements
The following named executive officers have entered into employment agreements with our company:
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John J. Sherman, President and Chief Executive Officer;
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R. Brooks Sherman, Jr., Executive Vice President-Chief Financial Officer;
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Phillip L. Elbert, President and Chief Operating Officer-Propane Operations;
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Laura L. Ozenberger, Senior Vice President-General Counsel and Secretary; and
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William R. Moler, Senior Vice President-Natural Gas Midstream Operations.
The following is a summary of the material provisions of these employment agreements, each of which is incorporated by reference herein as an exhibit to this report.
All of these employment agreements are substantially similar, with certain exceptions as set forth below. The employment agreements are for terms of either three or five years. During the fiscal year, the annual salaries for these individuals are as follows:
•
John J. Sherman-$350,000
•
R. Brooks Sherman, Jr.-$225,000
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Phillip L. Elbert-$275,000
•
Laura L. Ozenberger-$200,000
•
William R. Moler-$200,000
These employees are reimbursed for all expenses in accordance with the managing general partner’s policies. They are also eligible for fringe benefits normally provided to other employees.
All of the individuals are eligible for annual performance bonuses upon meeting certain established criteria for each year during the term of his or her employment.
Generally, unless waived by the managing general partner, in order for any of these individuals to receive any benefits under (i) the Inergy Long Term Incentive Plan and the Inergy Holdings Long Term Incentive Plan, or (ii) the performance bonus, the individual must have been continuously employed by the managing general partner or one of our affiliates from the date of his or her employment agreement up to the date for determining eligibility to receive such amounts.
Each employment agreement contains confidentiality and noncompetition provisions. Also, each employment agreement contains a disclosure and assignment of inventions clause that requires the employee to disclose the existence of any invention and assign such employee’s right in such invention to the managing general partner.
With respect to each of the named executive officers, in the event such person’s employment is terminated without cause, we will be required to continue making payments to such person for the remainder of the term of such person’s employment agreement.
Effective November 25, 2009, Mr. Moler’s employment agreement was amended to expand the noncompetition provision and extend the term until November 24, 2014. A copy of the amendment is included herewith as Exhibit 10.7A.
Outstanding Equity Awards at Fiscal Year-End Table
The following table summarizes the options and restricted units outstanding as of September 30, 2009, for the named executive officers. The table includes unit options and restricted units of Inergy, L.P. (NASDAQ: NRGY) granted under the Inergy Long Term Incentive Plan and unit options and restricted units of Inergy Holdings, L.P. (NASDAQ: NRGP) granted under the Inergy Holdings Long Term Incentive Plan.
(1) Option vested in full on February 10, 2008 (5 years from the grant date).
(2) 10,000 vested on June 20, 2009 and 20,000 will vest June 20, 2010.
(3) Option will vest in full on June 20, 2010 (5 years from the grant date).
(4) Option vested in full on July 12, 2009 (5 years from the grant date).
(5) Option will vest in full on September 15, 2010 (5 years from the grant date).
(6) 3,750 vested on June 20, 2008, 3,750 vested on June 20, 2009, and the remaining 7,500 will vest on June 20, 2010.
(7) 1,250 vested on September 15, 2008, 1,250 vested on September 15, 2009, and the remaining 2,500 will vest on September 15, 2010.
(8) Market value for NRGY units based on the NASDAQ closing price of $29.78 on September 30, 2009, and market value of NRGP units based on the NASDAQ closing price of $46.40 on September 30, 2009.
Option Exercises and Stock Vested Table
The following table provides information regarding option exercises and restricted unit vesting during the fiscal year ended September 30, 2009, for the named executive officers.
(1) Messrs. Sherman, Sherman, Elbert and Moler took their fiscal 2008 annual incentive award payouts in Inergy, L.P. restricted units with the number based on the cash value of their respective annual incentive awards divided by the NASDAQ closing price of our common units on such date (December 1, 2008), which units fully vested on February 4, 2009 (60 days from the grant date).
Pension Benefits Table
We do not offer any pension benefits.
Nonqualified Deferred Compensation Table
We have no non-qualified deferred compensation plans.
Potential Payments upon a Change in Control or Termination
Employment Agreements
Under the employment agreements with our named executive officers, we may be required to pay certain amounts upon the employment termination of the named executive officer in certain circumstances. Upon the termination of employment of a named executive officer without Cause, the employment agreements entered into between Inergy GP, LLC and each of the named executive officers provide for salary continuation at the rate in effect at termination of the employee through the remaining term of the employment agreement. Consequently, no severance is payable in the event of any termination (i) as a result of death, disability, or legal incompetence, (ii) as a result of Inergy GP, LLC ceasing to carry on its business without assigning the employment agreement, (iii) as a result of Inergy GP, LLC becoming bankrupt, (iv) for Cause or (v) by the employee for any or no reason. For purposes of the employment agreements:
Cause will generally be determined to have occurred in the event the:
•
employee has failed to perform his or her duties as an employee of Inergy GP, LLC, to perform any obligation under the employment agreement or to observe and abide by Inergy GP, LLC’s policies and decisions, provided that Inergy GP, LLC has given employee reasonable notice of that failure and employee is unsuccessful in correcting that failure or in preventing its reoccurrence;
•
employee has refused to comply with specific directions of his/her supervisor or other superior, provided that such directions are consistent with the employee’s position of employment;
•
employee has engaged in misconduct that is injurious to Inergy GP, LLC or any subsidiary, parent or affiliate of Inergy GP, LLC;
•
employee has been convicted of, or has entered a plea of nolo contendere to, any crime involving the theft or willful destruction of money or other property, any crime involving moral turpitude or fraud, or any crime constituting a felony;
•
employee has engaged in acts or omissions against Inergy GP, LLC or any subsidiary, parent or affiliate of Inergy GP, LLC constituting dishonesty, breach of fiduciary obligation, or intentional wrongdoing or misfeasance; or
•
employee has used alcohol or drugs on the job, or has engaged in excessive absenteeism from the performance of his/her duties as Inergy GP, LLC’s employee, other than for reasons of illness.
If a termination of a named executive officer by Inergy GP, LLC without Cause were to have occurred as of September 30, 2009, our named executive officers would have been entitled to the following:
•
John J. Sherman would have received $320,833, representing base salary for the remaining 11 months of the term of his employment agreement (payable bi-monthly in arrears). For two years following the termination of Mr. Sherman’s employment he will continue to be subject to the non-competition provisions of his employment agreement.
•
R. Brooks Sherman, Jr. would have received $168,750, representing base salary for the remaining 9 months of the term of his employment agreement (payable bi-monthly in arrears). For two years following termination of Mr. Sherman’s employment he will continue to be subject to the non-competition provisions of his employment agreement.
•
Phillip L. Elbert would have received $68,750, representing base salary for the remaining 3 months of the term of his employment agreement (payable bi-monthly in arrears). In addition, to receiving severance payments upon a termination of employment without Cause, Mr. Elbert is entitled to the same benefits if he terminates his employment for “Good Reason” which is defined as (i) Inergy GP, LLC requiring, as a condition of employee’s employment, that employee commit a felony or engage in conduct that is a crime under the Securities Act of 1933, as amended, or the Securities Exchange Act of 1934, as amended; and (ii) employee being required by Inergy GP, LLC to be based at any office or location that is more than 35 miles from the location where employee was employed immediately preceding the date of the voluntary or involuntary termination of employee’s employment. For up to two years following termination of Mr. Elbert’s employment he will continue to be subject to the non-competition provisions of his employment agreement.
•
Laura L. Ozenberger would have received $200,000 representing base salary for the remaining 12 months of the term of her employment agreement (payable bi-monthly in arrears). For a minimum of one year following termination of employment Ms. Ozenberger will continue to be subject to the non-competition provisions of her employment agreement.
•
William R. Moler would have received $400,000 representing base salary for the remaining 24 months of the term of his employment agreement (payable bi-monthly in arrears). In addition, to receiving severance payments upon a termination of employment without Cause, Mr. Moler is entitled to the same benefits if he terminates his employment for “Good Reason” which is defined as (i) employee being required by Inergy GP, LLC to be based at any office or location that is more than 75 miles from the location where employee was employed immediately preceding the date of the voluntary or involuntary termination of employee’s employment, or (ii) a material reduction in employee’s job duties and responsibilities. For two years following termination of Mr. Moler’s employment he will continue to be subject to the non-competition provisions of his employment agreement. Effective November 25, 2009, Mr. Moler’s employment agreement was amended to expand the noncompetition provision and extend the term until November 24, 2014. A copy of the amendment is included herewith as Exhibit 10.7A.
Inergy Long Term Incentive Plan and Inergy Holdings Long Term Incentive Plan
Upon a change in control, all unit options and restricted units will automatically vest and become payable or exercisable, as the case may be, in full and any restricted periods or performance criteria will terminate or be deemed to have been achieved at the maximum level. For purposes of the Inergy Long Term Incentive Plan and Inergy Holdings Long Term Incentive Plan, a “change in control” means, and shall be deemed to have occurred upon one of the following events: (i) any sale, lease, exchange or other transfer (in one or a series of related transactions) of all or substantially all of the assets of the Inergy Partners, LLC or Inergy, L.P. to any person or its affiliates, other than Inergy GP, LLC, the Partnership or any of their affiliates, or (ii) any merger, reorganization, consolidation or other transaction pursuant to which more than 50% of the combined voting power of the equity interests in Inergy GP, LLC or Inergy Partners, LLC ceases to be controlled by Inergy Holdings, L.P.
If a change in control were to have occurred as of September 30, 2009, all unvested awards held by the named executive officers under the Inergy Long Term Incentive Plan as well as the Inergy Holdings Long Term Incentive Plan would have automatically vested and become exercisable, as follows:
(1) For options, the amounts included in the “Total” column are calculated by subtracting the per share exercise price under the options from the closing per share price of our common units on September 30, 2009 ($29.78), or the closing per share price of the common units of Holdings ($46.40), as applicable, and multiplying the difference by the number of units subject to the option. For restricted units the amounts included in the “Total” column are calculated by multiplying the number of restricted units by the closing per share price of our common units on September 30, 2009 ($29.78), or the closing per share price of the common units of Holdings ($46.40), as applicable.
Director Compensation Table
The following table sets forth the cash and non-cash compensation earned for the year ended September 30, 2009, by each person who served as a non-employee director of Inergy GP, LLC.
(1) The amounts included in the “Unit Awards” and “Option Awards” columns reflect the dollar amount of compensation expense we recognized with respect to these awards for the fiscal year ended September 30, 2009, and include amounts attributable to awards granted in and prior to fiscal 2009. Assumptions used in the calculation of these amounts are discussed in Note 9 to our consolidated financial statements. These amounts reflect our accounting expense for these awards and do not correspond to the actual value that will be recognized by the directors.
(2) Dollar value of distributions paid on restricted units during the fiscal year ended September 30, 2009.
(3) Mr. Pascal retired from the board of directors effective December 12, 2008.
Compensation of Directors
Officers of our managing general partner who also serve as directors will not receive additional compensation. Each director receives cash compensation of $25,000 per year for attending our regularly scheduled quarterly board meetings. Each non-employee director receives $1,000 for each special meeting of the board of directors attended and $1,000 per compensation, audit or conflicts committee meeting attended. The chairman of the audit committee receives an annual fee of $5,000 per year and the chairman of the compensation committee receives an annual fee of $1,000 per year. Furthermore, each non-employee director receives an annual grant of restricted units under the long-term incentive plan equal to $25,000 in value. In April 2009, Messrs. Gfeller, Krause and Taylor each received 1,126 restricted units under the Inergy Long Term Incentive Plan. These units vest ratably over three years beginning one year from the grant date. Each non-employee director is reimbursed for out-of-pocket expenses in connection with attending meetings of the board of directors or committees. Each director is fully indemnified for actions associated with being a director to the extent permitted under Delaware law. Messrs. Gfeller and Krause also receive compensation for their services on the board of directors of Inergy Holdings GP, LLC, which is not reflected in the table above.
Compensation Committee Interlocks and Insider Participation
The compensation committee of the board of directors of our managing general partner oversees the compensation of our executive officers. Warren H. Gfeller and Arthur B. Krause serve as the members of the compensation committee, and neither of them was an officer or employee of our company or any of its subsidiaries during fiscal 2009.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters.
The following table sets forth certain information as of October 30, 2009, regarding the beneficial ownership of our units by:
•
each person who then beneficially owned more than 5% of such units then outstanding;
•
each of the named executive officers of our managing general partner;
•
each of the directors of our managing general partner; and
•
all of the directors and named executive officers of our managing general partner as a group.
All information with respect to beneficial ownership has been furnished by the respective directors, officers or 5% or more unitholders, as the case may be.
* Less than 1%
(1) Unless otherwise indicated, the address of each person listed above is: Two Brush Creek Boulevard, Suite 200, Kansas City, Missouri 64112. All persons listed have sole voting power and investment power with respect to their units unless otherwise indicated.
(2) Of the common units indicated as beneficially owned by Inergy Holdings, 2,837,034 units are held by Inergy Partners, LLC, 789,202 units are held by IPCH Acquisition Corp., both wholly-owned subsidiaries of Inergy Holdings, and 1,080,453 units are held directly by Inergy Holdings.
(3) Information as to the number of common units is furnished in reliance upon the Schedule 13G’s of the corresponding entities or individuals.
(4) Mr. Sherman holds an ownership interest in Inergy Holdings through various trusts of which he has voting control. As trustee, Mr. John Sherman may be deemed to own 4,706,689 common units. Of these units, 789,202 are held by IPCH Acquisition Corp., a wholly-owned subsidiary of Inergy Holdings L.P. (formerly Inergy Holdings, LLC.), 2,837,034 units are held by Inergy Partners, LLC, of which Inergy Holdings L.P. (formerly Inergy Holdings, LLC) has 100% voting control, and 1,080,453 common units are held by Inergy Holdings, L.P. (formerly Inergy Holdings, LLC.). Mr. Sherman disclaims beneficial ownership of the reported securities except to the extent of his pecuniary interest. The remaining 136,760 common units include the 116,870 units held in a revocable trust by John J. Sherman, the 4,892 units held through the Inergy, L.P. EUPP and 14,998 units that are individually owned.
The following table shows the beneficial ownership as of October 30, 2009, of Inergy Holdings, L.P. of the directors and named executive officers of our managing general partner, the directors and named executive officers of the general partner of Inergy Holdings, L.P. and each person who beneficially owned more than 5% of such units outstanding. As reflected above, Inergy Holdings owns our managing general partner, non-managing general partner, incentive distribution rights and, through subsidiaries, 7.8% of our outstanding limited partner units.
* Less than 1%
(1) The address of each person listed above is Two Brush Creek Boulevard, Suite 200, Kansas City, Missouri 64112.
(2) Mr. Sherman may be deemed to beneficially own 7,936,826 common units held through various trusts, of which Mr. Sherman serves as either the trustee or co-trustee, and 2,053 units through the Employee Unit Purchase Plan.
(3) Mr. Gautreaux may be deemed to beneficially own 969,471 common units held through various trusts of which Mr. Gautreaux serves as either the trustee or co-trustee.
(4) Mr. Elbert may be deemed to beneficially own 855,732 common units held through various trusts of which Mr. Elbert serves as either the trustee or co-trustee.
We refer you to Item 5 of this report for certain information regarding securities authorized for issuance under equity compensation plans.
Item 13.
Item 13. Certain Relationships, Related Transactions and Director Independence.
Related Party Transactions
In connection with our acquisition of assets from United Propane, Inc. on July 31, 2003, we entered into ten leases of real property formerly used by United Propane (now known as Bonavita, Inc.) in its business. We entered into five of these leases with United Propane, three of these leases with Pascal Enterprises, Inc. and two
of these leases with Robert A. Pascal. Each of these leases provided for an initial five-year term, and was renewable by us for up to two additional terms of five years each. During the initial term of these leases we were required to make monthly rental payments totaling $59,167, of which $17,167 was payable to United Propane, $16,800 was payable to Pascal Enterprises and $25,200 was payable to Mr. Pascal. During fiscal 2008, we exercised our renewal option on six of these leases for an additional five-year term each. Three of these leases are with United Propane, two of these leases are with Mr. Pascal and one is with Pascal Enterprises. We are now required to make monthly rental payments totaling $50,947 of which $8,400 is payable to United Propane, $30,997 is payable to Mr. Pascal and $11,550 is payable to Pascal Enterprises. We believe that the monthly rental payments on the above described leases are consistent with the terms that could have been negotiated with an unrelated third party.
Robert A. Pascal is the sole shareholder of Bonavita, Inc., Pascal Enterprises and United Leasing. Mr. Pascal retired from our board of directors on December 12, 2008.
On occasion, Inergy Holdings reimburses us for expenses paid on behalf of Inergy Holdings. The expenses that are reimbursed predominantly include insurance and professional fees. These expenses for the years ended September 30, 2009, 2008 and 2007, amounted to $0.5 million, $0.2 million and $0.4 million, respectively. When we have a receivable from Inergy Holdings it is included in prepaid expenses and other current assets on our consolidated balance sheets. At September 30, 2009 and 2008, we had $0.1 million and $0.2 million, respectively, due from Inergy Holdings.
Review, Approval or Ratification of Transactions with Related Persons
Our Related Person Transactions Policy applies to any transaction since the beginning of our fiscal year (or currently proposed transaction) in which we or any of our subsidiaries was or is to be a participant, the amount involved exceeds $120,000 and any director, director nominee, executive officer, 5% or greater unitholder (or their immediate family members) had, has or will have a direct or indirect material interest. A transaction that would be covered by this policy would include, but not be limited to, any financial transaction, arrangement or relationship (including any indebtedness or guarantee of indebtedness) or any series of similar transactions, arrangements or relationships.
Under our Related Person Transactions Policy, related person transactions may be entered into or continue only if the transaction is deemed to be “fair and reasonable” to us, in accordance with the terms of our Partnership Agreement. Under our Partnership Agreement, transactions that represent a “conflict of interest” may be approved in one of three ways and, if approved in any of those ways, will be considered “fair and reasonable” to us and the holders of our common units. The three ways enumerated in our Related Person Transactions Policy for reaching this conclusion include:
(i) approval by the Conflicts Committee of the Board (the “Conflicts Committee”) under Section 7.9 of the Partnership Agreement (“Special Approval”);
(ii) approval by our Chief Executive Officer applying the criteria specified in Section 7.9 of the Partnership Agreement if the transaction is in the normal course of the Partnership’s business and is (a) on terms no less favorable to the Partnership than those generally being provided to or available from unrelated third parties or (b) fair to the Partnership, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to the Partnership); and
(iii) approval by an independent committee of the Board (either the Audit Committee or a Special Committee) applying the criteria in Section 7.9 of the Partnership Agreement.
Once a transaction is approved in any of these ways, it is “fair and reasonable” and accordingly deemed (i) approved by all of our partners and (ii) not to be a breach of any fiduciary duties of general partner.
Our managing general partner determines in its discretion which method of approval is required depending on the circumstances.
Under our Partnership Agreement, when determining whether a related person transaction is “fair and reasonable,” if our managing general partner elects to adopt a resolution or a course of action that has not received Special Approval, then our managing general partner may consider:
•
the relative interests of any party to such conflict, agreement, transaction or situation and the benefits and burdens relating to such interest;
•
any customary or accepted industry practices and any customary or historical dealings with a particular person;
•
any applicable generally accepted accounting practices or principles; and
•
such additional factors as the managing general partner or conflicts committee determines in its sole discretion to be relevant, reasonable or appropriate under the circumstances.
A related person transaction that is approved by the conflicts committee is, as discussed in greater detail above, conclusively deemed to be fair and reasonable to us. Under our Partnership Agreement, the material facts known to our managing general partner or any of our affiliates regarding the transaction must be disclosed to the conflicts committee at the time the committee gives its approval. When approving a related party transaction, the conflicts committee considers all factors it considers relevant, reasonable or appropriate under the circumstances, including the relative interests of any party to the transaction, customary industry practices and generally accepted accounting principles.
Under our Partnership Agreement, in the absence of bad faith by the managing general partner, the resolution, action or terms so made, taken or provided by the managing general partner with respect to approval of the related party transaction will not constitute a breach of the Partnership Agreement or any standard of fiduciary duty.
Under our Related Person Transactions Policy, as well as under our Partnership Agreement, there is no obligation to take any particular conflict to the conflicts committee-empanelling that committee is entirely at the discretion of the managing general partner. In many ways, the decision to engage the conflicts committee can be analogized to the kinds of transactions for which a Delaware corporation might establish a special committee of independent directors. The managing general partner considers the specific facts and circumstances involved. Relevant facts would include:
•
the nature and size of the transaction (e.g., transaction with a controlling unitholder, magnitude of consideration to be paid or received, impact of proposed transaction on the general partner and holders of common units);
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the related person’s interest in the transaction;
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whether the transaction is on terms no less favorable than terms generally available to an unaffiliated third-party under the same or similar circumstances;
•
if applicable, the availability of other sources of comparable services or products; and
•
the financial costs involved, including costs for separate financial, legal and possibly other advisors at our expense.
When determining whether a related person transaction is in the normal course of our business and is (a) on terms no less favorable to us than those generally being provided to or available from unrelated third parties or (b) fair to us, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to us), the managing general partner considers any facts and circumstances that it deems to be relevant, including:
•
the terms of the transaction, including the aggregate value;
•
the business purpose of the transaction;
•
the relative interests of any party to such conflict, agreement, transaction or situation and the benefits and burdens relating to such interest;
•
whether the terms of the transaction are comparable to the terms that would exist in a similar transaction with an unaffiliated third party;
•
any customary or accepted industry practices;
•
any applicable generally accepted accounting practices or principles; and
•
such additional factors as the managing general partner or the conflicts committee determines in its sole discretion to be relevant, reasonable or appropriate under the circumstances.
Distributions and Payments to the Managing General Partner and the Non-managing General Partner
Distributions and payments are made by us to our managing general partner and its affiliates in connection with our ongoing operation. These distributions and payments were determined by and among affiliated entities and are not the result of arm’s length negotiations.
Cash distributions will generally be made approximately 99% to the limited partner unitholders, including affiliates of the managing general partner as holders of common units, and approximately 1% to the non-managing general partner. In addition, when distributions exceed certain target distribution levels, Inergy Holdings is entitled to receive increasing percentages of the distributions (incentive distribution rights), up to 48% of the distributions above the highest target level.
During fiscal 2009, Inergy Holdings received $48.1 million in distributions related to its 0.8% general partner interest and incentive distribution rights and $12.3 million related to its 7.8% limited partner interest.
Our managing general partner and its affiliates will not receive any management fee or other compensation for the management of us. Our managing general partner and its affiliates will be reimbursed, however, for direct and indirect expenses incurred on our behalf. The expense reimbursement to our managing general partner and its affiliates was $3.1 million for the fiscal year ended September 30, 2009, and $3.5 million for the fiscal years ended September 30, 2008 and 2007, with the reimbursement related primarily to personnel costs.
If our managing general partner withdraws in violation of the partnership agreement or is removed for cause, a successor general partner has the option to buy the general partner interests and incentive distribution rights from our non-managing general partner for a cash price equal to fair market value. If our managing general partner withdraws or is removed under any other circumstances, our non-managing general partner has the option to require the successor general partner to buy its general partner interests and incentive distribution rights for a cash price equal to fair market value.
If either of these options is not exercised, the general partner interests and incentive distribution rights will automatically convert into common units equal to the fair market value of those interests. In addition, we will be required to pay the departing general partner for expense reimbursements.
Upon our liquidation, the partners, including our non-managing general partner, will be entitled to receive liquidating distributions according to their particular capital account balances.
Rights of our Managing General Partner and our Non-managing General Partner
Inergy Holdings owns an aggregate 8.6% interest in us inclusive of ownership of all of our non-managing general partner and our managing general partner. Our managing general partner manages our operations and activities.
Item 14.
Item 14. Principal Accountant Fees and Services.
The following table presents fees billed for professional audit services rendered by Ernst & Young LLP for the audit of our annual financial statements and for other services for the years ended September 30, 2009 and 2008 (in millions):
(1) Audit fees consist of assurance and related services that are reasonably related to the performance of the audit or review of our financial statements. This category includes fees related to the review of our quarterly and other SEC filings and services related to internal control assessments.
(2) Audit-related fees consist of due diligence fees associated with acquisition transactions, financial accounting and reporting consultations and benefit plan audits.
The audit committee of our general partner reviewed and approved all audit and non-audit services provided to us by Ernst & Young during fiscal year 2009. For information regarding the audit committee’s pre-approval policies and procedures related to the engagement by us of an independent accountant, see our audit committee charter on our website at www.inergypropane.com.
PART IV
Item 15.
Item 15. Exhibits and Financial Statement Schedules.
(a) Exhibits, Financial Statements and Financial Statement Schedules:
1. Financial Statements:
See Index Page for Financial Statements located on page 94.
2. Financial Statement Schedule:
Schedule II: Valuation and Qualifying Accounts located on page 134.
Other financial statement schedules have been omitted because they either are not required, are immaterial or are not applicable or because equivalent information has been included in the financial statements, the notes thereto or elsewhere herein.
3. Exhibits:
* Previously filed
** Filed herewith
*** Management contracts or compensatory plans or arrangements required to be identified by Item 15(a).
(b) Exhibits.
See exhibits identified above under Item 15(a)3.
(c) Financial Statement Schedules.
See financial statement schedules identified above under Item 15(a)2.
Inergy, L.P. and Subsidiaries
Consolidated Financial Statements
September 30, 2009 and 2008 and each of the
Three Years in the Period Ended
September 30, 2009
Contents
Report of Independent Registered Public Accounting Firm
Report of Independent Registered Public Accounting Firm on Internal Controls
Audited Consolidated Financial Statements:
Consolidated Balance Sheets
Consolidated Statements of Operations
Consolidated Statements of Partners’ Capital
Consolidated Statements of Cash Flows
Notes to Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm
The Board of Directors and Unitholders of Inergy, L.P.
We have audited the accompanying consolidated balance sheets of Inergy, L.P. and Subsidiaries (the Company) as of September 30, 2009 and 2008, and the related consolidated statements of operations, partners’ capital and cash flows for each of the three years in the period ended September 30, 2009. Our audits also included the financial statement schedule listed in the Index at Item 15(a). These financial statements and schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Inergy, L.P. and Subsidiaries at September 30, 2009 and 2008, and the consolidated results of their operations and their cash flows for each of the three years in the period ended September 30, 2009, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Inergy, L.P. and Subsidiaries’ internal control over financial reporting as of September 30, 2009, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commissions and our report dated November 30, 2009 expressed an unqualified opinion thereon.
/s/ ERNST & YOUNG LLP
Kansas City, Missouri
November 30, 2009
Report of Independent Registered Public Accounting Firm
The Board of Directors and Unitholders of Inergy, L.P.
We have audited Inergy, L.P. and Subsidiaries’ internal control over financial reporting as of September 30, 2009, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Inergy, L.P. and Subsidiaries’ management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate.
As indicated in the accompanying Management’s Report on Internal Control over Financial Reporting, management’s assessment of and conclusion on the effectiveness of internal control over financial reporting did not include the internal controls of its fiscal 2009 acquisitions, which are included in the 2009 consolidated financial statements of Inergy, L.P. and Subsidiaries and constituted $14.4 million of total assets as of September 30, 2009, and $10.5 million of revenues for the year then ended. Our audit of internal control over financial reporting of Inergy, L.P. and Subsidiaries also did not include an evaluation of the internal control over financial reporting of its fiscal 2009 acquisitions.
In our opinion, Inergy, L.P. and Subsidiaries maintained, in all material respects, effective internal control over financial reporting as of September 30, 2009, based on the COSO criteria.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the 2009 consolidated financial statements of Inergy, L.P. and Subsidiaries and our report dated November 30, 2009 expressed an unqualified opinion thereon.
/s/ ERNST & YOUNG LLP
Kansas City, Missouri
November 30, 2009
Inergy, L.P. and Subsidiaries
Consolidated Balance Sheets
(in millions, except unit information)
The accompanying notes are an integral part of these consolidated financial statements.
Inergy, L.P. and Subsidiaries
Consolidated Statements of Operations
(in millions, except per unit data)
The accompanying notes are an integral part of these consolidated financial statements.
Inergy, L.P. and Subsidiaries
Consolidated Statements of Partners’ Capital
(in millions)
The accompanying notes are an integral part of these consolidated financial statements.
Inergy, L.P. and Subsidiaries
Consolidated Statements of Cash Flows
(in millions)
The accompanying notes are an integral part of these consolidated financial statements.
Inergy, L.P. and Subsidiaries
Consolidated Statements of Cash Flows (continued)
(in millions)
The accompanying notes are an integral part of these consolidated financial statements.
Inergy, L.P. and Subsidiaries
Notes to Consolidated Financial Statements
Note 1. Partnership Organization and Formation
Organization
The consolidated financial statements of Inergy, L.P. (“Inergy”, “The Partnership” or the “Company”) include the accounts of Inergy and its subsidiaries, including Inergy Propane, LLC (“Inergy Propane”), Inergy Midstream, LLC (collectively, the “Operating Companies”) and Inergy Finance Corp.
Inergy Partners, LLC (“Inergy Partners” or the “Non-Managing General Partner”), a subsidiary of Inergy Holdings, L.P. (“Holdings”), owns the Non-Managing General Partner interest in the Company. Inergy GP, LLC (“Inergy GP” or the “Managing General Partner”), a wholly-owned subsidiary of Holdings, has sole responsibility for conducting the Company’s business and managing its operations. Holdings is a holding company whose principal business, through its subsidiaries, is its management of and ownership in the Company. Holdings also directly owns the incentive distribution rights (“IDR”) with respect to Inergy.
Pursuant to a partnership agreement, Inergy GP or any of its affiliates is entitled to reimbursement for all direct and indirect expenses incurred or payments made on behalf of Inergy and all other necessary or appropriate expenses allocable to Inergy or otherwise reasonably incurred by Inergy GP in connection with operating the Company’s business. These costs, which totaled $3.1 million for the fiscal year ended September 30, 2009, and $3.5 million for each of the fiscal years ended September 30, 2008 and 2007, include compensation, bonuses and benefits paid to officers and employees of Inergy GP and its affiliates.
As of September 30, 2009, Holdings owns an aggregate 8.6% interest in Inergy, L.P., inclusive of ownership of all of the non-managing general partner and the managing general partner. This ownership is comprised of a 0.8% general partnership interest and 7.8% limited partnership interest.
Nature of Operations
Inergy is engaged primarily in the sale, distribution, storage, marketing, trading, processing and fractionation of propane, natural gas and other natural gas liquids. The retail market is seasonal because propane is used primarily for heating in residential and commercial buildings, as well as for agricultural purposes. Inergy’s operations are primarily concentrated in the Midwest, Northeast and South regions of the United States.
Principles of Consolidation
All significant intercompany balances and transactions have been eliminated in consolidation.
Reclassifications
The consolidated balance sheet for the year ended September 30, 2008 reflects an increase to both accounts receivable and accounts payable of $9.8 million. Certain other prior period amounts have been reclassified to conform to the current period presentation. These reclassifications had no effect on net income.
Note 2. Summary of Significant Accounting Policies
Financial Instruments and Price Risk Management
Inergy utilizes certain derivative financial instruments to (i) manage its exposure to commodity price risk, specifically, the related change in the fair value of inventories, as well as the variability of cash flows related to forecasted transactions; (ii) ensure adequate physical supply of commodity will be available; and (iii) manage its
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Notes to Consolidated Financial Statements-(Continued)
exposure to interest rate risk associated with fixed rate borrowings. Inergy records all derivative instruments on the balance sheet as either assets or liabilities measured at fair value. Changes in the fair value of these derivative financial instruments are recorded either through current earnings or as other comprehensive income, depending on the type of transaction.
Inergy is party to certain commodity derivative financial instruments that are designated as hedges of selected inventory positions, and qualify as fair value hedges. Inergy is also party to certain interest rate swap agreements designed to manage interest rate risk exposure. Inergy’s overall objective for entering into fair value hedges is to manage its exposure to fluctuations in commodity prices and changes in the fair market value of its inventories and fixed rate borrowings. These derivatives are recorded at fair value on the balance sheet as price risk management assets or liabilities and the related change in fair value is recorded to earnings in the current period as cost of product sold. Any ineffective portion of the fair value hedges is recognized as cost of product sold in the current period. Inergy recognized a $0.2 million net gain in the year ended September 30, 2009, related to the ineffective portion of its fair value hedging instruments. In addition, for the year ended September 30, 2009, Inergy recognized a net loss of $0.1 million related to the portion of fair value hedging instruments that it excluded from its assessment of hedge effectiveness.
Inergy also enters into derivative financial instruments that qualify as cash flow hedges, which hedge the exposure of variability in expected future cash flows predominantly attributable to forecasted purchases to supply fixed price sale contracts. These derivatives are recorded on the balance sheet at fair value as price risk management assets or liabilities. The effective portion of the gain or loss on these cash flow hedges is recorded in other comprehensive income in partner’s capital and reclassified into earnings in the same period in which the hedge transaction affects earnings. Any ineffective portion of the gain or loss is recognized as cost of product sold in the current period. Accumulated other comprehensive income (loss) was $11.0 million and $(25.3) million at September 30, 2009 and 2008, respectively. Approximately $11.7 million is expected to be reclassified to earnings from other comprehensive income over the next twelve months.
Inergy’s policy is to offset fair value amounts of derivative instruments and cash collateral paid or received with the same counterparty under a master netting arrangement.
The cash flow impact of derivative financial instruments is reflected as cash flows from operating activities in the consolidated statements of cash flows.
Revenue Recognition
Sales of propane, other liquids and salt are recognized at the time product is shipped or delivered to the customer depending on the sales terms. Gas processing and fractionation fees are recognized upon delivery of the product. Revenue from the sale of propane appliances and equipment is recognized at the later of the time of sale or installation. Revenue from repairs and maintenance is recognized upon completion of the service. Revenue from storage contracts is recognized during the period in which storage services are provided.
Expense Classification
Cost of product sold consists of tangible products sold including all propane and other natural gas liquids, salt and all propane related appliances. Operating and administrative expenses consist of all expenses incurred by Inergy other than those described above in cost of product sold and depreciation and amortization. Certain of Inergy’s operating and administrative expenses and depreciation and amortization are incurred in the distribution of the product sales and storage sale but are not included in cost of product sold. These amounts were $134.6 million, $131.0 million and $114.7 million during the years ended September 30, 2009, 2008 and 2007, respectively.
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Notes to Consolidated Financial Statements-(Continued)
Credit Risk and Concentrations
Inergy is both a retail and wholesale supplier of propane gas. Inergy generally extends unsecured credit to its wholesale customers in the United States and Canada. In addition, Inergy collects margin payments from its customers to mitigate risk. Credit is generally extended to retail customers through delivery into Company and customer owned propane gas storage tanks. Provisions for doubtful accounts receivable are based on specific identification and historical collection results and have generally been within management’s expectations.
Inergy enters into netting agreements with certain wholesale customers to mitigate the Company’s credit risk. Realized gains and losses reflected in the Company’s receivables and payables are reflected at a net balance to the extent a netting agreement is in place and the Company intends to settle on a net basis. Unrealized gains and losses reflected in the Company’s assets and liabilities from price risk management activities are reflected on a net basis to the extent a netting agreement is in place.
Two suppliers, BP Amoco Corp. (12%) and Sunoco, Inc. (11%), accounted for 23% of propane purchases during the past fiscal year. The Company believes that contracts with these suppliers will enable Inergy to purchase most of its supply needs at market prices and ensure adequate supply. No other single supplier accounted for more than 10% of propane purchases in the current year.
No single customer represents 10% or more of consolidated revenues. In addition, nearly all of Inergy’s revenues are derived from sources within the United States, and all of its long-lived assets are located in the United States.
Use of Estimates
The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amount of assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the year. Actual results could differ from those estimates.
Inventories
Inventories for retail operations, which mainly consist of propane gas and other liquids, are stated at the lower of cost or market and are computed using the average cost method. Wholesale propane and other liquids inventories are designated under a fair value hedge program and are consequently marked to market. Propane and other liquids inventories being hedged and carried at market value at September 30, 2009 and 2008, amount to $53.7 million and $36.4 million, respectively. Inventories for midstream operations are stated at the lower of cost or market and are computed predominantly using the average cost method.
Shipping and Handling Costs
Shipping and handling costs are recorded as part of cost of product sold at the time product is shipped or delivered to the customer except as discussed in “Expense Classification.”
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Notes to Consolidated Financial Statements-(Continued)
Property, Plant and Equipment
Property, plant and equipment are stated at cost. Depreciation is computed by the straight-line method over the estimated useful lives of the assets, as follows:
Salt deposits are depleted on a unit of production method.
Inergy reviews its long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If such events or changes in circumstances are present, a loss is recognized if the carrying value of the asset is in excess of the sum of the undiscounted cash flows expected to result from the use of the asset and its eventual disposition. An impairment loss is measured as the amount by which the carrying amount of the asset exceeds the fair value of the asset. Inergy has determined that no impairment exists as of September 30, 2009. See Note 4 for a discussion of assets held for sale at September 30, 2009 and 2008.
Identifiable Intangible Assets
The Company has recorded certain identifiable intangible assets, including customer accounts, covenants not to compete, trademarks, deferred financing costs and deferred acquisition costs. Customer accounts, covenants not to compete and trademarks have arisen from the various acquisitions by Inergy. Deferred financing costs represent financing costs incurred in obtaining financing and are being amortized over the term of the related debt. Deferred acquisition costs represent costs incurred on acquisitions that Inergy is actively pursuing. Additionally, an acquired intangible asset should be separately recognized if the benefit of the intangible asset is obtained through contractual or other legal rights, or if the intangible asset can be sold, transferred, licensed, rented or exchanged, regardless of the acquirer’s intent to do so.
Certain intangible assets are amortized on a straight-line basis over their estimated economic lives, as follows:
Trademarks have been assigned an indefinite economic life and are not being amortized, but are subject to an annual impairment evaluation.
Estimated amortization, including amortization of deferred financing costs reported as interest expense, for the next five years ending September 30, is as follows (in millions):
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Notes to Consolidated Financial Statements-(Continued)
Goodwill
Goodwill is recognized for various acquisitions by Inergy as the excess of the cost of the acquisitions over the fair value of the related net assets at the date of acquisition. Goodwill is subject to at least an annual assessment for impairment by applying a fair-value-based test.
In connection with the goodwill impairment evaluation, the Company identified five reporting units. The carrying value of each reporting unit is determined by assigning the assets and liabilities, including the existing goodwill and intangible assets, to those reporting units as of the date of the evaluation on a specific identification basis. To the extent a reporting unit’s carrying value exceeds its fair value, an indication exists that the reporting unit’s goodwill may be impaired and the second step of the impairment test must be performed. In the second step, the implied fair value of the goodwill is determined by allocating the fair value to all of its assets (recognized and unrecognized) and liabilities to its carrying amount.
Inergy has completed the impairment test for each of its reporting units and determined that no impairment existed as of September 30, 2009.
Income Taxes
Inergy is a publicly-traded master limited partnership. Partnerships are generally not subject to Federal income tax, although publicly-traded partnerships are treated as corporations for Federal income tax purposes and therefore subject to federal income tax, unless the partnership generates at least 90% of its gross income from qualifying sources. If the qualifying income requirement is satisfied, the publicly-traded partnership will be treated as a partnership for Federal income tax purposes. Inergy Sales and Service, Inc. (“Services”), a subsidiary of Inergy, does not generate at least 90% of its gross income from qualifying sources, and as such, federal and state income taxes are provided on the taxable income of Services. The remaining Inergy subsidiaries generate at least 90% of gross income from qualifying sources. As a result, except for the operations of Services, Inergy’s net earnings for Federal income tax purposes are allocated to the individual partners for inclusion in their tax returns. Legislation in certain states allows for taxation of partnerships. As such, certain state taxes for Inergy have also been included in the accompanying financial statements as income taxes due to the nature of the tax in those particular states. Net earnings for financial statement purposes may differ significantly from taxable income reportable to unitholders as a result of differences between the tax basis and the financial reporting basis of assets and liabilities and the taxable income allocation requirements under the partnership agreement.
The provision for income tax was $0.7 million for the years ended September 30, 2009, 2008 and 2007. At September 30, 2009, the Company had cumulative temporary differences between the book and tax basis of Services of $17.2 million, comprised primarily of a net operating loss carryforward. At September 30, 2009 and 2008, this resulted in a deferred tax asset of $6.5 million and $5.9 million, respectively, which the Company has fully reserved with a valuation allowance of $6.5 million and $5.9 million, respectively. In order to fully realize the deferred tax asset Services will need to generate future taxable income. A valuation allowance is provided when it is more likely than not that some or all of the deferred tax asset will not be realized. Based on the level of current taxable income and projections of future taxable income of Services over the periods in which the deferred tax asset would be deductible, the Company is providing a full valuation allowance that it is more likely than not that that it will not realize the full benefit of the deferred tax asset.
Sales Tax
Inergy accounts for the collection and remittance of all taxes on a net tax basis. As a result, these amounts are not reflected in the consolidated statements of operations.
Inergy, L.P. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
Customer Deposits
Customer deposits primarily represent cash received by Inergy from wholesale and retail customers for propane purchased under contract that will be delivered at a future date.
Cash and Cash Equivalents
Inergy defines cash equivalents as all highly liquid investments with maturities of three months or less when purchased.
Computer Software Costs
Inergy includes costs associated with the acquisition of computer software in property, plant and equipment. Inergy amortizes computer software costs on a straight-line basis over expected periods of benefit, which generally are five years.
Fair Value
Cash and cash equivalents, accounts receivable (net of reserve for bad debts) and payables are carried at cost, which approximates fair value due to their liquid and short-term nature. As of September 30, 2009, the estimated fair value of the fixed-rate Senior Notes, based on available trading information, totaled $1,041.3 million compared with the aggregate principal amount at maturity of $1,050.0 million. The Company’s credit agreement (“Credit Agreement”) consists of a $75 million revolving working capital facility (“Working Capital Facility”) and a $350 million revolving acquisition facility (“Acquisition Facility”). The carrying value of amounts outstanding under the Credit Agreement of $27.2 million at September 30, 2009, approximate fair value due primarily to the floating interest rate associated with the Credit Agreement.
Comprehensive Income (Loss)
Comprehensive income includes net income and other comprehensive income, which is solely comprised of unrealized gains and losses on derivative financial instruments. Accumulated other comprehensive income (loss) consists of the following (in millions):
(a) Other comprehensive income (loss) includes a reclassification of $(24.5) million and $9.8 million to net income during the years ended September 30, 2009 and 2008, respectively.
Inergy records the effective portion of the unrealized gains and losses on its derivative financial instruments that qualify as cash flow hedges as other comprehensive income.
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Notes to Consolidated Financial Statements-(Continued)
Income Per Unit
The Company calculates basic net income per unit by dividing net income, after considering the Non-Managing General Partner’s interest, including priority distributions and beneficial conversion value (Note 9), by the weighted average number of limited partner units outstanding. Under this method, the calculation of net income per unit reflects an allocation of earnings to each class of units that is consistent with the partnership agreement’s treatment of the respective classes’ capital accounts. Diluted net income per limited partner unit is computed by dividing net income, after considering the Non-Managing General Partner’s interest, by the sum of weighted average number of common units and the effect of other dilutive units.
Accounting for Unit-Based Compensation
Inergy has a unit-based employee compensation plan and all share-based payments to employees, including grants of employee stock options, are recognized in the income statement based on their fair values.
The amount of compensation expense recorded by the Company during the years ended September 30, 2009, 2008 and 2007, was $3.1 million, $3.5 million and $0.7 million, respectively. The compensation expense for the years ended September 30, 2009, 2008 and 2007, includes $1.4 million, $1.1 million and $0.3 million, respectively, of unit-based compensation expense on Inergy Holdings, L.P. units.
Segment Information
There are certain accounting requirements that establish standards for reporting information about operating segments, as well as related disclosures about products and services, geographic areas and major customers. Further, they define operating segments as components of an enterprise for which separate financial information is available that is evaluated regularly by the chief operating decision maker in deciding how to allocate resources and assessing performance. In determining its reportable segments, Inergy examined the way it organizes its business internally for making operating decisions and assessing business performance. See Note 13 for disclosures related to Inergy’s propane and midstream segments.
Recently Issued Accounting Pronouncements
FASB Accounting Standards Codification Subtopic 825-10 (“825-10”), originally issued as SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities”, was issued in February 2007 to permit entities to choose to measure many financial instruments and certain other items at fair value at specified election dates. A business entity is required to report unrealized gains and losses on items for which the fair value option has been elected in earnings at each subsequent reporting date. The Company adopted 825-10 on October 1, 2008. The adoption of 825-10 did not have an impact the Company’s financial statements.
FASB Accounting Standards Codification Subtopic 820-10 (“820-10”), originally issued as SFAS No. 157, “Fair Value Measurements”, was issued in September 2006 to define fair value, establish a framework for measuring fair value according to generally accepted accounting principles and expand disclosures about fair value measurements. The Company adopted 820-10 on October 1, 2008. The adoption of 820-10 required certain additional footnote disclosures (Note 6), however, it did not have a significant impact on any amounts comprising the consolidated balance sheets, consolidated statements of operations, consolidated statements of partners’ capital or the consolidated statements of cash flows.
FASB Accounting Standards Codification Subtopic 210-20 (“210-20”), originally issued as FASB Staff Position No. FIN 39-1, “Amendment of FASB Interpretation No. 39”, was issued in April 2007 to permit companies to
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Notes to Consolidated Financial Statements-(Continued)
offset fair value amounts recognized for the right to reclaim cash collateral (a receivable), or the obligation to return cash collateral (a payable), against fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting agreement. In addition, upon the adoption, companies are permitted to change their accounting policy to offset or not offset fair value amounts recognized for derivative instruments under master netting arrangements. The Company adopted 210-20 on October 1, 2008 and elected to change its accounting policy for derivative instruments executed with the same counterparty under a master netting agreement. The Company’s policy is to offset fair value amounts of derivative instruments and cash collateral paid or received with the same counterparty under a master netting arrangement. This change in accounting policy has been presented retroactively. The adoption of 210-20 had the following impact on the September 30, 2008 consolidated balance sheet (in millions):
FASB Accounting Standards Codification Subtopic 815-10 (“815-10”), originally issued as SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities-an amendment of FASB Statement No. 133” was issued in March 2008 and applies to all derivative instruments and related hedged items. 815-10 requires entities to provide greater transparency about (a) how and why an entity uses derivative instruments, (b) how derivative instruments and related hedged items are accounted for, and (c) how derivative instruments and related hedged items affect an entity’s financial position, results of operations and cash flows. The Company adopted 815-10 on March 31, 2009. The adoption of 815-10 required certain additional disclosures (Note 5), however, it did not impact any amounts comprising the consolidated balance sheets, consolidated statements of operations, consolidated statements of partners’ capital or the consolidated statements of cash flows.
FASB Accounting Standards Codification Subtopic 805-10 (“805-10”), originally issued as SFAS No. 141 (revised 2007), “Business Combinations”, was issued in December 2007 and establishes principles and requirements for how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, any non- controlling interest in the acquiree and the goodwill acquired. 805-10 also establishes disclosure requirements designed to enable users to evaluate the nature and financial effects of the business combination. 805-10 is required to be adopted by the Company for business combinations for which the acquisition date is on or after October 1, 2009.
FASB Accounting Standards Codification Subtopic 810-10 (“810-10”), originally issued as SFAS No. 160, “Non-controlling Interests in Consolidated Financial Statements-an amendment of ARB No. 51”, was issued in December 2007 and requires that accounting and reporting for minority interests will be recharacterized as non-controlling interests and classified as a component of equity. 810-10 also establishes reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the non-controlling owners. 810-10 applies to all entities that prepare consolidated financial statements, except not-for-profit organizations, but will affect only those entities that have an outstanding non-controlling interest in one or more subsidiaries or that deconsolidate a subsidiary. 810-10 is required to be adopted by the Company for the fiscal quarter ended December 31, 2009. The Company is evaluating the potential financial statement impact of 810-10 to its consolidated financial statements.
FASB Accounting Standards Codification Subtopic 260-10 (“260-10”), originally issued as EITF Issue No. 07-4, “Application of the Two-Class Method under FASB Statement No. 128 to Master Limited Partnerships”, was
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Notes to Consolidated Financial Statements-(Continued)
ratified in March 2008 and applies to Master Limited Partnerships (“MLP”) that are required to make incentive distributions when certain thresholds have been met regardless of whether the IDR is a separate limited partner (“LP”) interest or embedded in the general partner interest. 260-10 addresses how the current period earnings of an MLP should be allocated to the general partner, LP’s and, when applicable, IDR’s. 260-10 is required to be adopted by the Company for the fiscal quarter ended December 31, 2009. The Company evaluating the potential financial statement impact of 260-10 to its consolidated financial statements.
FASB Accounting Standards Codification Subtopic 260-10 (“260-10”), originally issued as FSP EITF Issue No. 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions are Participating Securities”, was ratified in June 2008 and applies to the calculation of earnings per share (“EPS”) under FASB Accounting Standards Codification Subtopic 260-10 (“260-10”), originally issued as SFAS 128, “Earnings Per Share”, for share-based payment awards with rights to dividends or dividend equivalents. 260-10 states that unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents are participating securities and shall be included in the computation of EPS pursuant to the two-class method. 260-10 is required to be adopted by the Company for the fiscal quarter ended December 31, 2009. The Company is evaluating the potential financial statement impact of 260-10 to its consolidated financial statements.
In May 2009, the FASB issued FASB Accounting Standards Codification Subtopic 855-10 (“855-10”), originally issued as SFAS No. 165, “Subsequent Events”. 855-10 establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. The Company adopted 855-10 on June 30, 2009. The adoption of 855-10 required the Company to disclose the date through which subsequent events have been evaluated and the basis for that date (Note 15). The adoption of 855-10 did not impact any amounts comprising the consolidated balance sheets, consolidated statements of operations, consolidated statements of partners’ capital or the consolidated statements of cash flows.
In June 2009, the FASB issued FASB Accounting Standards Codification Subtopic 105-10 (“105-10”), originally issued as SFAS 168, “The FASB Accounting Standards Codification and Hierarchy of Generally Accepted Accounting Principles”, to supersede FASB Statement No. 162, “The Hierarchy of Generally Accepted Accounting Principles”, and reorganize the standards applicable to financial statements of nongovernmental entities that are presented in conformity with GAAP. The purpose of the codification was to provide a single source of authoritative nongovernmental GAAP literature. The codification was not intended to create new accounting standards or guidance. While the codification includes portions of SEC content related to matters within the basic financial statements for user convenience, it does not contain all SEC guidance on accounting topics, and does not replace any SEC rules or regulations. The Company adopted 105-10 on September 30, 2009. The adoption of 105-10 did not impact any amounts comprising the consolidated balance sheets, consolidated statements of operations, consolidated statements of partners’ capital or the consolidated statements of cash flows.
Note 3. Acquisitions
During the fiscal year ended September 30, 2009, Inergy made three retail acquisitions, including the Blu-Gas group of companies (“Blu-Gas”), Newton’s Gas Service, Inc. (“Newton’s Gas”) and F.G. White Company, Inc. (“F.G. White”). The aggregate purchase price of these acquisitions, net of cash acquired, was $11.8 million. This amount does not include $0.3 million paid in fiscal 2009 for acquisitions that closed in the previous year. The purchase price allocation for these acquisitions has been prepared on a preliminary basis pending final asset valuation and asset rationalization, and changes are expected when additional information becomes available. The Company finalized its purchase price allocation of the 2008 US Salt acquisition during 2009. This allocation resulted in an increase to property, plant and equipment of $69.4 million and an increase to intangible assets of
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Notes to Consolidated Financial Statements-(Continued)
$3.6 million, with a corresponding decrease to goodwill of $73.0 million. Other purchase accounting adjustments recorded in fiscal 2009 resulted in a net increase to goodwill of $4.3 million. Changes to reflect final asset valuation of other prior fiscal year acquisitions have been included in the Company’s consolidated financial statements but are not material.
U.S. GAAP requires that for any material business combination or disposition of assets, pro-forma information must be disclosed. The fiscal 2009 acquisitions were not considered material.
The operating results for these acquisitions are included in the consolidated results of operations from the dates of acquisition through September 30, 2009.
As a result of the fiscal 2009 acquisitions, the Company acquired $0.7 million of goodwill and $9.5 million of intangible assets, consisting of the following (in millions):
The amounts provided above relate solely to acquisitions that closed in fiscal 2009. The amounts disclosed in the supplemental schedule of noncash investing and financing activities in the consolidated statement of cash flows relate to amounts recorded during 2009, which related to acquisitions that closed in fiscal 2009 and 2008.
The weighted average amortization period of amortizable intangible assets acquired during the year ended September 30, 2009, is approximately thirteen years.
Note 4. Certain Balance Sheet Information
Inventories
Inventories consist of the following at September 30, 2009 and 2008, respectively (in millions):
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Notes to Consolidated Financial Statements-(Continued)
Property, Plant and Equipment
Property, plant and equipment consists of the following at September 30, 2009 and 2008, respectively (in millions):
Depreciation expense totaled $88.6 million, $73.7 million and $59.7 million for the years ended September 30, 2009, 2008 and 2007, respectively. Depletion expense totaled $0.2 million for the year ended September 30, 2009.
The tanks and plant equipment balances above include tanks owned by the Company that reside at customer locations. The leases associated with these tanks are accounted for as operating leases. These tanks have a value of $424.0 million with an associated accumulated depreciation balance of $89.3 million at September 30, 2009.
At September 30, 2009 and 2008, the Company capitalized interest of $14.8 million and $5.5 million, respectively, related to certain midstream asset expansion projects.
The property, plant and equipment balances above at September 30, 2009 and 2008, include $2.0 million and $4.5 million, respectively, of propane operations assets deemed held for sale. These assets were identified primarily as a result of losses due to disconnecting customer installations of unprofitable accounts due to low margins, poor payment history or low volume usage. As a result, the carrying value of these assets was reduced to their estimated recoverable value less anticipated disposition costs, resulting in losses of $4.9 million and $11.5 million for the years ended September 30, 2009 and 2008, respectively. The $4.9 million and $11.5 million charges are included as components of operating income as losses on disposal of assets. When aggregated with other realized losses, such amounts totaled $5.2 million and $11.5 million, respectively.
Intangible Assets
Intangible assets consist of the following at September 30, 2009 and 2008, respectively (in millions):
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Notes to Consolidated Financial Statements-(Continued)
Amortization and interest expense associated with the above described intangible assets at September 30, 2009, 2008 and 2007, amounted to $30.3 million, $26.8 million and $26.1 million, respectively.
Note 5. Risk Management
The Company is exposed to certain market risks related to its ongoing business operations. These risks include exposure to changing commodity prices as well as fluctuations in interest rates. The Company utilizes derivative instruments to manage its exposure to fluctuations in commodity prices, which is discussed more fully below. The Company also utilizes derivative instruments to manage its exposure to fluctuations in interest rates, which is discussed more fully in Note 7. Additional information related to derivatives is provided in Note 2 and Note 6.
Commodity Derivative Instruments and Price Risk Management
Risk Management Activities
Inergy sells propane and other commodities to energy related businesses and may use a variety of financial and other instruments including forward contracts involving physical delivery of propane. Inergy will enter into offsetting positions to hedge against the exposure its customer contracts create. Inergy does not designate these instruments as hedging instruments. These instruments are marked to market with the changes in the market value reflected in cost of product sold. Inergy attempts to balance its contractual portfolio in terms of notional amounts and timing of performance and delivery obligations. This balance in the contractual portfolio significantly reduces the volatility in cost of product sold related to these instruments. However, immaterial net unbalanced positions can exist or are established based on assessment of anticipated short-term needs or market conditions.
Cash Flow Hedging Activity
Inergy sells propane and heating oil to retail customers at fixed prices. Inergy will enter into derivative instruments to hedge a significant portion of its exposure to fluctuations in commodity prices as a result of selling the fixed price contracts. These instruments are identified and qualify to be treated as cash flow hedges. This accounting treatment requires the effective portion of the gain or loss on the derivative to be reported as a component of other comprehensive income and reclassified into earnings in the same period or periods during which the hedged transaction affects earnings. Gains and losses on the derivative representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in current earnings.
Fair Value Hedging Activity
Inergy will enter into derivative instruments to hedge its exposure to fluctuating commodity prices that results from maintaining its wholesale propane and other liquids inventory. Those instruments qualify to be treated as fair value hedges. This accounting treatment requires the fair value changes in both the derivative instruments and the hedged inventory to be recorded in cost of product sold.
Commodity inventory held in bulk storage facilities is not expected to be sold in the immediate future and is hedged in order to minimize exposure to fluctuations in commodity prices. Commodity inventory held at retail locations is not hedged as this inventory is expected to be sold in the immediate future and is therefore not exposed to fluctuations in commodity prices over an extended period of time.
Inergy, L.P. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
Commodity Price and Credit Risk
Notional Amounts and Terms
The notional amounts and terms of the Company’s derivative financial instruments include the following at September 30, 2009, and September 30, 2008 (in millions):
Notional amounts reflect the volume of transactions, but do not represent the amounts exchanged by the parties to the financial instruments. Accordingly, notional amounts do not reflect the Company’s monetary exposure to market or credit risks.
Fair Value of Derivative Instruments
The following tables detail the amount and location on the Company’s consolidated balance sheets and consolidated statements of operations related to all of its derivatives (in millions):
(a) The gain (loss) on both the derivative and the item being hedged are located in cost of product sold in the consolidated statements of operations.
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Notes to Consolidated Financial Statements-(Continued)
(b) The gain (loss) on both the derivative and the item being hedged are located in interest expense in the consolidated statements of operations.
(c) The gain (loss) on the amount reclassified from OCI into income, the ineffective portion and the amount excluded from effectiveness testing are included in cost of product sold.
(d) The gain (loss) is recognized in cost of product sold.
The following table summarizes the change in the unrealized fair value of energy derivative contracts related to risk management activities for the years ended September 30, 2009 and 2008, where settlement has not yet occurred (in millions):
All contracts subject to price risk had a maturity of twenty-one months or less, however, the majority of contracts expire within twelve months.
Credit Risk
Inherent in the Company’s contractual portfolio are certain credit risks. Credit risk is the risk of loss from nonperformance by suppliers, customers or financial counterparties to a contract. Inergy takes an active role in managing credit risk and has established control procedures, which are reviewed on an ongoing basis. The Company attempts to minimize credit risk exposure through credit policies and periodic monitoring procedures as well as through customer deposits, letters of credit and entering into netting agreements that allow for offsetting counterparty receivable and payable balances for certain financial transactions, as deemed appropriate. The counterparties associated with assets from price risk management activities as of September 30, 2009 and 2008, were propane retailers, resellers, energy marketers and dealers.
Certain of the Company’s derivative instruments have credit limits that require the Company to post collateral. The amount of collateral required to be posted is a function of the net liability position of the derivative as well as the Company’s established credit limit with the respective counterparty. If the Company’s credit rating were to change, the counterparties could require the Company to post additional collateral. The amount of additional collateral that would be required to be posted would vary depending on the extent of change in the Company’s credit rating as well as the requirements of the individual counterparty. The aggregate fair value of all commodity derivative instruments with credit-risk-related contingent features that are in a liability position on September 30, 2009, is $17.3 million for which the Company has posted collateral of $5.4 million in the normal course of business. The Company has received collateral of $9.6 million in the normal course of business on contracts with a gross value of $60.6 million. All collateral amounts have been netted against the asset or liability with the respective counterparty.
Note 6. Fair Value Measurements
FASB Accounting Standards Codification Subtopic 820-10 (“820-10”) establishes a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value. The hierarchy gives the highest priority to
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Notes to Consolidated Financial Statements-(Continued)
unadjusted quoted prices in active markets for identical assets or liabilities (level 1 measurement) and the lowest priority to unobservable inputs (level 3 measurement). The three levels of the fair value hierarchy are as follows:
•
Level 1-Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 primarily consists of financial instruments such as exchange-traded derivatives, listed equities and US government treasury securities.
•
Level 2-Pricing inputs are other than quoted prices in active markets included in level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange-traded derivatives such as over the counter (“OTC”) forwards, options and physical exchanges.
•
Level 3-Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value.
As of September 30, 2009, the Company held certain assets and liabilities that are required to be measured at fair value on a recurring basis. These included the Company’s derivative instruments related to propane, heating oil, crude oil, natural gas, natural gas liquids and interest rates as well as the portion of inventory that is hedged in a qualifying fair value hedge. The Company’s derivative instruments consist of forwards, swaps, futures, physical exchanges and options.
Certain of the Company’s derivative instruments are traded on the NYMEX. These instruments have been categorized as level 1.
The Company’s derivative instruments also include OTC contracts, which are not traded on a public exchange. The fair values of these derivative instruments are determined based on inputs that are readily available in public markets or can be derived from information available in publicly quoted markets. These instruments have been categorized as level 2.
The Company’s inventory that is the hedged item in a qualifying fair value hedge is valued based on prices quoted from observable sources and verified with broker quotes. This inventory has been categorized as level 2.
The Company’s OTC options 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. These options have been categorized as level 3.
Inergy, L.P. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
The following table sets forth by level within the fair value hierarchy the Company’s assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2009 (in millions). The assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.
(a) Amounts represent the impact of legally enforceable master netting agreements that allow the Company to settle positive and negative positions as well as cash collateral held or placed with the same counterparties.
For assets and liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3) during the period, 820-10 requires a reconciliation of the beginning and ending balances, separated for each major category of assets. The reconciliation is as follows (in millions):
Inergy, L.P. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
Note 7. Long-Term Debt
Long-term debt consisted of the following at September 30, 2009 and 2008, respectively (in millions):
Credit Agreement
The Company’s Credit Agreement consists of a $75 million revolving Working Capital Facility and a $350 million revolving Acquisition Facility. The effective amount of working capital borrowing capacity available to the Company under the two facilities is $200 million utilizing capacity under the acquisition credit facility for working capital needed during the winter heating season. The Credit Agreement is guaranteed by each of Inergy’s wholly-owned domestic subsidiaries. The Company’s obligations under this Credit Agreement are secured by liens and mortgages on the Company’s real and personal property. This Credit Agreement matures on November 10, 2010.
Inergy is required to reduce the principal outstanding on the Working Capital Facility to $10 million or less for a minimum of 30 consecutive days during the period commencing March 1 and ending September 30. As such, $10 million of the outstanding balance at September 30, 2009 and 2008, have been classified as a long-term liability in the accompanying consolidated balance sheets. At September 30, 2009, the balance outstanding under the Credit Agreement was $27.2 million, with the entire balance borrowed for working capital purposes. At September 30, 2008, the balance outstanding under the Credit Agreement was $247.0 million, including $182.0 million borrowed for acquisitions and growth capital expenditures and $65.0 million borrowed for working capital purposes. Lehman Commercial Paper, Inc. (“Lehman CP”), a subsidiary of Lehman Brothers Holdings, Inc., holds a $25 million lender commitment within Inergy’s Credit Agreement and filed for Chapter 11 Bankruptcy on October 5, 2008. Inergy does not plan for the Lehman lender commitment to be available for the remainder of the term of the Credit Agreement. The interest rates of these revolvers are based on prime rate and LIBOR plus the applicable spreads, which were between 2.0% and 3.5% at September 30, 2009, and between 4.24% and 5.46% at September 30, 2008, for all outstanding debt under the Credit Agreement. Unused borrowings under the Credit Agreement amounted to $381.1 million and $154.4 million at September 30, 2009 and 2008, respectively. Outstanding standby letters of credit under the Credit Agreement amounted to $16.7 million and $23.6 million at September 30, 2009 and 2008, respectively.
As discussed in Note 15, the Company now has a $450 million general partnership revolving credit facility for acquisitions, capital expenditures and general partnership purposes and a $75 million revolving working capital facility.
At September 30, 2009, the Company was in compliance with all of its debt covenants.
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Notes to Consolidated Financial Statements-(Continued)
Senior Unsecured Notes
2014 Senior Notes
On December 22, 2004, Inergy and its wholly-owned subsidiary, Inergy Finance Corp (“Finance Corp.” and together with Inergy, the “Issuers”) completed a private placement of $425 million in aggregate principal amount of 6.875% senior unsecured notes due 2014 (the “2014 Senior Notes”). The 2014 Senior Notes contain covenants similar to the Credit Agreement. The net proceeds were used to repay outstanding indebtedness.
The 2014 Senior Notes represent senior unsecured obligations and rank pari passu in right of payment with all the Company’s other present and future senior indebtedness. The 2014 Senior Notes are fully, unconditionally, jointly and severally guaranteed by all of Inergy’s wholly-owned current domestic subsidiaries. Also, Inergy has no independent assets or operations, and subsidiaries not guaranteeing the indenture are minor. Accordingly, condensed consolidating financial information for the parent and subsidiaries is not presented.
On October 26, 2005, Inergy completed an offer to exchange the 2014 Senior Notes for $425 million of 6.875% senior notes due 2014 (the “2014 Exchange Notes”) that are registered and do not carry transfer restrictions, registration rights and provisions for additional interest. The 2014 Exchange Notes did not provide Inergy with any additional proceeds and satisfied its obligations under the registration rights agreement.
The 2014 Senior Notes are redeemable, at Inergy’s option, in whole or in part, at any time on or after December 15, 2009, 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.
Interest Rate Swaps
Inergy is party to six interest rate swap agreements scheduled to mature in December 2014, each designed to hedge $25 million in underlying fixed rate senior unsecured notes in order to manage interest rate risk exposure. These swap agreements, which expire on the same date as the maturity date of the related senior unsecured notes due 2014 and contain call provisions consistent with the underlying senior unsecured notes, require the counterparty to pay the Company an amount based on the stated fixed interest rate due every six months. In exchange, Inergy is required to make semi-annual floating interest rate payments on the same dates to the counterparty based on an annual interest rate equal to the 6-month LIBOR interest rate plus spreads between 0.92% and 2.20% applied to the same notional amount of $150 million. The swap agreements have been accounted for as fair value hedges. Amounts to be received or paid under the agreements are accrued and recognized over the life of the agreements as an adjustment to interest expense. The change in the market value of the interest rate swaps for the year ended September 30, 2009, was recorded as a $3.7 million decrease to interest expense. This amount was offset by a $3.7 million increase to interest expense that was recorded as a result of a change in the fair value of the hedged fixed rate debt.
2016 Senior Notes
On January 11, 2006, Inergy and its wholly-owned subsidiary, Inergy Finance Corp. issued $200 million aggregate principal amount of 8.25% senior unsecured notes due 2016 (“2016 Senior Notes”) in a private placement to eligible purchasers.
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Notes to Consolidated Financial Statements-(Continued)
The 2016 Senior Notes contain covenants similar to the 2014 Senior Notes. Inergy used the net proceeds of the offering to repay outstanding indebtedness under the revolving acquisition credit facility. The 2016 Senior Notes represent senior unsecured obligations of Inergy and rank pari passu in right of payment with all other present and future senior indebtedness of Inergy. The 2016 Senior Notes are fully, unconditionally, jointly and severally guaranteed by all of Inergy’s wholly-owned current domestic subsidiaries. Also, Inergy has no independent assets or operations, and subsidiaries not guaranteeing the indenture are minor. Accordingly, condensed consolidating financial information for the parent and subsidiaries is not presented.
On May 18, 2006, Inergy completed an offer to exchange its existing 8.25% 2016 Senior Notes for $200 million of 8.25% senior notes due 2016 (the “2016 Exchange Notes”) that are registered and do not carry transfer restrictions, registration rights and provisions for additional interest. The 2016 Exchange Notes did not provide Inergy with any additional proceeds and satisfied Inergy’s obligations under the registration rights agreement.
The 2016 Senior Notes are redeemable, at Inergy’s option, in whole or in part, at any time on or after March 1, 2011, 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.
In April 2008, Inergy issued an additional $200 million of senior unsecured notes as an add-on to its existing 8.25% Senior Unsecured Notes due 2016 under Rule 144A to eligible purchasers. The notes mature on March 1, 2016. The proceeds from the bond issuance were $204 million, representing a 2% premium to par value. On September 16, 2008, Inergy completed an offer to exchange the additional $200 million of 8.25% senior notes due 2016 for $200 million of 8.25% senior notes due 2016 (the “Additional 2016 Exchange Notes”) that are registered and do not carry transfer restrictions, registration rights and provisions for additional interest. The Additional 2016 Exchange Notes did not provide Inergy with any additional proceeds and satisfied its obligations under the registration rights agreement.
2015 Senior Notes
On February 2, 2009, Inergy and its wholly-owned subsidiary, Inergy Finance Corp, issued $225 million aggregate principal amount of 8.75% senior unsecured notes due 2015 (the “2015 Senior Notes”) under Rule 144A to eligible purchasers. The 8.75% notes mature on March 1, 2015, and were issued at 90.191% of the principle amount to yield 11%.
The 2015 Senior Notes contain covenants similar to the 2014 and 2016 Senior Notes. Inergy used the net proceeds of the offering to repay outstanding indebtedness under the revolving acquisition credit facility. The 2015 Senior Notes represent senior unsecured obligations of Inergy and rank pari passu in right of payment with all other present and future senior indebtedness of Inergy. The 2015 Senior Notes are fully, unconditionally, jointly and severally guaranteed by all of Inergy’s wholly-owned current domestic subsidiaries. Also, Inergy has no independent assets or operations, and subsidiaries not guaranteeing the indenture are minor. Accordingly, condensed consolidating financial information for the parent and subsidiaries is not presented.
On October 7, 2009, Inergy completed an offer to exchange its existing 8.75% 2015 Senior Notes for $225 million of 8.75% senior notes due 2015 (the “2015 Exchange Notes”) that are registered and do not carry transfer
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Notes to Consolidated Financial Statements-(Continued)
restrictions, registration rights and provisions for additional interest. The 2015 Exchange Notes did not provide Inergy with any additional proceeds and satisfied Inergy’s obligations under the registration rights agreement.
The 2015 Senior Notes are redeemable, at Inergy’s option, in whole or in part, at any time on or after March 1, 2013, 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.
ASC Credit Agreement
Steuben Gas Storage Company, a majority-owned subsidiary of Arlington Storage Company (“ASC”) had a debt agreement in place at the time of the Company’s acquisition of ASC (“ASC Credit Agreement”). The ASC Credit Agreement is secured by the assets of Steuben and has no recourse against the assets of the Company. The ASC Credit Agreement is scheduled to mature in December 2015. The interest rate on half of the ASC Credit Agreement is at a fixed rate, while the other half is based on LIBOR plus the applicable spreads.
Notes Payable and Other Obligations
Non-interest bearing obligations due under noncompetition agreements and other note payable agreements consist of agreements between Inergy and the sellers of retail propane companies acquired from fiscal years 2003 through 2009 with payments due through 2019 and imputed interest ranging from 8.0% to 9.0%. Noninterest-bearing obligations consist of $24.4 million and $22.4 million in total payments due under agreements, less unamortized discount based on imputed interest of $5.8 million and $4.4 million at September 30, 2009 and 2008, respectively.
The aggregate amounts of principal to be paid on the outstanding long-term debt and notes payable during the next five years ending September 30 and thereafter are as follows (in millions):
Note 8. Leases
Inergy has certain noncancelable operating leases, mainly for office space and vehicles, which expire at various times over the next ten years. Certain of these leases contain terms that provide that the rental payment be indexed to published information.
Inergy, L.P. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
Future minimum lease payments under noncancelable operating leases for the next five years ending September 30 and thereafter consist of the following (in millions):
Rent expense for operating leases for the years ending September 30, 2009, 2008 and 2007, totaled $11.7 million, $10.6 million and $9.7 million, respectively.
Inergy has certain related party leases as discussed in Note 12.
Note 9. Partners’ Capital
Special Units
In August 2005, Inergy issued for aggregate gross proceeds of $25 million, 769,941 special units (the “Special Units”), representing a new class of equity securities in Inergy that were not entitled to a current cash distribution but would convert into common units representing limited partnership interests in Inergy at a specified conversion rate upon the commercial operation of the Stagecoach expansion project. The Special Units were issued to fund the $25 million acquisition of the rights to the Phase II expansion project of the Stagecoach natural gas storage facility in connection with the Stagecoach acquisition and were issued to Holdings.
On April 25, 2007, the 769,941 Special Units converted into 919,349 common units as a result of the commercial operation of the Phase II expansion of the Stagecoach natural gas storage facility. This beneficial conversion feature present in these Special Units was valued at $10.3 million and has been recognized as a non-cash allocation of (income) to the holder of the converted units for the purpose of calculating earnings per limited partner unit.
Common Unit Offerings
On March 23, 2006, Inergy’s shelf registration statement (File No. 333-132287) was declared effective by the Securities and Exchange Commission for the periodic sale of up to $1.0 billion of common units, partnership securities and debt securities, or any combination thereof. Pursuant to the shelf registration statement, Inergy is permitted to issue these securities from time to time for general business purposes, including debt repayment, future acquisitions, capital expenditures and working capital, or for other potential uses identified in a prospectus supplement.
On September 10, 2009, Inergy’s new shelf registration statement (File No. 333-158066) was declared effective by the Securities and Exchange Commission for the periodic sale of up to $1.0 billion of common units, partnership securities and debt securities, or any combination thereof.
In June 2006, Inergy issued 4,312,500 common units, under the shelf registration statement, in a public offering, which included 562,500 common units issued as result of the underwriters exercising their over-allotment
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Notes to Consolidated Financial Statements-(Continued)
provision. The issuance of these common units resulted in net proceeds of $102.7 million, after deducting underwriters’ discounts, commissions and other offering expenses. These proceeds were partially used to repay indebtedness under the Credit Agreement with the remainder used to fund capital expenditures made in connection with internal growth projects related to Inergy’s midstream assets.
In February 2007, Inergy issued 3,450,000 common units, under the shelf registration statement, which included 450,000 common units issued as a result of the underwriters exercising their over-allotment provision. The issuance of these common units resulted in net proceeds of $104.5 million, after deducting underwriters’ discounts, commissions and other offering expenses. The net proceeds from this offering were used to repay indebtedness under Inergy’s Credit Agreement.
In August 2008, Inergy issued 809,389 common units in conjunction with the acquisition of US Salt and in October 2008, Inergy issued 309,194 common units to Blu-Gas in a private placement as a portion of the purchase price.
In March 2009, Inergy issued 4,000,000 common units, under the shelf registration statement, and in April 2009, the underwriters exercised their option to purchase 418,000 additional Inergy common units. Net proceeds from the aforementioned issuances amounted to $94.3 million.
In August 2009, Inergy issued 3,500,000 common units, under the shelf registration statement, and in September 2009, the underwriters exercised their option to purchase 525,000 additional Inergy common units. Net proceeds from the aforementioned issuances amounted to $106.9 million.
Quarterly Distributions of Available Cash
Inergy is expected to make quarterly cash distributions of all of its Available Cash, generally defined as income (loss) before income taxes plus depreciation and amortization, less maintenance capital expenditures and net changes in reserves established by the General Partner for future requirements. These reserves are retained to provide for the proper conduct of the Company’s business, or to provide funds for distributions with respect to any one or more of the next four fiscal quarters.
Distributions by Inergy in an amount equal to 100% of its Available Cash will generally be made 99% to the common and subordinated unitholders and 1% to the General Partner, subject to the payment of incentive distributions to the holders of Incentive Distribution Rights to the extent that certain target levels of cash distributions are achieved. To the extent there is sufficient Available Cash, the holders of common units had the right to receive the Minimum Quarterly Distribution ($0.30 per unit), plus any arrearages, prior to any distribution of Available Cash to the holders of subordinated units.
Inergy, L.P. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
Inergy is expected to make distributions of its Available Cash within 45 days after the end of each fiscal quarter ending December, March, June and September to holders of record on the applicable record date. A summary of Inergy’s quarterly distributions for the years ended September 30, 2009, 2008 and 2007, is presented below:
Unit Purchase Plan
Inergy’s managing general partner sponsors a unit purchase plan for its employees and the employees of its affiliates. The unit purchase plan permits participants to purchase common units in market transactions from Inergy, the general partners or any other person. All purchases made have been in market transactions, although the plan allows Inergy to issue additional units. Inergy has reserved 100,000 units for purchase under the unit purchase plan. As determined by the compensation committee, the managing general partner may match each participant’s cash base pay or salary deferrals by an amount up to 10% of such deferrals and have such amount applied toward the purchase of additional units. The managing general partner has also agreed to pay the brokerage commissions, transfer taxes and other transaction fees associated with a participant’s purchase of common units. The maximum amount that a participant may elect to have withheld from his or her salary or cash base pay with respect to unit purchases in any calendar year may not exceed 10% of his or her base salary or wages for the year. Units purchased on behalf of a participant under the unit purchase plan generally are to be held by the participant for at least one year. To the extent a participant desires to sell or dispose of such units prior to the end of this one year holding period, the participant will be ineligible to participate in the unit purchase plan again until the one year anniversary of the date of such sale. The unit purchase plan is intended to
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Notes to Consolidated Financial Statements-(Continued)
serve as a means for encouraging participants to invest in common units. Units purchased through the unit purchase plan by Inergy and its employees for the fiscal years ended September 30, 2009, 2008 and 2007, were 11,298 units, 11,670 units and 8,681 units, respectively. Holdings’ general partner sponsors a similar plan for Inergy and its employees. Common units purchased through the Holdings’ unit purchase plan for the fiscal years ended September 30, 2009, 2008 and 2007, were 5,505 units, 5,387 units and 2,667 units, respectively.
Long-Term Incentive Plan
Inergy’s managing general partner sponsors the long-term incentive plan for its employees, consultants and directors and the employees of its affiliates that perform services for Inergy. The long-term incentive plan currently permits the grant of awards covering an aggregate of 5,000,000 common units, which can be granted in the form of unit options, phantom units and/or restricted units. With the exception of 56,000 unit options (exercise prices from $1.92 to $5.34) granted to non-executive employees in exchange for option grants made by the predecessor in fiscal 1999, all of which have been grandfathered into the long-term incentive plan and are presented as grants in the table below, all units granted under the plan will vest in accordance with the Unit Option Agreements, which typically provide that unit options begin vesting five years from the anniversary date of the applicable grant date. Shares issued as a result of unit option exercises are newly issued shares.
Restricted Units
A restricted unit is a common unit that participates in distributions and vests over a period of time yet during such time is subject to forfeiture. The compensation committee may make grants of restricted units to employees, directors and consultants containing such terms as the compensation committee determines. The compensation committee will determine the period over which restricted units granted to participants will vest. The compensation committee, in its discretion, may base its determination upon the achievement of specified financial objectives or other events. In addition, the restricted units will vest upon a change in control of the managing general partner of Inergy. If a grantee’s employment, consulting arrangement or membership on the board of directors terminates for any reason, the grantee’s restricted units will be automatically forfeited unless, and to the extent, the compensation committee or the terms of the award agreement provide otherwise.
The Company intends the restricted units to serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation of the common units. Therefore, plan participants will not pay any consideration for the common units they receive, and Inergy will receive no cash remuneration for the units.
The Company granted 326,910, 60,064 and 69,520 restricted units during the years ended September 30, 2009, 2008 and 2007, respectively. The majority of the restricted units are 100% vested on the fifth anniversary of the grant date, subject to the provisions as outlined in the restricted unit award agreement. Some of these units are subject to the achievement of certain specified performance objectives and failure to meet the performance objectives will result in forfeiture and cancellation of the restricted units. The Company recognizes expense on these units each quarter by multiplying the closing price of the Company’s common units on the date of grant by the number of units granted, and expensing that amount over the vesting period.
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Notes to Consolidated Financial Statements-(Continued)
A summary of Inergy’s weighted-average grant date fair value for restricted units for the year ended September 30, 2009, is as follows:
The weighted-average grant date fair value of restricted units granted during the year ended September 30, 2008, amounted to $28.71. No restricted units vested during the year ended September 30, 2008. The weighted-average grant date fair value of restricted units granted and vested during the year ended September 30, 2007, amounted to $32.16 and $26.62, respectively. The fair value of restricted units vested during the year ended September 30, 2009, was $2.0 million. The fair value of restricted units vested during the year ended September 30, 2007, was negligible.
The compensation expense recorded by the Company related to these restricted stock awards was $1.6 million, $2.4 million and $0.4 million for the years ended September 30, 2009, 2008 and 2007, respectively.
Unit Options
Unit options issued under the long-term incentive plan have an exercise price equal to the fair market value of the units on the date of the grant. In general, unit options will expire after 10 years and are subject to vesting periods as outlined in the unit option agreement. In addition, most unit option grants made under the plan provide that the unit options will become exercisable upon a change of control of the managing general partner or Inergy.
A summary of Inergy’s unit option activity for the years ended September 30, 2009, 2008 and 2007, is as follows:
Inergy, L.P. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
Information regarding options outstanding and exercisable as of September 30, 2009, is as follows:
The weighted-average remaining contract lives for options outstanding and exercisable at September 30, 2009, were approximately five years and four years, respectively. The fair value of each option grant was estimated as of the grant date using the Black-Scholes option pricing model using the assumptions outlined in the table below. Expected volatility was based on a combination of historical and implied volatilities of the Company’s stock over a period at least as long as the options’ expected term. The expected life represents the period of time that the options granted are expected to be outstanding. The risk-free rate is based on the applicable U.S. Treasury yield curve in effect at the time of the grant of the share options.
The aggregate intrinsic values of options outstanding and exercisable at September 30, 2009, were $1.2 million and $1.1 million, respectively. The aggregate intrinsic value of unit options exercised during the year ended September 30, 2009, was $0.5 million. Aggregate intrinsic value represents the positive difference between the Company’s closing stock price on the last trading day of the fiscal period, which was $29.78 on September 30, 2009, and the exercise price multiplied by the number of options outstanding.
As of September 30, 2009, there was $16.4 million of total unrecognized compensation cost related to unvested share-based compensation awards granted to employees under the restricted stock and unit option plans, including $9.3 million related to Holdings unvested share-based compensation awards. That cost is expected to be recognized over a five-year period.
Note 10. Employee Benefit Plans
A 401(k) plan is available to all of Inergy’s employees after meeting certain requirements. The plan permits employees to make contributions up to 75% of their salary, up to statutory limits, which was $16,500 in 2009. The plan provides for matching contributions by Inergy for employees completing one year of service of at least 1,000 hours. Aggregate matching contributions made by Inergy were $2.1 million in fiscal 2009 and 2008, and $1.9 million in fiscal 2007.
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Notes to Consolidated Financial Statements-(Continued)
Of Inergy’s 2,910 employees, 8% are subject to collective bargaining agreements. For the years ended September 30, 2009, 2008 and 2007, Inergy made contributions on behalf of its union employees to union sponsored defined benefit plans of $2.9 million, $2.7 million and $2.6 million, respectively.
Note 11. Commitments and Contingencies
Inergy periodically enters into agreements with suppliers to purchase fixed quantities of propane, distillates, natural gas and liquids at fixed prices. At September 30, 2009, the total of these firm purchase commitments was $225.3 million of which $220.1 million will occur over the course of the next twelve months with the balance of $5.2 million occurring over the following twelve months. The Company also enters into non-binding agreements with suppliers to purchase quantities of propane, distillates, natural gas and liquids at variable prices at future dates at the then prevailing market prices.
Inergy has entered into certain purchase commitments in connection with the identified growth projects related to the Thomas Corners and Finger Lakes midstream assets. At September 30, 2009, the total of these firm purchase commitments was $10.4 million and the purchases associated with these commitments will occur over the course of the next twelve months.
Inergy is periodically involved in litigation proceedings. The results of litigation proceedings cannot be predicted with certainty; however, management believes that Inergy does not have material potential liability in connection with these proceedings that would have a significant financial impact on its consolidated financial condition, results of operations or cash flows.
Inergy utilizes third-party insurance subject to varying retention levels of self-insurance, which management considers prudent. Such self-insurance relates to losses and liabilities primarily associated with medical claims, workers’ compensation claims and general, product, vehicle and environmental liability. Losses are accrued based upon management’s estimates of the aggregate liability for claims incurred using certain assumptions followed in the insurance industry and based on past experience. The primary assumption utilized is actuarially determined loss development factors. The loss development factors are based primarily on historical data. Inergy’s self insurance reserves could be affected if future claims development differs from the historical trends. Inergy believes changes in health care costs, trends in health care claims of its employee base, accident frequency and severity and other factors could materially affect the estimate for these liabilities. Inergy continually monitors changes in employee demographics, incident and claim type and evaluates its insurance accruals and adjusts its accruals based on its evaluation of these qualitative data points. At September 30, 2009 and 2008, Inergy’s self-insurance reserves were $19.3 million and $17.4 million, respectively.
Note 12. Related Party Transactions
In connection with the acquisition of assets from United Propane, Inc. on July 31, 2003, the Company entered into ten leases of real property formerly used by United Propane (now known as Bonavita, Inc.) in its business. Five of these leases are with United Propane, three of the leases are with Pascal Enterprises, Inc. and two with Robert A. Pascal. Each of these leases provided for an initial five-year term, and was renewable for up to two additional terms of five years each. During the initial term of these leases the Company was required to make monthly rental payments totaling $59,167, of which $17,167 was payable to United Propane, $16,800 was payable to Pascal Enterprises and $25,200 was payable to Mr. Pascal. During fiscal 2008, the Company exercised its renewal option on six of these leases for an additional five-year term each. Three of these leases are with United Propane, two of these leases are with Mr. Pascal and one is with Pascal Enterprises. The Company is now required to make monthly rental payments totaling $50,947, of which $8,400 is payable to United Propane, $30,997 is payable to Mr. Pascal and $11,550 is payable to Pascal Enterprises.
Inergy, L.P. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
Robert A. Pascal is the sole shareholder of Bonavita, Inc., Pascal Enterprises and United Leasing. Mr. Pascal retired from the Company’s board of directors on December 12, 2008.
On occasion, Holdings reimburses the Company for expenses paid on behalf of Holdings. The expenses that are reimbursed predominantly include insurance and professional fees. These expenses for the years ended September 30, 2009, 2008 and 2007, amounted to $0.5 million, $0.2 million and $0.4 million, respectively. When the Company has a receivable from Holdings, it is included in prepaid expenses and other current assets on the Company’s consolidated balance sheets. At September 30, 2009 and 2008, Inergy had $0.1 million and $0.2 million, respectively, due from Holdings.
The managing general partner and its affiliates will not receive any management fee or other compensation for the management of the Company. The managing general partner and its affiliates will be reimbursed, however, for direct and indirect expenses incurred on Inergy’s behalf. The expense reimbursement to the managing general partner and its affiliates was $3.1 million for the fiscal year ended September 30, 2009, and $3.5 million for the fiscal years ended September 30, 2008 and 2007, with the reimbursement related primarily to personnel costs.
During fiscal 2009, Inergy Holdings received $48.1 million in distributions related to its 0.8% general partner interest and incentive distribution rights and $12.3 million related to its 7.8% limited partner interest.
Note 13. Segments
Inergy’s financial statements reflect two operating and reportable segments: propane operations and midstream operations. Inergy’s propane operations include propane sales to end users, the sale of propane-related appliances and service work for propane-related equipment, the sale of distillate products and wholesale distribution of propane and marketing and price risk management services to other users, retailers and resellers of propane. Inergy’s midstream operations include storage of natural gas for third parties, fractionation of natural gas liquids, processing of natural gas, distribution of natural gas liquids and the production and sale of salt. Results of operations for acquisitions that occurred during the year ended September 30, 2009, are included in the propane segment.
The identifiable assets associated with each reportable segment include accounts receivable and inventories. Goodwill, property, plant and equipment and expenditures for property, plant and equipment are also presented for each segment. The net asset/liability from price risk management, as reported in the accompanying consolidated balance sheets, is primarily related to the propane segment.
Inergy, L.P. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
Revenues, gross profit, identifiable assets, goodwill, property, plant and equipment and expenditures for property, plant and equipment for each of Inergy’s reportable segments are presented below (in millions):
Inergy, L.P. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
Note 14. Quarterly Financial Data (Unaudited)
Inergy’s business is seasonal due to weather conditions in its service areas. Propane sales to residential and commercial customers are affected by winter heating season requirements, which generally results in higher operating revenues and net income during the period from October through March of each year, and lower operating revenues and either net losses or lower net income during the period from April through September of each year. Sales to industrial and agricultural customers are much less weather sensitive. Summarized unaudited quarterly financial data is presented below (in millions, except per unit information):
(a) The accumulation of basic and diluted net income (loss) per limited partner unit does not total the amount for the fiscal year due to changes in ownership percentages throughout the year.
Note 15. Subsequent Events
The Company has identified subsequent events requiring disclosure through November 30, 2009, the date of the filing of this Form 10-K.
On November 13, 2009 a quarterly distribution of $0.675 per limited partner unit was paid to unitholders of record on November 6, 2009 with respect to the fourth fiscal quarter of 2009, which totaled $55.2 million.
On November 24, 2009, the Company entered into a secured credit facility which provides borrowing capacity of up to $525 million in the form of a $450 million general partnership credit facility and a $75 million working capital credit facility. This facility replaces its former senior credit facility due 2010. This new facility will mature on November 22, 2013. Borrowings under this new facility are available for working capital needs, future acquisitions, capital expenditures and other general partnership purposes, including the refinancing of existing indebtedness under the former credit facility.
The new secured credit facility contains various affirmative and negative covenants and default provisions, as well as requirements with respect to the maintenance of specified financial ratios and limitations on making investments, permitting liens and entering into other debt obligations. All borrowings under the facility bear interest, at the Company’s option, subject to certain limitations, at a rate equal to the following:
•
the Alternate Base Rate, which is defined as the higher of i) the federal funds rate plus 0.50%; ii) JP Morgan’s prime rate; or iii) the Adjusted LIBO Rate plus 1%; plus a margin varying from 1.50% to 2.75%; or
Inergy, L.P. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
•
the Adjusted LIBO Rate, which is defined as the LIBO Rate plus a margin varying from 2.50% to 3.75%.
Certain counterparties have elected to call their respective interest rate swap positions. The aggregate notional amount associated with these swaps amounts to $125 million. These swaps will be called in December 2009 and the Company is currently evaluating its options to manage its interest rate risk.
SIGNATURES
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.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following officers and directors of Inergy GP, LLC, as managing general partner of Inergy, L.P., the registrant, in the capacities and on the dates indicated.
Schedule II
Inergy, L.P. and Subsidiaries
Valuation and Qualifying Accounts
(in millions)