10-K 1 d10k.htm FORM 10-K Form 10-K
Table of Contents

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM 10-K

 

 

(Mark One)

 

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended September 30, 2010

OR

 

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                            to                         .

Commission file number: 000-32453

 

 

INERGY, L.P.

(Exact name of registrant as specified in its charter)

 

 

 

Delaware   43-1918951
(State or other jurisdiction of
incorporation or organization)
 

(I.R.S. Employer

Identification No.)

Two Brush Creek Boulevard, Suite 200, Kansas City, Missouri 64112

(Address of principal executive offices) (Zip Code)

(816) 842-8181

(Registrant’s telephone number including area code)

SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:

 

Title of Each Class

 

Name of Each Exchange on Which Registered

Common Units representing limited partnership interests   The New York Stock Exchange

SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: None

 

 

Indicate by check mark if registrant is a well-known seasoned issuer, as defined by Rule 405 of the Securities Act.    Yes  x    No  ¨

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act.    Yes  ¨    No  x

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  x    No  ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  x

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

 

Large accelerated filer  x     Accelerated filer  ¨
Non-accelerated filer  ¨    (Do not check if a smaller reporting company)   Smaller reporting company  ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨    No  x

The aggregate market value of the 77,740,764 common units of the registrant held by non-affiliates computed by reference to the $39.26 closing price of such common units on October 29, 2010, was $3.1 billion. The aggregate market value of the 60,688,232 common units of the registrant held by non-affiliates computed by reference to the $37.80 closing price of such common units on March 31, 2010, the last business day of the registrant’s most recently completed second fiscal quarter, was $2.3 billion. As of November 15, 2010, the registrant had 120,918,070 common and class B units outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the following documents are incorporated by reference into the indicated parts of this report: None.

 

 

 


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GUIDE TO READING THIS REPORT

The following information should help you understand some of the conventions used in this report.

 

   

Throughout this report,

(1) When we use the terms “we,” “us,” “our company,” “Inergy,” or “Inergy, L.P.,” we are referring either to Inergy, L.P., the registrant itself, or to Inergy, L.P. and its operating subsidiaries collectively, as the context requires.

(2) When we use the term “our predecessor,” we are referring to Inergy Partners, LLC, the entity that conducted our business before our initial public offering, which closed on July 31, 2001. Inergy, L.P. was formed as a Delaware limited partnership on March 7, 2001 and did not have operations until the closing of our initial public offering. Our predecessor commenced operations in November 1996. The discussion of our business throughout this report relates to the business operations of Inergy Partners, LLC before Inergy, L.P.’s initial public offering and of Inergy, L.P. thereafter.

(3) When we use the term “Inergy Propane,” we are referring to Inergy Propane, LLC itself, or to Inergy Propane, LLC and its operating subsidiaries collectively, as the context requires.

(4) When we use the term “finance company,” we are referring to Inergy Finance Corp., a subsidiary of Inergy, L.P., formed on September 21, 2004.

(5) When we use the term “managing general partner,” we are referring to Inergy GP, LLC.

(6) When we use the term “non-managing general partner,” we are referring to Inergy Partners, LLC.

(7) When we use the term “general partners,” we are referring to our managing general partner and our non- managing general partner.

(8) When we use the term “Inergy Holdings” or “Holdings,” we are referring to Inergy Holdings, L.P. itself, or to Inergy Holdings, L.P. and its subsidiaries collectively, as the context requires.

 

   

Historically, we have had a managing general partner and a non-managing general partner. As explained further in Part I, Item 1. Business, on November 5, 2010, we closed on the transactions contemplated by the Simplification Transaction among us, Inergy Holdings and the other parties thereto pursuant to which, among other things, we cancelled our incentive distribution rights and acquired the equity interests of our non-managing general partner. Our managing general partner does not have rights to allocations or distributions from our company and does not receive a management fee, but it is reimbursed for expenses incurred on our behalf.


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INERGY, L.P.

INDEX TO ANNUAL REPORT ON FORM 10-K

 

          Page  
PART I   

Item 1.

  

Business

     1   

Item 1A.

  

Risk Factors

     18   

Item 1B.

  

Unresolved Staff Comments

     34   

Item 2.

  

Properties

     34   

Item 3.

  

Legal Proceedings

     34   

Item 4.

  

Removed and Reserved

     35   
PART II   

Item 5.

  

Market for the Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities

     36   

Item 6.

  

Selected Financial Data

     37   

Item 7.

  

Management’s Discussion and Analysis of Financial Condition and Results of Operations

     40   

Item 7A.

  

Quantitative and Qualitative Disclosures about Market Risk

     66   

Item 8.

  

Financial Statements and Supplementary Data

     67   

Item 9.

  

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

     67   

Item 9A.

  

Controls and Procedures

     67   

Item 9B.

  

Other Information

     68   
PART III   

Item 10.

  

Directors, Executive Officers and Corporate Governance

     69   

Item 11.

  

Executive Compensation

     73   

Item 12.

  

Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters

     88   

Item 13.

  

Certain Relationships, Related Transactions and Director Independence

     89   

Item 14.

  

Principal Accountant Fees and Services

     93   
PART IV   

Item 15.

  

Exhibits and Financial Statement Schedules

     94   


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PART I

Item 1. Business.

Recent Developments

On August 7, 2010, we, Inergy Holdings and certain other parties thereto entered into an agreement and plan of merger, which was amended and restated on September 3, 2010 (the “Merger Agreement”), as part of a plan to simplify our capital structure. Pursuant to the steps contemplated by the Merger Agreement (the “Simplification Transaction”), Inergy Holdings merged into a wholly owned subsidiary of its general partner (the “Merger”) and the outstanding common units in Inergy Holdings were cancelled. In connection with the Simplification Transaction, our incentive distribution rights, all of which were held by Inergy Holdings, were cancelled, and we acquired the approximate 0.6% economic general partner interest in us that was held by our non-managing general partner.

Upon completion of the Merger, the holders of Holdings common units (the “Holdings unitholders”) received 0.77 Inergy common units for each Inergy Holdings common unit that they own (the “exchange ratio”). The exchange ratio took into account 1,080,453 Inergy common units that are owned by Inergy Holdings which were distributed to the Holdings unitholders as part of the Merger consideration. Inergy issued approximately 35.2 million new common units in connection with the Simplification Transaction. We also issued 11,568,560 Class B Units to certain members of senior management and directors of Inergy Holdings’ general partner and other beneficial owners of Inergy Holdings common units in lieu of issuing them an equivalent number of common units. The Class B Units will not receive cash distributions but instead will receive distributions of additional Class B Units. The Class B units will convert automatically into Inergy common units on a one-for-one basis in two tranches over a two-year period.

Finally, in connection with the Simplification Transaction, we assumed and immediately paid off approximately $24.1 million of outstanding indebtedness under Inergy Holdings’ credit agreements. The Simplification Transaction took effect on November 5, 2010.

Inergy GP, our managing general partner, continues to manage us following the Simplification Transaction and our management team has remained unchanged. Additionally, one of the independent members of Holdings’ general partner’s board of directors joined our general partner’s board of directors. The other independent members of Holdings’ general partner’s board of directors were already serving as independent members of our general partner’s board of directors.

On October 14, 2010, we completed the acquisition of Tres Palacios Gas Storage, LLC. Tres Palacios Gas Storage, LLC is the owner and operator of a natural gas storage facility located in Matagorda County, Texas (“Tres Palacios”). Tres Palacios is a high deliverability, salt dome natural gas storage facility with approximately 38.4 bcf of working gas capacity (Caverns 1-3). The facility is expandable by an additional 9.5 bcf of working gas capacity which we expect to place in service by or before 2014 (Cavern 4). Located approximately 100 miles southwest of Houston, Tres Palacios is currently connected to a total of ten intrastate and interstate pipelines offering connectivity to multiple demand markets including the Houston and San Antonio metropolitan areas and the broader Texas markets as well as markets in the Northeast, Midwest, Southeast, Florida and Mid-Atlantic United States and Mexico. Tres Palacios offers customers greater than six-turn gas storage capability with maximum withdrawal capacity of 2.5 bcf per day and maximum injection capacity of 1 bcf per day.

On October 19, 2010, we completed the acquisition of the propane operating assets of Schenck Gas Services, LLC, located in East Hampton, New York.

On November 15, 2010, we completed the acquisition of the propane assets of Pennington Energy Corporation (“Pennington”), headquartered in Morenci, Michigan. Pennington currently delivers propane to nearly 14,800 customers from seven customer service centers in Northwest Ohio and Southeast Michigan.

 

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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 four natural gas storage facilities (“Stagecoach”, “Steuben”, “Thomas Corners” and “Tres Palacios”), a liquefied petroleum gas (“LPG”) storage facility (“Finger Lakes LPG”), a natural gas liquids (“NGL”) business and a solution-mining and salt production company (“US Salt”). For the fiscal year ended September 30, 2010, we sold and physically delivered 340.2 million gallons of propane to retail customers and 415.3 million gallons of propane to wholesale customers.

We believe we are the fourth 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 29, 2010, we serve over 700,000 retail customers in 33 states from 356 customer service centers, which have an aggregate of 34.2 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:

 

   

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 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 2014.

 

   

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.

 

   

Finger Lakes LPG, currently 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 fee-based and is currently 100% contracted primarily with investment grade-rated companies with term contracts having a weighted-average maturity extending to 2011. We expect to extend these contracts in the future. 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. 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 the first half of calendar 2011.

 

   

100% of the membership interests of Arlington Storage Company, LLC (“ASC”). During the fiscal year we acquired the minority interests in Steuben Gas Storage Company (“Steuben”) and ASC is now the sole owner and operator of Steuben, which owns a 6.2 bcf natural gas storage facility located in Steuben County, New York. 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 2011. We expect to extend these contracts in the future.

 

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Thomas Corners, a 7 bcf natural gas storage facility also located in Steuben County, New York, with maximum withdrawal and injection capabilities of 140 MMcf/day and 70 MMcf/day, respectively. 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 2015.

 

   

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.

 

   

Tres Palacios, a high deliverability, salt dome natural gas storage facility with approximately 38.4 bcf of working gas capacity (Caverns 1-3). The facility is expandable by an additional 9.5 bcf of working gas capacity which we expect to place in service by or before 2014 (Cavern 4). Caverns 1 and 2 are currently 90% contracted with primarily investment grade-rated companies until 2013. We closed on the acquisition of this facility on October 14, 2010. Tres Palacios offers customers greater than six-turn gas storage capability with maximum withdrawal capacity of 2.5 bcf per day and maximum injection capacity of 1 bcf per day.

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, 2010, we have acquired 86 companies for an aggregate purchase price of approximately $2.1 billion, including working capital, assumed liabilities and acquisition costs. The acquisitions include the assets of two propane companies acquired during fiscal 2010 for an aggregate purchase price, net of cash acquired, of $253.0 million.

The following chart sets forth information about each business we acquired during the fiscal year ended September 30, 2010, and through the date of this filing:

 

Acquisition Date

  Company   

Location

December 2009

  Liberty Propane, LP    Overland Park, KS

January 2010

  MGS Corporation    Hackensack, NJ

Acquisitions after September 30, 2010

        

October 2010

  Tres Palacios Gas Storage LLC    Matagorda County, TX

October 2010

  Schenck Gas Services, LLC    East Hampton, NY

November 2010

  Pennington Energy Corporation    Morenci, MI

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 New York Stock Exchange 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.inergylp.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.

 

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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 can arise as more geographically remote neighborhoods are developed. Propane is often 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 38% 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

 

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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

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:

 

   

weather-related demand shifts;

 

   

increasing supply related to new production technology and the development of shale gas formations;

 

   

infrastructure constraints;

 

   

trading impacts on short-term energy markets; and

 

   

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

 

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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. In the South around our Tres Palacios asset, seasonal peak days generated by excessive electric demand during the summer also drive consumption. 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 and salt dome storage such as the Stagecoach, Thomas Corners and Tres Palacios facilities. 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.

 

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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, California, separates 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 was the single largest producer of salt in 2007, 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.

 

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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 2011. 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, 2010, we have acquired and successfully integrated 86 companies—80 retail 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:

 

   

businesses that generate distributable cash flow that is accretive to common unitholders on a per unit basis;

 

   

propane and midstream businesses in attractive market areas;

 

   

propane businesses with established names and reputations for customer service and reliability;

 

   

propane businesses with high concentration of propane sales to residential customers;

 

   

midstream businesses that generate predictable, stable fee-based cash flow streams;

 

   

midstream businesses with organic expansion opportunities or strategic regional enhancement; and

 

   

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.

 

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Flexible Financial Structure

We have a $450 million revolving general partnership credit facility for acquisitions and a $75 million revolving working capital facility. 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. We expect that the elimination of our incentive distribution rights will reduce our cost of capital, which will enhance our ability to compete for future acquisitions and finance organic growth projects.

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, 2010, sales to residential customers represented approximately 65% 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, 2010, we delivered 415.3 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

 

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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 will add additional gas storage capacity to our operations in the Northeast. Our recent acquisition of Tres Palacios, which is located approximately 100 miles southwest of Houston, provides us access to the Houston and San Antonio metropolitan areas and the broader Texas markets as well as markets in the Northeast, Midwest, Southeast, Florida and Mid-Atlantic United States and Mexico. The Tres Palacios facility, like Stagecoach, is located near shale gas supply, connected to multiple supply sources and supports strong demand markets. The Texas natural gas fired electric generation market is among the largest in the United States. 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. These contracts are primarily with investment-grade rated customers such as large east coast utilities and major gas marketing firms. 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.

 

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Propane Operations

Retail Propane

Customer Service Centers

At October 29, 2010, we distributed propane to over 700,000 retail customers from 356 customer service centers in 33 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:

 

State

   Number of
Customer
Service
Centers
 

Alabama

     44   

Arizona

     1   

Arkansas

     2   

Colorado

     5   

Connecticut

     4   

Delaware

     1   

Florida

     19   

Georgia

     5   

Illinois

     4   

Indiana

     24   

Kentucky

     2   

Maine

     5   

Maryland

     6   

Massachusetts

     7   

Michigan

     31   

Mississippi

     29   

New Hampshire

     3   

New Jersey

     8   

New Mexico

     3   

New York

     11   

North Carolina

     29   

Ohio

     25   

Oklahoma

     3   

Pennsylvania

     17   

Rhode Island

     1   

South Carolina

     3   

Tennessee

     10   

Texas

     26   

Vermont

     11   

Virginia

     6   

Washington

     3   

West Virginia

     2   

Wisconsin

     6   
        

Total

     356   
        

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

 

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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, 2010, 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:

 

   

65% to residential customers;

 

   

25% to industrial and commercial customers; and

 

   

10% to agricultural customers.

No single retail customer accounted for more than 1% of our revenue during the fiscal year ended September 30, 2010. 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:

 

   

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;

 

   

loss of customers to competing energy sources has been low;

 

   

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

 

   

our ability to offset customer losses through a combination of acquisitions and to a lesser extent, sales to new customers in existing markets.

 

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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, 2010, we owned a fleet of 143 tractors, 234 transports, 1,341 bobtail and rack trucks and 885 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:

 

   

customers are billed on a timely basis;

 

   

customers are more likely to pay a local business;

 

   

cash payments are received faster; and

 

   

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

 

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distribution companies, primarily in the Midwest and Southeast. While our wholesale supply, marketing and distribution operations accounted for 27% of total revenue, this business represented 4% of our gross profit during the fiscal year ended September 30, 2010.

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, 2010, 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. (17%) and Sunoco, Inc. (11%), accounted for 28% 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 700 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 in August 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,

 

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the Stagecoach facility is currently connected to Tennessee Gas Pipeline Company’s (“TPG”) 300 Line and the Millennium Pipeline and is a significant participant in the northeast United States natural gas distribution system. The Stagecoach facility is currently 100% contracted primarily with investment grade-rated companies with term contracts having a weighted-average maturity extending to 2014. We currently have pending, before the Federal Energy Regulatory Commission (“FERC”), two applications for Natural Gas Act Section 7(c) certificate authorization to construct and operate expansions of the Stagecoach facility: the North/South expansion project (proposed additional compression and measurement facilities to serve shippers seeking to wheel gas on a firm basis through existing North and/or South Laterals of Stagecoach) and the Marc I Hub Line expansion project (proposed 43 mile, 30 inch bi-directional gas pipeline connecting the Stagecoach South Lateral pipeline interconnect at TGP’s 300 line to Transcontinental Pipe Line Company, LLC’s (“Transco”) Leidy Line. If certificated as requested, it is anticipated that these expansion projects will allow shippers to wheel/transport gas bi-directionally on a firm basis approximately 75 miles between the Millennium Pipeline and Transco’s Leidy Line and all points in between.

ASC was acquired in October 2007 and was the majority owner and operator of Steuben. During this fiscal year we acquired the minority interests in Steuben and ASC is now the sole 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 fee based-based and is currently 100% contracted primarily with investment grade-rated companies with term contracts having a weighted-average maturity extending to 2011. 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. 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 2015. From November 2009 through March 2010, Thomas Corners generated revenue from interruptible storage contracts. 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).

In October 2010, we completed the acquisition of the Tres Palacios natural gas storage facility located in Matagorda County, Texas. Tres Palacios is a high deliverability, salt dome natural gas storage facility with approximately 38.4 bcf of working gas capacity (Caverns 1-3). The facility is expandable by an additional 9.5 bcf of working gas capacity which we expect to place in service by or before 2014 (Cavern 4). Caverns 1 and 2 are currently 90% contracted with primarily investment grade-rated companies until 2013. Located approximately 100 miles southwest of Houston, Tres Palacios is currently connected to a total of ten intrastate and interstate pipelines offering connectivity to multiple demand markets including the Houston and San Antonio metropolitan areas and the broader Texas markets as well as markets in the Northeast, Midwest, Southeast, Florida and Mid-Atlantic United States and Mexico.

On January 11, 2010, we announced that we had executed a definitive agreement to purchase the Seneca Lake natural gas storage facility located in Schuyler County, New York (“Seneca Lake”) and two related pipelines for approximately $65 million. Seneca Lake is an approximate 2.0 bcf underground salt cavern storage facility located on our US Salt property outside Watkins Glen, New York, and has a maximum withdrawal capability of 145 MMcf/day and maximum injection capability of 75 MMcf/day. Seneca Lake is connected to the Dominion Transmission System via the 16-inch diameter, 20 mile Seneca West Pipeline and indirectly to the city gate of Binghamton, New York, via the 12-inch diameter, 37.5 mile Seneca East Pipeline, which runs within approximately 4 miles of our Stagecoach North Lateral interconnect with the Millennium Pipeline. The acquisition is subject to customary closing conditions and regulatory approvals.

 

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LPG Storage Operations

Our Finger Lakes LPG facility, acquired in October 2006, is currently 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 fee-based and is currently 100% contracted primarily with investment grade-rated companies with term contracts having a weighted-average maturity extending to 2011. 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. 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 the first half of calendar 2011.

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. In addition to the 5 million barrel Finger Lakes LPG storage expansion that we are currently developing, 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 14 to our consolidated financial statements.

Employees

As of October 29, 2010, we had 2,997 full-time employees and 85 part-time employees. Of the 3,082 employees, 128 were general and administrative and 2,954 were operational. Of the operational employees, 262 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 extensive federal, state and local regulation. In particular, our Stagecoach, Steuben, Thomas Corners and Tres Palacios natural gas storage facilities are subject to regulation by the FERC.

 

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Under the Natural Gas Act, the FERC has authority to regulate gas transportation services in interstate commerce, including natural gas storage services. The FERC exercises jurisdiction over rates charged for services and the terms and conditions of service; the 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; standards of conduct between affiliated entities; and various other matters. Regulated natural gas companies are prohibited from charging rates determined by the FERC to be unjust, unreasonable, or unduly discriminatory, and both the existing tariff rates and the proposed rates of regulated natural gas companies are subject to challenge.

The rates and terms and conditions of our natural gas storage and hub services are found in the FERC-approved tariffs of Central New York Oil and Gas Company, LLC (“CNYOG”), the owner of the Stagecoach facility; Steuben Gas Storage Company, the owner of the Steuben facility; ASC, the owner of the Thomas Corners facility; and Tres Palacios Gas Storage, LLC (“TPG Storage”), the owner of the Tres Palacios facility. CNYOG, ASC and TPG Storage are authorized to charge and collect market-based rates for services provided at the Stagecoach, Thomas Corners and Tres Palacios facility, respectively. Steuben Gas Storage Company is authorized to charge and collect cost-of-service rates at the Steuben facility. A loss of market-based rate authority, or any successful complaint or protest against the rates charged or provided by CNYOG, ASC or TPG Storage could have an adverse impact on our revenues.

Our natural gas and LPG storage operations are also subject to non-rate regulation by state agencies. For example, the Railroad Commission of Texas (“RRC”) has jurisdiction over oil and gas wells drilled and produced, underground natural gas storage caverns and related facilities and pipelines used to transport oil or gas resources in Texas, and the New York State Department of Environmental Conservation (“NYSDEC”) has jurisdiction over the underground storage of natural gas and LPG and well drilling, conversion and plugging in New York. As a result, the RRC regulates aspects of the Tres Palacios facility and the NYSDEC regulates aspects of our Stagecoach, Thomas Corners, and Steuben natural gas storage facilities and our LPG storage facilities (including both our Bath facility and our Finger Lakes facility under development). Our inability to obtain, maintain or renew any material permit required to operate or expand our storage projects could have an adverse impact on our revenues.

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.

In response to recent major pipeline accidents, including an explosion in a residential neighborhood in San Bruno, California, Congress is considering several bills proposing increased pipeline safety requirements. Among the changes being considered are significantly higher maximum civil penalties, new standards for excess flow and shutoff valves, public accessibility of pipeline information and expansion of safety requirements to classes of pipeline that were formerly exempt. We cannot predict the final outcome of these legislative efforts or the precise impact that compliance with any resulting new requirements may have on our business. Any new or expanded pipeline safety requirements could increase our cost of operation and impair our ability, or the ability of interconnected transportation facilities, to provide service during the period in which assessments and repairs take place, adversely affecting our business.

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

 

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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.

On June 26, 2009, the U.S. House of Representatives approved adoption of the “American Clean Energy and Security Act of 2009,” also known as the “Waxman-Markey cap-and-trade legislation” or “ACESA.” The purpose of ACESA is to control and reduce emissions of “greenhouse gases,” or “GHGs” in the United States. GHGs are certain gases, including carbon dioxide and methane, which may contribute to the warming of the Earth’s atmosphere and other climatic changes. ACESA would establish an economy-wide cap on emissions of GHGs in the United States and would require certain regulated entities to obtain GHG emission “allowances” corresponding to the annual emission of GHGs attributable to their products or operations. Regulated entities under ACESA include producers of NGLs (i.e., natural gas fractionators), local natural gas distribution companies and certain industrial facilities. Under ACESA, the number of authorized emission allowances would decline each year, resulting in an expected and progressive increase in the cost or value of the allowances. The net effect of maintaining emission allowances under ACESA would be to increase the costs associated with the combusting of carbon-based fuels such as natural gas, NGLs (including propane) and refined petroleum products. The U.S. Senate has begun work on its own legislation for controlling and reducing domestic GHG emissions, and President Obama has indicated his support of legislation to reduce GHG emissions through an emission allowance system.

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. 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

 

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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:

 

   

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.

 

   

Although we intend to use our securities as acquisition currency, some prospective sellers may not be willing to accept our securities as consideration.

 

   

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:

 

   

our inability to integrate the operations of recently acquired businesses;

 

   

the diversion of management’s attention from other business concerns;

 

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customer or key employee loss from the acquired businesses; and

 

   

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:

 

   

operating distinct business segments that require different operating strategies and different managerial expertise;

 

   

the necessity of coordinating organizations, systems and facilities in different locations;

 

   

integrating personnel with diverse business backgrounds and organizational cultures; and

 

   

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:

 

   

operating a significantly larger combined organization and integrating additional retail and wholesale distribution operations to our existing supply, marketing and distribution operations;

 

   

coordinating geographically disparate organizations, systems and facilities;

 

   

integrating personnel from diverse business backgrounds and organizational cultures;

 

   

consolidating corporate, technological and administrative functions;

 

   

integrating internal controls, compliance under the Sarbanes-Oxley Act of 2002 and other corporate governance matters;

 

   

the diversion of management’s attention from other business concerns;

 

   

customer or key employee loss from the acquired businesses;

 

   

a significant increase in our indebtedness; and

 

   

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.

 

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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, 2010, we had $1.7 billion of total outstanding indebtedness. Our leverage, various limitations in the agreements governing 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:

 

   

make it more difficult for us to make distributions to our unitholders;

 

   

impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general partnership purposes or other purposes;

 

   

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;

 

   

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;

 

   

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;

 

   

limit our flexibility in planning for, or reacting to, changes in our business and the propane industry; and

 

   

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:

 

   

pay distributions on, redeem or repurchase our equity interests or redeem or repurchase our subordinated debt;

 

   

make investments;

 

   

incur or guarantee additional indebtedness or issue preferred securities;

 

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create or incur certain liens;

 

   

enter into agreements that restrict distributions or other payments from our restricted subsidiaries to us;

 

   

consolidate, merge or transfer all or substantially all of our assets;

 

   

engage in transactions with affiliates;

 

   

create unrestricted subsidiaries; and

 

   

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.

Since we and Holdings announced on August 7, 2010, our entry into the original Merger Agreement, two unitholder class action lawsuits have been filed by Inergy unitholders against us, Inergy Holdings, Inergy GP, certain executive officers and certain members of the Inergy Holdings board of directors. The allegations and status of these lawsuits are more fully described under Part 1, Item 3. Legal Proceedings. The plaintiffs in these lawsuits seek to have the Merger rescinded. The plaintiffs also seek damages and attorneys’ fees from all defendants.

While we do not believe the lawsuits have merit and intend to defend the lawsuits vigorously, we cannot predict the outcome of the lawsuits, or other potential lawsuits related to the transactions contemplated by the Merger Agreement, nor can we predict the amount of time and expense that will be required to resolve the lawsuits. An unfavorable resolution of any such litigation surrounding the transactions contemplated by the Merger Agreement could delay or prevent the consummation of such transactions. In addition, the cost to us of defending the litigation, even if resolved in our favor, could be substantial. Such litigation could also divert the attention of management and resources in general from day-to-day operations.

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

 

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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 or regulations restricting emissions of “greenhouse gasses” could result in increased operating costs and reduced demand for our midstream services.

On December 15, 2009, the U.S. EPA published its findings that emissions of carbon dioxide, methane and other greenhouse gases, or “GHGs,” present an endangerment to public heath and the environment because emissions of such gasses are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climate changes. These findings allow the EPA to adopt and implement regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. The EPA has adopted two sets of regulations under the Clean Air Act. The first limits emissions of GHGs from motor vehicles beginning with the 2012 model year. The EPA has asserted that these final motor vehicle GHG emission standards trigger Clean Air Act construction and operating permit requirements for stationary sources, commencing when the motor vehicle standards take effect on January 2, 2011. On June 3, 2010, the EPA published its final rule to address the permitting of GHG emissions from stationary sources under the Prevention of Significant Deterioration (“PSD”) and Title V permitting programs. This rule “tailors” these permitting programs to apply to certain stationary

 

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sources of GHG emissions in a multi-step process, with the largest sources first subject to permitting. It is widely expected that facilities required to obtain PSD permits for their GHG emissions also will be required to reduce those emissions according to “best available control technology” standards for GHG that have yet to be developed. In addition, in April 2010, the EPA proposed to expand its existing GHG reporting rule to include onshore oil and natural gas production, processing, transmission, storage and distribution facilities. If the proposed rule is finalized as proposed, reporting of GHG emissions from such facilities would be required on an annual basis, with reporting beginning in 2012 for emissions occurring in 2011.

In addition, both houses of Congress have actively considered legislation to reduce emissions of GHGs, and more than one-third of the states, including California, have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring either major sources of emissions such as electric power plants or major producers of fuels such as refineries or natural gas processing plants to acquire and surrender emission allowances, with the number of allowances available for purchase reduced each year until the overall GHG emission reduction goal is achieved. The adoption of any legislation or regulations that requires reporting of GHGs or otherwise limits emissions of GHGs from our equipment and operations could require us to incur costs to monitor and report on GHG emissions or reduce emissions of GHGs associated with our operations, and such requirements also could adversely affect demand for our midstream services. Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts and floods and other climatic events; if any such effects were to occur, they could have an adverse effect on our assets and operations.

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.

 

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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:

 

   

price;

 

   

reliability and quality of service;

 

   

responsiveness to customer needs;

 

   

safety concerns;

 

   

long-standing customer relationships;

 

   

the inconvenience of switching tanks and suppliers; and

 

   

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. (17%) and Sunoco, Inc. (11%), accounted for 28% of propane purchases during the fiscal year ended September 30, 2010. 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.

 

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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 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 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 ASC, our subsidiary and owner of the Thomas Corners facility. The rates and terms and conditions for interstate services provided by Tres Palacios are found in the FERC-approved rates of Tres Palacios Gas Storage, our subsidiary and owner of the Tres Palacios 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

 

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storage provider may be challenged by protest and such increases may ultimately be rejected by FERC. We currently hold authority from FERC to charge and collect market-based rates for services provided at the Stagecoach facility, the Thomas Corners facility and the Tres Palacios facility. There can be no guarantee that we will be allowed to continue to operate under such a rate structure for the remainder of those facilities’ operating lives. Any successful complaint or protest against rates charged for our storage and related services, or our loss of market-based rate authority, could have an adverse impact on our revenues.

In addition, our 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

 

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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 have grown our business is through the expansion of our existing assets, such as the Thomas Corners development, the West Coast expansion project and the Finger Lakes LPG storage expansion project. 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. When 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.

Certain of our expansion projects must receive certificate authority from FERC prior to construction, such as our currently proposed expansions of the Stagecoach natural gas storage facility (CNYOG’s North/South expansion project and Marc I hub line expansion project). We cannot guarantee such certificate authorization will be granted or, if granted, that such authorization will be free of burdensome or expensive conditions.

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.

 

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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, and do not have the 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. John J. Sherman, who currently is the only voting member of the general partner of Inergy Holdings, effectively has the authority to appoint all of our directors. 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:

 

   

the proportionate ownership interest of our existing unitholders in us will decrease;

 

   

the amount of cash available for distribution on each common unit or partnership security may decrease;

 

   

the relative voting strength of each previously outstanding common unit will be diminished; and

 

   

the market price of the common units or partnership securities may decline.

 

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Our managing general partner has conflicts of interest and limited fiduciary responsibilities, which may permit our managing general partner to favor its own interests to the detriment of unitholders.

Inergy Holdings, L.P. owns and controls our managing general partner. 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 managing general partner may favor its own interests and those of its affiliates over the interests of our unitholders. The nature of these conflicts includes the following considerations:

 

   

Our managing general partner may limit its liability and reduce its 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.

 

   

Our managing general partner is allowed to take into account the interests of parties in addition to the partnership in resolving conflicts of interest, thereby limiting its fiduciary duties to our unitholders.

 

   

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.

 

   

Our managing general partner determines whether to issue additional units or other equity securities of the partnership.

 

   

Our managing general partner determines which costs are reimbursable by us.

 

   

Our managing general partner controls the enforcement of obligations owed to us by it.

 

   

Our managing general partner decides whether to retain separate counsel, accountants or others to perform services for us.

 

   

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.

 

   

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 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 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.

 

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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 we were to become subject to a material amount of state or local taxation, 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. Despite the fact that we are organized as a limited partnership under Delaware law, it is possible under current law for a partnership such as ours to be treated as a corporation for federal income tax purposes unless it satisfies requirements regarding the sources of its income. Based on our current operations we believe that we are treated as a partnership rather than a corporation; however, a change in our business could cause us to be treated as a corporation for federal income tax purposes.

In addition, current law may change so as to cause us to be treated as a corporation for federal income tax purposes. For example, members of Congress have recently considered substantive changes to the existing federal income tax laws that would affect the tax treatment of certain publicly traded partnerships. 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. We are unable to predict whether any of these changes, or other proposals, will ultimately be enacted.

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.

If we were treated as a corporation for federal income tax purposes, we would be obligated to pay federal income tax on our taxable income at the corporate tax rate, currently a maximum rate of 35%, as well as any applicable state income tax. Distributions to our unitholders generally would be taxed to them in the same manner as distributions from a corporation, and none of our 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, our treatment as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our common units.

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.

We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes. 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, the costs of any contest with the IRS will be borne indirectly by you and our managing general partner because the costs will reduce our cash available for distribution.

You may be required to pay taxes even if you do not receive cash distributions from us.

Because you will be treated as a partner in us for federal income tax purposes, we will allocate a share of our taxable income to you which could be different in amount than the cash we distribute to you, and you may be required to pay any federal income taxes and, in some cases, state and local income taxes on your share of our taxable income even if you do not receive any cash distributions from us.

 

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Tax gain or loss on disposition of our common units could be more or less than expected.

If you sell your common units, you will recognize a gain or loss equal to the difference between your amount realized and your tax basis in those common units. Because distributions in excess of your allocable share of our total net taxable income result in a reduction in your tax basis in your common units, the amount, if any, of such prior excess distributions with respect to the units you sell will, in effect, become taxable income to you if you sell such units at a price greater than your tax basis in those common units, even if the price you receive is less than your original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture of depreciation deductions. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if you sell your units, you may incur a tax liability in excess of the amount of cash you receive 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 U. S. federal income tax returns and pay tax on their share of our taxable income. If you are a tax-exempt entity or a non-U.S. person, you should consult your tax advisor before investing in our common units.

We treat each purchaser of common units as having the same tax benefits without regard to the specific common units purchased. The IRS may challenge this treatment, which could 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 reporting that they have a higher tax basis in their units than would be the case if the IRS strictly applied Treasury Regulations relating to these depreciation or amortization adjustments. 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 those Treasury Regulations.

The IRS may challenge the manner in which we calculate our unitholder’s basis adjustment under Section 743(b). If so, because the specific unitholders to which this issue relates cannot be identified, the IRS may assert adjustments to all unitholders selling units within the period under audit. 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 or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions. Consequently, a successful IRS challenge could have a negative impact on the value of the common units.

 

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We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of 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.

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 existing Treasury Regulations. Recently, the U.S. Treasury Department issued proposed Treasury Regulations that provide a safe harbor pursuant to which publicly traded partnerships may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge our proration method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units. If so, that unitholder would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.

If you loan your units to a “short seller” to cover a short sale of units, you may be considered as having disposed of the loaned units, and you may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and you may recognize gain or loss from such disposition. During the period of the loan, any of our income, gain, loss or deduction with respect to those units may not be reportable by you and any cash distributions you receive as to those units could be fully taxable as ordinary income. To assure your status as a partner and avoid the risk of gain recognition from a loan to a short seller you are urged to modify any applicable brokerage account agreements to prohibit your broker from borrowing your units.

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.

A partnership is considered to terminate for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in its capital and profits within a twelve-month period. It is anticipated that the proposed merger of Inergy Holdings, L.P. (“Holdings”) through a number of steps with and into our wholly owned subsidiary (the “Transactions”) will result in an exchange of our partnership interests that, together with all other units sold or exchanged within the prior twelve-month period, will represent a sale or exchange of 50% or more of the total interest in our capital and profits. Consequently, we expect that we will be treated as having terminated, and as having been reconstituted, as a partnership for federal income tax purposes as a result of the Transactions. Although our constructive termination should not affect our classification as a partnership for federal income tax purposes, it will result in a deferral of certain deductions allowable in computing our taxable income for the year in which the termination occurs. The effect of this deferral of deductions on unitholders will depend upon each unitholder’s particular situation, including when, and at what prices, the unitholder purchased its common units and the ability of the unitholder to utilize any suspended passive losses.

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 state and local taxes, unincorporated business taxes, estate, inheritance or intangible taxes and foreign 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 various parts of the United States. Unitholders may be required to file state and local income tax returns 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 required U. S. federal, state, local and foreign tax returns.

 

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Item 1B. Unresolved Staff Comments.

None.

Item 2. Properties.

As of October 29, 2010, we owned 212 of our 356 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 25.8 million gallons of propane and butane at eight locations under annual lease agreements. In addition, we own two underground storage facilities with an aggregate capacity of 29.9 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, 2010, we owned the following:

 

   

1,375 bulk storage tanks at approximately 700 locations with typical capacities of 12,000 to 30,000 gallons;

 

   

650,000 stationary customer storage tanks with typical capacities of 100 to 1,200 gallons; and

 

   

225,000 portable propane cylinders with typical capacities of up to 35 gallons.

We own the following midstream assets as discussed in Item 1:

 

   

the Stagecoach natural gas storage facility;

 

   

Finger Lakes LGP storage facility;

 

   

Steuben natural gas storage facility;

 

   

Thomas Corners natural gas storage facility;

 

   

US Salt plant;

 

   

Tres Palacios natural gas storage facility; and

 

   

an NGL business in Bakersfield, California.

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. 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

 

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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.

Following the announcement of the Merger Agreement, two unitholder class action lawsuits were filed by our unitholders in the Court of Chancery of the State of Delaware challenging the proposed merger (Joel A. Gerber v. Inergy GP, LLC et al., No. 5864 and G-2 Trading LLC v. Inergy GP, LLC et al., No. 5816) (collectively, the “Inergy Unitholder Lawsuits”). The plaintiffs in the Inergy Unitholder Lawsuits filed a motion for a temporary injunction and a motion for expedited treatment. The court granted the motion for expedited treatment and consolidated the Inergy Unitholder Lawsuits (the “Consolidated Inergy Action”). In a Memorandum Opinion, dated October 29, 2010, the Delaware Court of Chancery denied the motion for preliminary injunction.

The Consolidated Inergy Action alleges several causes of action challenging the proposed merger, including that the named directors and officers have breached our limited partnership agreement and their fiduciary duties in connection with the proposed merger. Specifically, the Consolidated Inergy Action alleges that we are paying an excessive price to the Inergy Holdings unitholders, thereby diluting the value of Inergy to its current unitholders. The consideration provided to Inergy Holdings unitholders, the Consolidated Inergy Action alleges, represents a 20.7% premium to Inergy Holdings unitholders and exceeds Inergy Holdings’ aggregate enterprise value by 27%. The Consolidated Inergy Action further alleges that the proposed merger will reduce the ownership of our public unitholders prior to the Simplification Transaction from 92% to 57%—without providing an adequate return to those unitholders—so that the named directors and officers can avoid potential tax ramifications related to their Inergy Holdings common units. Additionally, the Consolidated Inergy Action alleges several deficiencies in the process by which the named directors and officers are conducting the proposed transaction. Finally, the plaintiffs in the Consolidated Inergy Action argue that our unitholders must vote on the proposed merger because the Merger Agreement, they allege, constitutes a merger between Inergy and Holdings.

Item 4. Removed and Reserved.

 

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PART II

Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities.

From July 31, 2001 to March 16, 2010, our common units representing limited partner interests were traded on NASDAQ’s Global Select National Market under the symbol “NRGY.” On March 17, 2010, our common units representing limited partner interests began trading on The New York Stock Exchange 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 and the NYSE, as well as the amount of cash distributions declared per common unit for the periods indicated.

 

Quarters Ended:

   Low      High      Cash
Distribution
Per Unit
 

Fiscal 2010:

        

September 30, 2010

   $ 35.56       $ 43.95       $ 0.705   

June 30, 2010

     30.35         39.94         0.705   

March 31, 2010

     32.48         38.04         0.695   

December 31, 2009

     28.70         36.24         0.685   

Fiscal 2009:

        

September 30, 2009

   $ 25.01       $ 30.99       $ 0.675   

June 30, 2009

     21.54         26.34         0.665   

March 31, 2009

     17.06         25.23         0.655   

December 31, 2008

     12.38         22.70         0.645   

As of November 15, 2010, we had issued and outstanding 109,349,510 common units, 4,867,252 Class A units and 11,568,560 Class B units, which were held by 154, 2 and 21 unitholders of record, respectively.

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:

 

   

provide for the proper conduct of our business;

 

   

comply with applicable law, any of our debt instruments, or other agreements; or

 

   

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.

Issuance of Class A Units and Class B Units

On November 5, 2010, in connection with the Simplification Transaction, we issued 4,867,252 Class A units and 11,568,560 Class B units.

 

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Incentive Distribution Rights

Incentive distribution rights represent the right to receive an increasing percentage of quarterly distributions of available cash after a minimum quarterly distribution and certain target distribution levels have been achieved. All incentive distribution rights were eliminated as a result of the Simplification Transaction.

The following table sets forth in tabular format, a summary of our company’s equity compensation plan information as of September 30, 2010:

Equity Compensation Plan Information

 

Plan category

   Number of
securities to be
issued upon
exercise of
outstanding
options, warrants
and rights
     Weighted-
average
exercise
price of
outstanding
options,
warrants
and rights
     Number of securities
remaining available for
future issuance under
equity compensation
plans (excluding
securities reflected in
column (a))
 
     (a)      (b)      (c)  

Equity compensation plans approved by security holders

     —           —           —     

Equity compensation plans not approved by security holders

     42,500       $ 29.60         4,259,774   
                          

Total

     42,500       $ 29.60         4,259,774   
                          

Item 6. Selected Financial Data.

The following tables set 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, 2010, 2009, 2008, 2007 and 2006, 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 income taxes, plus net interest expense 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, long-term incentive and equity compensation expenses and transaction costs. Transaction costs are third party professional fees and other costs that are incurred in conjunction with closing a transaction. 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 provides additional information for evaluating our ability to make the minimum quarterly distribution and is presented solely as a supplemental measure. We believe that Adjusted EBITDA provides additional information for evaluating our financial performance without regard to our financing methods, capital structure and historical cost basis. 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.

 

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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.

 

     Inergy L.P.
Years Ended September 30,
 
     2010     2009     2008     2007     2006  
     (in millions, except per unit and unit data)  

Statement of Operations Data:

          

Revenues

   $ 1,786.0      $ 1,570.6      $ 1,878.9      $ 1,483.1      $ 1,390.2   

Cost of product sold (excluding depreciation and amortization as shown below):

     1,165.9        996.9        1,376.7        1,026.1        993.3   
                                        

Gross profit

     620.1        573.7        502.2        457.0        396.9   

Expenses:

          

Operating and administrative

     309.0        279.6        265.6        247.8        245.2   

Depreciation and amortization

     161.8        115.8        98.0        83.4        76.7   

Loss on disposal of assets

     11.5        5.2        11.5        8.0        11.5   
                                        

Operating income

     137.8        173.1        127.1        117.8        63.5   

Other income (expense):

          

Interest expense, net

     (91.0     (69.7     (60.9     (52.0     (53.8

Other income

     2.0        0.1        1.0        1.9        0.8   
                                        

Income before income taxes

     48.8        103.5        67.2        67.7        10.5   

Provision for income taxes

     0.1        0.7        0.7        0.7        0.7   
                                        

Net income

     48.7        102.8        66.5        67.0        9.8   

Net income attributable to non-controlling partners in ASC’s consolidated net income

     0.7        1.4        1.4        —          —     
                                        

Net income attributable to partners

   $ 48.0      $ 101.4      $ 65.1      $ 67.0      $ 9.8   
                                        

Partners’ interest information:

          

Total interest in net income not attributable to limited partners’

   $ 71.8      $ 50.9      $ 38.2      $ 40.2      $ 19.8   
                                        

Total limited partners’ interest in net income (loss)

   $ (23.8   $ 50.5      $ 26.9      $ 26.8      $ (10.0
                                        

Net income (loss) per limited partner unit:

          

Basic

   $ (0.37   $ 0.93      $ 0.54      $ 0.56      $ (0.24
                                        

Diluted

   $ (0.37   $ 0.93      $ 0.54      $ 0.56      $ (0.24
                                        

Weighted-average limited partners’ units outstanding (in thousands):

          

Basic

     64,533        54,036        49,915        47,784        41,426   
                                        

Diluted

     64,533        54,063        49,989        47,965        41,426   
                                        

Cash distributions paid per unit

   $ 2.76      $ 2.60      $ 2.44      $ 2.28      $ 2.14   
                                        

 

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      2010     2009     2008     2007     2006  

Balance Sheet Data (end of period):

          

Total assets(c)

   $ 3,097.1      $ 2,133.1      $ 2,077.3      $ 1,722.9      $ 1,606.9   

Total debt, including current portion

     1,666.2        1,093.3        1,106.6        710.2        659.7   

Inergy L.P. partners’ capital

     1,189.3        799.4        637.8        741.2        676.1   

Other Financial Data:

          

EBITDA (unaudited)

   $ 300.7      $ 287.1      $ 223.9      $ 203.1      $ 141.0   

Adjusted EBITDA (unaudited)

     325.6        296.8        239.0        211.2        175.4   

Net cash provided by operating activities

     175.3        239.4        183.8        167.9        104.4   

Net cash used in investing activities

     (926.4     (230.6     (386.7     (187.8     (210.9

Net cash provided by (used in) financing activities

     883.8        (14.5     212.5        15.6        109.0   

Maintenance capital expenditures(a) (unaudited)

     9.9        8.0        5.4        5.1        3.7   

Other Operating Data (unaudited):

          

Retail propane gallons sold

     340.2        310.0        331.9        362.2        360.3   

Wholesale propane gallons delivered

     415.3        380.6        358.5        383.9        365.3   

Reconciliation of Net Income to EBITDA and Adjusted EBITDA:

          

Net income attributable to partners

   $ 48.0      $ 101.4      $ 65.1      $ 67.0      $ 9.8   

Interest of non-controlling partners in ASC’s ITDA(b)

     (0.2     (0.5     (0.8     —          —     

Provision for income taxes

     0.1        0.7        0.7        0.7        0.7   

Interest expense, net

     91.0        69.7        60.9        52.0        53.8   

Depreciation and amortization

     161.8        115.8        98.0        83.4        76.7   
                                        

EBITDA

   $ 300.7      $ 287.1      $ 223.9      $ 203.1      $ 141.0   

Non-cash (gain) loss on derivative contracts

     (1.0     1.4        0.1        (0.6     20.0   

Loss on disposal of assets

     11.5        5.2        11.5        8.0        11.5   

Long-term incentive and equity compensation expense

     10.9        3.1        3.5        0.7        2.9   

Transaction costs

     3.5        —          —          —          —     
                                        

Adjusted EBITDA

   $ 325.6      $ 296.8      $ 239.0      $ 211.2      $ 175.4   
                                        

 

(a)

Maintenance capital expenditures are defined as those capital expenditures that do not increase operating capacity or revenues from existing levels.

(b)

ITDA—Interest expense, taxes, depreciation and amortization expense.

(c)

These amounts differ from those previously presented as a result of our adoption of FASB Accounting Standards Codification Subtopic 210-20 on October 1, 2008. In conjunction with the adoption of this standard, we elected to change our accounting policy for derivative instruments executed with the same counterparty under a master netting agreement. This change in accounting policy has been presented retroactively.

 

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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:

 

   

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

 

   

statements preceded by, followed by or that contain forward-looking terminology including the words “believe,” “expect,” “may,” “will,” “should,” “could,” “anticipate,” “estimate,” “intend” or the negation thereof, 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:

 

   

weather conditions;

 

   

price and availability of propane, and the capacity to transport to market areas;

 

   

the ability to pass the wholesale cost of propane through to our customers;

 

   

costs or difficulties related to the integration of the business of our company and its acquisition targets may be greater than expected;

 

   

governmental legislation and regulations;

 

   

local economic conditions;

 

   

the demand for high deliverability natural gas storage capacity in the Northeast;

 

   

the availability of natural gas and the price of natural gas to the consumer compared to the price of alternative and competing fuels;

 

   

our ability to successfully implement our business plan for our natural gas storage facilities;

 

   

labor relations;

 

   

environmental claims;

 

   

competition from the same and alternative energy sources;

 

   

operating hazards and other risks incidental to transporting, storing and distributing propane;

 

   

energy efficiency and technology trends;

 

   

interest rates;

 

   

the price and availability of debt and equity financing; and

 

   

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.

 

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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 four natural gas storage facilities (“Stagecoach”, “Steuben”, “Thomas Corners” and “Tres Palacios”), a liquefied petroleum gas (“LPG”) storage facility (“Finger Lakes LPG”), 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 2010, they evaluated approximately 90 potential acquisitions.

We have grown primarily through acquisitions. Since the inception of our predecessor in November 1996 through September 30, 2010, we have acquired 86 companies, 80 propane companies and 6 midstream businesses, for an aggregate purchase price of approximately $2.1 billion, including working capital, assumed liabilities and acquisition costs.

On December 31, 2009, we acquired the partnership interests of Liberty Propane, LP (“Liberty”) headquartered in Overland Park, Kansas. At the time it was acquired, Liberty delivered propane to nearly 100,000 customers from 38 customer service centers in the Northeast, Mid-Atlantic and Western regions of the United States. On January 12, 2010, we acquired the propane assets of MGS Corporation (“MGS”), headquartered in Hackensack, New Jersey. At the time it was acquired, MGS delivered propane to nearly 6,400 customers from five customer service centers. The purchase price allocations for these acquisitions were completed during the year ended September 30, 2010. Changes to final asset valuation of prior fiscal year acquisitions have been included in our consolidated financial statements but are not material.

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

 

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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 1980 through 2010. 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 continued to be volatile during 2010. At the main pricing hub of Mount Belvieu Texas during the fiscal year ended September 30, 2010, propane prices ranged from a low of $0.93 per gallon to a high of $1.44 per gallon and a price of $1.20 per gallon at September 30, 2010. 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. Propane is a by-product of both crude oil refining and natural gas processing and thus typically follows the same pricing pattern as these two commodities with crude oil pricing being the more influential of the two historically. The prices of crude oil and natural gas had maintained historically high costs in calendar year 2007 and 2008 before both began to fall rather dramatically in late 2008 and throughout the 2008-2009 winter season. While natural gas pricing has remained at historically low levels since the decline, crude oil costs leveled off in the spring 2009 before beginning another increase that persisted through the 2009-2010 winter season with propane prices following a similar pattern for the majority of this time. 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:

 

   

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

 

   

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 the solution mining operations of US Salt. 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 predominantly 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 markets in the northeastern and southeastern 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 three significant capital projects related to our midstream operations: (1) Finger Lakes LPG storage expansion, (2) North/South Pipeline Compression Project and (3) MARC I Hub Line Project. 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 2011.

The North/South Project consists of adding additional compression and measurement facilities to our existing Stagecoach Laterals and when completed is expected to have firm transportation capacity of 325,000 dekatherms per day. The North/South Project is supported by long-term contracts and is expected to be placed into service by late 2011.

 

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The MARC I Hub Line Project is a 43 mile, 30” bi-directional pipeline located in Bradford, Sullivan, and Lycoming counties in Pennsylvania. The planned pipeline will extend between our Stagecoach South Lateral Interconnect with TGP near its compressor station 319 and Transco near its compressor station 517. The MARC I Hub Line Project is expected to have a minimum of 550,000 dekatherms per day of firm transportation capacity. We expect the MARC I Hub Line Project to be placed into service in mid-2012.

Our MARC I Hub Line Project and the North/South Project, when placed into service, will allow us to wheel volumes on a firm transportation basis through approximately 75 miles of pipe to and from Tennessee Gas Pipeline Company’s (“TGP”) 300 Line (“TGP”), Transco’s Leidy Line (“Transco”) and the Millennium Pipeline and all points in between. The two projects combined are expected to add over 45,000 horsepower of additional compression and 875,000 dekatherms per day of transportation capacity to our midstream business in the Northeast.

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, 2010, of $12.3 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.

Recent Developments

On August 7, 2010, Inergy and Holdings entered into an Agreement and Plan of Merger, which was amended and restated by the First Amended and Restated Agreement and Plan of Merger, dated as of September 3, 2010, as part of a plan to simplify the capital structures of Inergy and Holdings (the “Merger Agreement”). Pursuant to the steps contemplated by the Merger Agreement (the “Simplification Transaction”), Inergy Holdings merged into a wholly owned subsidiary of its general partner (the “Merger”) and the outstanding common units in Inergy Holdings were cancelled. The Merger closed on November 5, 2010, resulting in Holdings unitholders receiving 0.77 Inergy units for each Holdings unit. Cash will be paid to Holdings unitholders in lieu of any fractional units that would have resulted from the exchange. As a result of the closing, Holdings’ common units discontinued trading on the New York Stock Exchange as of the close of business on November 5, 2010.

On October 14, 2010, we completed the acquisition of Tres Palacios Gas Storage, LLC. Tres Palacios Gas Storage, LLC is the owner and operator of a natural gas storage facility located in Matagorda County, Texas (“Tres Palacios”). Tres Palacios is a high deliverability, salt dome natural gas storage facility with approximately 38.4 bcf of working gas capacity (Caverns 1-3). The facility is expandable by an additional 9.5 bcf of working gas capacity which we expect to place in service by or before 2014 (Cavern 4). Located approximately 100 miles southwest of Houston, Tres Palacios is currently connected to a total of ten intrastate and interstate pipelines offering connectivity to multiple demand markets including the Houston and San Antonio metropolitan areas and the broader Texas markets as well as markets in the Northeast, Midwest, Southeast, Florida and Mid-Atlantic United States and Mexico. Tres Palacios offers customers greater than six-turn gas storage capability with maximum withdrawal capacity of 2.5 bcf per day and maximum injection capacity of 1 bcf per day.

 

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Results of Operations

Fiscal Year Ended September 30, 2010 Compared to Fiscal Year Ended September 30, 2009

The following table summarizes the consolidated income statement components for the fiscal years ended September 30, 2010 and 2009, respectively (in millions):

 

     Year Ended
September 30,
    Change  
     2010     2009     In Dollars     Percentage  

Revenue

   $ 1,786.0      $ 1,570.6      $ 215.4        13.7

Cost of product sold

     1,165.9        996.9        169.0        17.0   
                          

Gross profit

     620.1        573.7        46.4        8.1   

Operating and administrative expenses

     309.0        279.6        29.4        10.5   

Depreciation and amortization

     161.8        115.8        46.0        39.7   

Loss on disposal of assets

     11.5        5.2        6.3        121.2   
                          

Operating income

     137.8        173.1        (35.3     (20.4

Interest expense, net

     (91.0     (69.7     (21.3     (30.6

Other income

     2.0        0.1        1.9        1,900.0   
                          

Income before income taxes

     48.8        103.5        (54.7     (52.9

Provision for income taxes

     0.1        0.7        (0.6     (85.7
                          

Net income

     48.7        102.8        (54.1     (52.6

Net income attributable to non-controlling partners in ASC’s consolidated net income

     0.7        1.4        (0.7     (50.0
                          

Net income attributable to partners

   $ 48.0      $ 101.4      $ (53.4     (52.7 )% 
                                

The following table summarizes revenues, including associated volume of gallons sold, for the years ended September 30, 2010 and 2009, respectively (in millions):

 

    Revenues     Gallons  
    Year Ended
September 30,
    Change     Year Ended
September 30,
    Change  
    2010     2009     In Dollars     Percent     2010     2009     In Units     Percent  

Retail propane

  $ 796.5      $ 736.7      $ 59.8        8.1     340.2        310.0        30.2        9.7

Wholesale propane

    475.9        387.7        88.2        22.7        415.3        380.6        34.7        9.1   

Other retail

    194.5        209.2        (14.7     (7.0     —          —          —          —     

Storage, fractionation and other midstream

    319.1        237.0        82.1        34.6        —          —          —          —     
                                                   

Total

  $ 1,786.0      $ 1,570.6      $ 215.4        13.7     755.5        690.6        64.9        9.4
                                                               

Volume. During fiscal 2010, we sold 340.2 million retail gallons of propane, an increase of 30.2 million gallons or 9.7% from the 310.0 million retail gallons of propane sold during fiscal 2009. Gallons sold during fiscal 2010 increased compared to fiscal 2009 as a result of acquisition-related volume of 49.9 million gallons partially offset by a 19.7 million gallon decline from lower volumes sold at our existing locations. The primary cause of the declining volumes at existing locations was (1) continued customer conservation, which we believe has resulted from the overall weak United States economic environment and to a lesser extent the lingering effects of higher propane costs, which have been at record high prices the past several years, (2) an abrupt end to the 2009/2010 winter heating season and (3) volume declines from net customer losses. Also impacting volumes sold during fiscal 2010 compared to fiscal 2009 was the weather in certain areas of our operations. Based on our calculations using degree day data provided by NOAA, the Southern and Southeast areas of the United States were significantly colder than the prior year period; however gallon gains realized in these areas were somewhat offset

 

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by degree day losses in the Eastern and certain Northern parts of our areas of operations. In total, the weather in our areas of operations was 1% colder than normal and 2% colder than last year.

Wholesale gallons delivered increased 34.7 million gallons, or 9.1%, to 415.3 million gallons in fiscal 2010 from 380.6 million gallons in fiscal 2009. 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 67.3 million gallons, or 23.8%, to 349.9 million gallons in fiscal 2010 from 282.6 million gallons in fiscal 2009. This increase was primarily attributable to the Butamer addition in July 2009 and new terminalling contracts.

During fiscal 2010 and 2009, our Northeast natural gas and LPG storage facilities were 100% contracted.

Revenues. Revenues in fiscal 2010 were $1,786.0 million, an increase of $215.4 million, or 13.7% from $1,570.6 million in fiscal 2009.

Revenues from retail propane sales were $796.5 million for the year ended September 30, 2010, an increase of $59.8 million, or 8.1%, compared to $736.7 million for the year ended September 30, 2009. This increase was primarily due to acquisition-related sales, which resulted in higher retail propane revenues of $117.8 million, partially offset by a combination of a decline in gallons sold to existing customers as described above and a slightly lower overall average retail selling price of propane in fiscal 2010, which contributed a revenue decline of $47.0 million and $11.0 million, respectively.

Revenues from wholesale propane sales were $475.9 million in fiscal 2010, an increase of $88.2 million or 22.7%, from $387.7 million in fiscal 2009. This increase resulted from the greater volumes of propane sold which contributed $35.3 million to the increase in revenues and the higher average wholesale sales price of propane which contributed to $52.9 million of the increase as a result of higher product costs.

Revenues from other retail sales, which primarily include distillates, service, rental, appliance sales and transportation services, were $194.5 million in fiscal 2010, a decrease of $14.7 million, or 7.0% from $209.2 million in fiscal 2009. Revenue from other retail sales declined as a result of lower distillate revenues at existing locations of $18.3 million and a $5.5 million decline in revenues from other products and services, partially offset by a $9.1 million increase from acquisition-related sales. Distillate revenues from existing locations decreased primarily as a result of lower volumes sold. Weather in our distillate areas of operations was 6% warmer than last year and 5% warmer than normal.

Revenues from storage, fractionation and other midstream activities were $319.1 million in fiscal 2010, an increase of $82.1 million or 34.6% from $237.0 million in fiscal 2009. Revenues from our West Coast NGL operations increased $72.0 million primarily as a result of increased commodity sales and processing fees associated with the Butamer addition. Higher average selling prices of natural gas liquids also contributed to the revenue increase. Revenues resulting from the in-servicing of our Thomas Corners facility and the related firm storage contracts resulted in a combined increase of $6.2 million. Additionally, revenues from our US Salt operations increased $3.2 million due to price increases and product mix management.

Cost of Product Sold. Cost of product sold for fiscal 2010 was $1,165.9 million, an increase of $169.0 million, or 17.0%, from $996.9 million in fiscal 2009.

Retail propane cost of product sold was $413.7 million for the year ended September 30, 2010, compared to $373.6 million for the year ended September 30, 2009. This $40.1 million, or 10.7%, increase was primarily due to a $68.0 million increase associated with acquisition-related volume, partially offset by a reduction of retail propane cost of product sold from existing locations of $25.5 million. The decline in retail propane cost of product sold from existing locations resulted primarily from lower volume sales as discussed above. Also

 

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contributing to the decline in retail propane cost of product sold was a $2.4 million decrease due 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 2010 was $449.2 million, an increase of $85.4 million or 23.5%, from wholesale cost of product sold of $363.8 million in fiscal 2009. This increase resulted from the greater volumes of propane purchased which contributed $33.2 million to the increase in cost and the higher average purchase price of wholesale propane sold which contributed $52.2 million of the increase as a result of higher commodity prices.

Other retail cost of product sold was $113.1 million for the year ended September 30, 2010, compared to $124.8 million for the year ended September 30, 2009. This $11.7 million, or 9.4%, decrease was primarily due to lower costs from distillate sales at existing locations of $15.1 million and a decline in costs for other products and services of $0.9 million, partially offset by a $4.3 million increase in the cost of product sold associated with acquisition-related sales. The cost of product sold for distillates declined primarily as a result of lower volumes sold at existing locations.

Storage, fractionation and other midstream cost of product sold was $189.9 million, an increase of $55.2 million, or 41.0%, from $134.7 million in fiscal 2009. Costs from our West Coast NGL operations were $62.2 million higher primarily as a result of increased commodity sales associated with the Butamer addition. Increases in the cost of natural gas liquids also contributed to the West Coast NGL cost of products sold increase. This increase was partially offset by lower costs of storage and operational efficiencies at our Stagecoach, US Salt and Finger Lakes LPG facilities.

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 $67.0 million and $62.0 million for fiscal 2010 and 2009, respectively. In addition, the depreciation expense associated with the delivery vehicles and customer tanks is reported within depreciation and amortization expense and amounted to $32.8 million and $33.0 million in fiscal 2010 and 2009, 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.

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 $73.6 million and $36.9 million for fiscal 2010 and 2009, respectively. Vehicle costs combined with wages for personnel directly involved in providing midstream services amounted to $2.9 million and $2.7 million for fiscal 2010 and 2009, 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 2010 was $620.1 million, an increase of $46.4 million, or 8.1%, from $573.7 million during fiscal 2009.

Retail propane gross profit was $382.8 million in fiscal 2010, an increase of $19.7 million, or 5.4%, compared to $363.1 million in fiscal 2009. This increase in retail propane gross profit was attributable to a $49.8 million increase from acquisitions and a $2.4 million increase related to changes in non-cash charges on derivative contracts associated with retail propane fixed price sales contracts as discussed above. These factors, which

 

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increased retail propane gross profit, were partially offset by a $23.3 million decline resulting from lower retail gallon sales at existing locations as discussed above and a $9.2 million decline arising from a lower cash margin per gallon. The decline in cash margin per gallon was primarily the result of a steep escalation in propane costs during the winter heating season contrasted with a period of falling propane costs in the prior year winter.

Wholesale propane gross profit was $26.7 million in fiscal 2010 compared to $23.9 million in fiscal 2009, an increase of $2.8 million or 11.7%. The increase in gross profit was primarily the result of both increased volumes sold and higher margins that we were able to generate from new and existing customers.

Other retail gross profit was $81.4 million for the year ended September 30, 2010, compared to $84.4 million for the year ended September 30, 2009. This $3.0 million, or 3.6%, decrease was due primarily to lower gross profit on other products and services and distillates of $4.6 million and $3.2 million, respectively, partially offset by a $4.8 million increase in related gross profit from acquisitions.

Storage, fractionation and other midstream gross profit was $129.2 million in fiscal 2010 compared to $102.3 million in fiscal 2009, an increase of $26.9 million, or 26.3%. This increase was primarily attributable to additional West Coast NGL contracts due to the Butamer addition in July 2009 and margin improvements as a result of changes in the variety of natural gas liquids sold, resulting in a $9.8 million increase. Additionally, gross profit increased $7.7 million due to the Thomas Corners facility being placed in service. Lower costs of storage and operational efficiencies at our Stagecoach, US Salt and Finger Lakes LPG facilities also contributed to the increased gross profit in fiscal 2010.

Operating and Administrative Expenses. Operating and administrative expenses were $309.0 million in fiscal 2010 compared to $279.6 million in fiscal 2009. This $29.4 million, or 10.5%, increase in operating expenses was due primarily to an increase in long-term incentive compensation of $7.8 million, operations of acquisitions of $29.9 million and $3.6 million of transaction expenses primarily related to those acquisitions. These types of transaction costs were capitalized in previous years, but are now required to be expensed under the new accounting rules. This increase was offset by a decrease in operating expenses of $11.9 million from other existing operations comprised predominately of lower payroll, insurance and other operating expenses.

Depreciation and Amortization. Depreciation and amortization increased to $161.8 million in fiscal 2010 from $115.8 million in fiscal 2009. This $46.0 million, or 39.7%, increase resulted primarily from the West Coast Butamer expansion project together with our other midstream segment projects and acquisitions.

Loss on Disposal of Assets. Loss on disposal of assets increased $6.3 million, or 121.2%, to $11.5 million in fiscal 2010 compared to $5.2 million in fiscal 2009. The losses recognized in fiscal 2010 and 2009 include losses of $9.7 million and $4.9 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 2010 and fiscal 2009 of $1.8 million and $0.3 million, respectively. 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 2010 and 2009, these assets were identified primarily as a result of losses due to disconnecting customer installations of less profitable accounts due to low margins, poor payment history or low volume usage and customers who have chosen to switch suppliers.

Interest Expense. Interest expense increased to $91.0 million in fiscal 2010 compared to $69.7 million in fiscal 2009. This $21.3 million, or 30.6%, increase was primarily attributable to higher average interest rates incurred on our borrowings and to a lesser extent an increase in the average outstanding borrowings during the period. Additionally, during fiscal 2010 and 2009, we capitalized $6.3 million and $14.8 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 (approximately 55%) in the operations of Steuben when we acquired 100% of the membership interest in ASC in

 

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October 2007. In January 2010, we acquired an additional 25% interest in Steuben and in April 2010 and July 2010, we acquired an additional 10% interest in Steuben. These acquisitions gave us 100% ownership of Steuben.

Net Income Attributable to Partners. Net income for fiscal 2010 was $48.0 million compared to net income for fiscal 2009 of $101.4 million. The $53.4 million, or 52.7%, decrease in net income was primarily attributable to increased depreciation and amortization ($46.0 million), operating and administrative expenses ($29.4 million) and interest expense ($21.3 million) in fiscal 2010, partially offset by a higher gross profit ($46.4 million).

EBITDA and Adjusted EBITDA. The following tables summarize EBITDA and Adjusted EBITDA for the fiscal years ended September 30, 2010 and 2009, respectively (in millions):

 

     Year Ended
September 30,
 
     2010     2009  

EBITDA:

    

Net income attributable to partners

   $ 48.0      $ 101.4   

Interest of non-controlling partners in ASC’s consolidated ITDA(a)

     (0.2     (0.5

Interest expense, net

     91.0        69.7   

Provision for income taxes

     0.1        0.7   

Depreciation and amortization

     161.8        115.8   
                

EBITDA

   $ 300.7      $ 287.1   
                

Non-cash (gain) loss on derivative contracts

     (1.0     1.4   

Long-term incentive and equity compensation expense

     10.9        3.1   

Loss on disposal of assets

     11.5        5.2   

Transaction costs

     3.5        —     
                

Adjusted EBITDA

   $ 325.6      $ 296.8   
                

 

(a)

ITDA—Interest expense, taxes, depreciation and amortization expense.

 

     Year Ended
September 30,
 
     2010     2009  

EBITDA:

    

Net cash provided by operating activities

   $ 175.3      $ 239.4   

Net changes in working capital balances

     61.6        (3.6

Provision for doubtful accounts

     (2.8     (3.7

Amortization of deferred financing costs and net bond discount

     (7.3     (5.2

Unit-based compensation expense

     (4.8     (3.1

Loss on disposal of assets

     (11.5     (5.2

Interest of non-controlling partners in ASC’s consolidated EBITDA

     (0.9     (1.9

Interest expense, net

     91.0        69.7   

Provision for income taxes

     0.1        0.7   
                

EBITDA

   $ 300.7      $ 287.1   
                

Non-cash (gain) loss on derivative contracts

     (1.0     1.4   

Long-term incentive and equity compensation expense

     10.9        3.1   

Loss on disposal of assets

     11.5        5.2   

Transaction costs

     3.5        —     
                

Adjusted EBITDA

   $ 325.6      $ 296.8   
                

 

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EBITDA is defined as income before income taxes, plus net interest expense and depreciation and amortization expense. For the years ended September 30, 2010 and 2009, EBITDA was $300.7 million and $287.1 million, respectively. 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, long-term incentive and equity compensation expenses and transaction costs. Transaction costs are third party professional fees and other costs that are incurred in conjunction with closing a transaction. Adjusted EBITDA was $325.6 million for fiscal 2010 compared to $296.8 million in fiscal 2009. 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 provides additional information for evaluating our ability to make the minimum quarterly distribution and is presented solely as a supplemental measure. We believe that Adjusted EBITDA provides additional information for evaluating our financial performance without regard to our financing methods, capital structure and historical cost basis. Further, 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, 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):

 

     Year Ended
September 30,
    Change  
     2009     2008     In Dollars     Percentage  

Revenue

   $ 1,570.6      $ 1,878.9      $ (308.3     (16.4 )% 

Cost of product sold

     996.9        1,376.7        (379.8     (27.6
                          

Gross profit

     573.7        502.2        71.5        14.2   

Operating and administrative expenses

     279.6        265.6        14.0        5.3   

Depreciation and amortization

     115.8        98.0        17.8        18.2   

Loss on disposal of assets

     5.2        11.5        (6.3     (54.8
                          

Operating income

     173.1        127.1        46.0        36.2   

Interest expense, net

     (69.7     (60.9     (8.8     (14.4

Other income

     0.1        1.0        (0.9     (90.0
                          

Income before income taxes

     103.5        67.2        36.3        54.0   

Provision for income taxes

     0.7        0.7        —          —     
                          

Net income

     102.8        66.5        36.3        54.6   

Net income attributable to non-controlling partners in ASC’s consolidated net income

     1.4        1.4        —          —     
                          

Net income attributable to partners

   $ 101.4      $ 65.1      $ 36.3        55.8
                                

 

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The following table summarizes revenues, including associated volume of gallons sold, for the years ended September 30, 2009 and 2008, respectively (in millions):

 

    Revenues     Gallons  
    Year Ended
September 30,
    Change     Year Ended
September 30,
    Change  
    2009     2008     In Dollars     Percent     2009     2008     In Units     Percent  

Retail propane

  $ 736.7      $ 840.7      $ (104.0     (12.4 )%      310.0        331.9        (21.9     (6.6 )% 

Wholesale propane

    387.7        546.1        (158.4     (29.0     380.6        358.5        22.1        6.2   

Other retail

    209.2        223.0        (13.8     (6.2     —          —          —          —     

Storage, fractionation and other midstream

    237.0        269.1        (32.1     (11.9     —          —          —          —     
                                                   

Total

  $ 1,570.6      $ 1,878.9      $ (308.3     (16.4 )%      690.6        690.4        0.2        —  
                                                               

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 23.5 million gallons, or 9.1%, to 282.6 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

 

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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 Finger Lakes LPG facility and Stagecoach 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.

 

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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 our West Coast NGL 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

 

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$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 held a majority interest in the operations of Steuben until July 2010.

Net Income Attributable to Partners. 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):

 

     Year Ended
September 30,
 
     2009     2008  

EBITDA:

    

Net income attributable to partners

   $ 101.4      $ 65.1   

Interest of non-controlling partners in ASC’s consolidated ITDA(a)

     (0.5     (0.8

Interest expense, net

     69.7        60.9   

Provision for income taxes

     0.7        0.7   

Depreciation and amortization

     115.8        98.0   
                

EBITDA

   $ 287.1      $ 223.9   
                

Non-cash loss on derivative contracts

     1.4        0.1   

Long-term incentive and equity compensation expense

     3.1        3.5   

Loss on disposal of assets

     5.2        11.5   
                

Adjusted EBITDA

   $ 296.8      $ 239.0   
                

 

(a)

ITDA—Interest expense, taxes, depreciation and amortization expense.

 

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     Year Ended
September 30,
 
     2009     2008  

EBITDA:

    

Net cash provided by operating activities

   $ 239.4      $ 183.8   

Net changes in working capital balances

     (3.6     3.7   

Provision for doubtful accounts

     (3.7     (5.7

Amortization of deferred financing costs and net bond discount

     (5.2     (2.3

Unit based compensation expense

     (3.1     (3.5

Loss on disposal of assets

     (5.2     (11.5

Interest of non-controlling partners in ASC’s consolidated EBITDA

     (1.9     (2.2

Interest expense, net

     69.7        60.9   

Provision for income taxes

     0.7        0.7   
                

EBITDA

   $ 287.1      $ 223.9   
                

Non-cash loss on derivative contracts

     1.4        0.1   

Long-term incentive and equity compensation expense

     3.1        3.5   

Loss on disposal of assets

     5.2        11.5   
                

Adjusted EBITDA

   $ 296.8      $ 239.0   
                

EBITDA is defined as income before income 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. 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 long-term incentive and equity 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 provides additional information for evaluating our ability to make the minimum quarterly distribution and is presented solely as a supplemental measure. We believe that Adjusted EBITDA provides additional information for evaluating our financial performance without regard to our financing methods, capital structure and historical cost basis. Further, 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.

 

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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. In January 2010 and September 2010, we issued 5,749,100 common units (which included 749,100 common units issued as the result of the underwriters exercising their over-allotment provision) and 11,787,500 common units (which included 1,537,500 common units issued as a result of the underwriters exercising their over-allotment provision), respectively. The proceeds from these issuances were utilized to repay outstanding indebtedness under our revolving general partnership and working capital credit facilities and to fund the purchase price of acquisitions. We have $396.9 million remaining under this shelf registration statement.

Cash Flows and Contractual Obligations

Net operating cash inflows were $175.3 million and $239.4 million for the fiscal years ended September 30, 2010 and 2009, respectively. The $64.1 million decrease in operating cash flows was attributable to net decreases in cash components of net income attributable to partners and changes in working capital balances.

Net investing cash outflows were $926.4 million and $230.6 million for the fiscal years ended September 30, 2010 and 2009, respectively. Net cash outflows were primarily impacted by a $588.0 investment in escrow account and a $240.9 million increase in cash outlays related to acquisitions, partially offset by a $132.5 million decrease in capital expenditures.

Net financing cash inflows (outflows) were $883.8 million and $(14.5) million for the fiscal years ended September 30, 2010 and 2009, respectively. The net change was primarily impacted by a $582.7 million increase in proceeds related to the issuance of long-term debt, net of payments on long-term debt, and a $401.5 million increase in proceeds from the issuance of common units, partially off set by a $57.7 million increase in total distributions paid, an acquisition of minority interest of $18.3 million and an $18.1 million increase in payments for deferred financing costs.

Net operating cash inflows were $239.4 million and $183.8 million for fiscal years ended 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 ended 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 ended 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.

At September 30, 2010 and 2009, we had goodwill of $424.1 million and $374.3 million, respectively, representing 14% and 18% of total assets in each year, respectively. This goodwill is attributable to our acquisitions.

At September 30, 2010, we were in compliance with all debt covenants to our credit facilities.

 

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The following table summarizes our contractual obligations as of September 30, 2010 (in millions):

 

     Total      Less than
1 year
     1-3 years      4-5 years      After
5  years
 

Aggregate amount of principal and interest to be paid on the outstanding long-term debt(a)

   $ 2,402.6       $ 130.5       $ 257.5       $ 869.4       $ 1,145.2   

Future minimum lease payments under noncancelable operating leases

     44.6         11.9         17.8         10.0         4.9   

Fixed price purchase commitments(c)

     259.3         250.0         9.3         —           —     

Standby letters of credit

     19.7         15.5         4.2         —           —     

Purchase commitments of identified growth projects(b)

     12.3         12.3         —           —           —     
                                            

Total contractual obligations

   $ 2,738.5       $ 420.2       $ 288.8       $ 879.4       $ 1,150.1   
                                            

 

(a)

None of our long-term debt is variable interest rate debt at September 30, 2010.

(b)

Identified growth projects related to the Thomas Corners and Finger Lakes LPG midstream assets.

(c)

Fixed price purchase commitments are offset by sales contracts that are included in our cash flow hedging program 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. While global financial markets and economic conditions have been disrupted and volatile in the past, the conditions have improved more recently. However, we give no assurance that we can raise additional capital to meet these needs. 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 are 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 November 24, 2009, we entered into a secured credit facility (“Credit Agreement”) which provides borrowing capacity of up to $525 million in the form of a $450 million revolving general partnership credit facility (“General Partnership Facility”) and a $75 million working capital credit facility (“Working Capital Facility”). This facility replaces our former senior credit facility due 2010. This new facility will mature on November 22, 2013. The Credit Agreement accrues interest at either prime rate or LIBOR plus applicable spreads. At September 30, 2010, there were no borrowings outstanding under the Credit Agreement. 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 requirement on April 30, 2010.

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.

 

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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);

 

   

make investments, loans and acquisitions;

 

   

enter into a merger, consolidation or sale of assets;

 

   

enter into any sale-leaseback transaction or enter into any new business;

 

   

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;

 

   

enter into certain affiliate transactions;

 

   

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 $40 million in any fiscal year;

 

   

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;

 

   

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:

 

   

our $425 million 6.875% senior notes due December 15, 2014 that were issued on December 22, 2004;

 

   

our $200 million 8.25% senior notes due March 1, 2016 that were issued on January 11, 2006;

 

   

our $200 million 8.25% senior notes due March 1, 2016 that were issued on April 29, 2008;

 

   

our $225 million 8.75% senior notes due March 1, 2015 that were issued on February 2, 2009;

 

   

our $600 million 7.00% senior notes due October 1, 2018 that were issued on September 27, 2010;

 

   

other debt that is substantially similar to the 6.875% senior notes; and

 

   

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 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 $150 million and 4.75 to 1.0 at all other times;

 

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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%, 8.75% and 7.00% 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 $150 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, 2010, our ratio of total funded debt to consolidated EBITDA was 4.38 to 1.0, and our ratio of consolidated EBITDA to consolidated interest expense was 3.17 to 1.0.

Each of the following is an event of default under the Credit Agreement:

 

   

default in payment of principal when due;

 

   

default in payment of interest, fees or other amounts within three days of their due date;

 

   

violation of specified affirmative and negative covenants;

 

   

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;

 

   

specified cross-defaults;

 

   

bankruptcy and other insolvency events of us or our material subsidiaries;

 

   

impairment of the enforceability or the validity of agreements relating to the Credit Agreement;

 

   

judgments exceeding $10 million (to the extent not covered by insurance) against us or any of our subsidiaries are undischarged or unstayed for 45 consecutive days;

 

   

certain defaults under ERISA that could reasonably be expected to result in a material adverse effect on us; or

 

   

the occurrence of certain change of control events with respect to us.

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.

 

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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.

 

Year

   Percentage  

2009

     103.438

2010

     102.292

2011

     101.146

2012 and thereafter

     100.000

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.

 

Year

   Percentage  

2011

     104.125

2012

     102.750

2013

     101.375

2014 and thereafter

     100.000

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

 

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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.

 

Year

   Percentage  

2013

     104.375

2014 and thereafter

     100.000

2018 Senior Notes

On September 27, 2010, we and our wholly-owned subsidiary, Inergy Finance Corp, issued $600 million aggregate principal amount of 7% senior unsecured notes due 2018 (the “2018 Senior Notes”) under Rule 144A to eligible purchasers. The 7% notes mature on October 1, 2018.

The 2018 Senior Notes contain covenants similar to our existing senior unsecured notes due 2014, 2015 and 2016. We intend to use the net proceeds of the offering to fund part of the consideration for the Tres Palacios acquisition (see Note 16). The 2018 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 2018 Senior Notes are fully, unconditionally, jointly and severally guaranteed by all of our wholly-owned domestic subsidiaries.

The 2018 Senior Notes are redeemable, at our option, in whole or in part, at any time on or after October 1, 2014, in each case at the redemption prices described in the table below, together with any accrued and unpaid interest to the date of the redemption.

 

Year

   Percentage  

2014

     103.500

2015

     101.750

2016 and thereafter

     100.000

 

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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;

 

   

pay distributions on, redeem or repurchase our units or redeem or repurchase our subordinated debt;

 

   

make investments;

 

   

incur or guarantee additional indebtedness or issue preferred units;

 

   

create or incur certain liens;

 

   

enter into agreements that restrict distributions or other payments from our restricted subsidiaries to us;

 

   

consolidate, merge or transfer all or substantially all of our assets;

 

   

engage in transactions with affiliates; and

 

   

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 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. We adopted 810-10 on October 1, 2009. The adoption of 810-10 did not have a material impact on our results of operations or financial position.

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, IDRs. We adopted 260-10 on October 1, 2009, and the impact on our earnings per unit calculation has been retrospectively applied.

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. We adopted 260-10 on October 1, 2009. The adoption of 260-10 did not have a significant impact on our earnings per unit calculation.

 

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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 commodity 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. 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.

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 periodically 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. The commodity 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 $0.4 million net gain in the year ended September 30, 2010, related to the ineffective portion of our fair value hedging instruments. In addition, for the year ended September 30, 2010, 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 was $4.4 million and $11.0 million at

 

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September 30, 2010 and 2009, respectively. Approximately $4.9 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 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, 2010, and would have affected net income by an immaterial amount for the year ended September 30, 2010.

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 Goodwill and 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, 2010. 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. 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 $0.4 million at September 30, 2010.

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 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. 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

 

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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, 2010 and 2009, our self-insurance reserves were $19.3 million.

Factors That May Affect Future Results of Operations, Financial Condition or Business

 

   

We may not be able to generate sufficient cash from operations to allow us to pay the minimum quarterly distribution.

 

   

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.

 

   

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.

 

   

If we do not continue to make acquisitions on economically acceptable terms, our future financial performance will be reliant upon internal growth and efficiencies.

 

   

We cannot assure you that we will be successful in integrating our recent acquisitions.

 

   

Sudden and sharp propane price increases that cannot be passed on to customers may adversely affect our profit margins.

 

   

Our indebtedness may limit our ability to borrow additional funds, make distributions to unitholders or capitalize on acquisition or other business opportunities.

 

   

The highly competitive nature of the retail propane business could cause us to lose customers, thereby reducing our revenues.

 

   

If we are not able to purchase propane from our principal suppliers, our results of operations would be adversely affected.

 

   

Competition from alternative energy sources may 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.

 

   

We are subject to operating and litigation risks that could adversely affect our operating results to the extent not covered by insurance.

 

   

Our results of operations and financial condition may be adversely affected by governmental regulation and associated environmental regulatory costs.

 

   

Energy efficiency and new technology may reduce the demand for propane.

 

   

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.

 

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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, 2010, we had no floating rate obligations borrowed under our Credit Agreement. Floating rate obligations expose us to the risk of increased interest expense in the event of increases in short-term interest rates.

Certain counterparties elected to call their respective interest rate swap positions in December 2009 and April 2010. The aggregate notional amount associated with these swaps amounted to $125 million and $25 million. We elected to cancel our remaining interest rate swap positions of $75 million in August 2010. The Company received $4.3 million, $0.9 million and $3.2 million in December 2009, April 2010 and August 2010, respectively, in consideration for the cancellation of the swaps.

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, 2010 and 2009, 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, 2010, and September 30, 2009, was assets of $22.5 million and $23.8 million, respectively and liabilities of $24.3 million and $29.3 million, respectively.

 

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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 $0.1 million change in the market value of the contracts as there were 0.5 million gallons of net unbalanced positions at September 30, 2010.

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. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.

None.

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, 2010, 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) during the period ended September 30, 2010, that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

Changes in Internal Control over Financial Reporting

On December 31, 2009, we completed our acquisition of Liberty. See Note 4 “Acquisitions” for a discussion of the acquisition and related financial data.

We are currently in the process of evaluating the internal controls and procedures of Liberty and MGS. Further, we are in the process of integrating Liberty and MGS operations. Management will continue to evaluate our internal control over financial reporting as we execute integration activities, however, integration activities could materially affect our internal control over financial reporting in future periods.

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

 

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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 two acquisitions (collectively “the Acquisitions”) which were acquired during fiscal 2010 and are included in the 2010 consolidated financial statements. The financial reporting systems of the Acquisitions were integrated into the company’s financial reporting systems throughout 2010. 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 $246.1 million and $116.0 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, 2010. 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, 2010, 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 29, 2010 on the effectiveness of our internal control over financial reporting, which is included herein.

Item 9B. Other Information.

On November 24, 2010, John J. Sherman, our President and Chief Executive Officer entered into an employment agreement with Inergy GP, LLC, our managing general partner, which provides for an initial term of five years, subject to one year renewals thereafter unless terminated in accordance with its terms. Pursuant to the terms of the employment agreement, beginning December 1, 2010, Mr. Sherman is entitled to receive an annual base salary of $400,000 and is eligible for an annual bonus based on achievement of performance objectives established by the board of directors. The target amount of the annual bonus is 100% of Mr. Sherman’s annual salary.

If Mr. Sherman’s employment is terminated other than for cause he is entitled to receive the unpaid amount of his salary for the remainder of the term of the agreement. 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.

The foregoing description of Mr. Sherman’s employment agreement is not complete and is qualified in its entirety by reference to the employment agreement, which is filed as Exhibit 10.1 to this Form 10-K.

 

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PART III

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 662/3% 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 six directors.

Inergy Holdings, L.P. owns our managing general partner. As the sole member of our managing general partner, Inergy Holdings has the power to elect our board of directors.

As explained further in Part I, Item 1. Business, on November 5, 2010, we closed on the transactions contemplated by the Merger Agreement among us, Inergy Holdings and the other parties thereto pursuant to which, among other things, we cancelled our incentive distribution rights and acquired the equity interests of our non-managing general partner.

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

     55       President, Chief Executive Officer and Director

Phillip L. Elbert

     52       President and Chief Operating Officer—Propane Operations and Director

R. Brooks Sherman, Jr.

     45       Executive Vice President and Chief Financial Officer

Carl A. Hughes

     56       Senior Vice President—Business Development

Laura L. Ozenberger

     52       Senior Vice President—General Counsel and Secretary

Andrew L. Atterbury

     37       Senior Vice President—Corporate Development

William R. Moler

     44       Senior Vice President—Natural Gas Midstream Operations

Warren H. Gfeller

     58       Director

Arthur B. Krause

     69       Director

Richard T. O’Brien

     56       Director

Robert D. Taylor

     63       Director

 

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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 served as President, Chief Executive Officer and director of Inergy Holdings GP, LLC and a director of Great Plains Energy Inc. We believe the breadth of Mr. Sherman’s experience in the energy industry, through his current position as the President and CEO and his past employment described above, as well as his current board of director positions, has given him valuable knowledge about our business and our industry that makes him an asset to the board of directors of Inergy GP.

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 served as the President and Chief Operating Officer—Propane Operations of Inergy Holdings GP, LLC. Through his various leadership positions described above, Mr. Elbert has gained valuable experience in evaluating the financial performance and operations of companies in the propane industry, which makes him a valuable member of the board of directors of Inergy GP.

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 served 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 served 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

 

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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 served as a director of Inergy Holdings GP, LLC, Zapata Corporation and Duckwall-Alco Stores, Inc. Mr. Gfeller worked for many years in the propane industry. This experience has given him a unique perspective on our operations, and, coupled with his extensive financial and accounting training and practice, has made him a valuable member of the board of directors of Inergy GP.

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 currently serves as a director of Westar Energy and served as a director of Inergy Holdings GP, LLC from April 2005 until November 2010. Mr. Krause’s prior leadership experience and his extensive financial and accounting training and practice have made him a valuable member of the board of directors of Inergy GP.

Richard T. O’Brien. Mr. O’Brien was appointed to the board of our managing general partner on November 5, 2010. Mr. O’Brien currently serves as the President and Chief Executive Officer and a director of Newmont Mining Corporation, one of the world’s largest gold producers, based in Denver, Colorado. From April 2001 until September 2005, Mr. O’Brien served as the Executive Vice President and Chief Financial Officer of AGL Resources, a natural gas distributor headquartered in Atlanta, Georgia. He currently serves as a director of Vulcan Materials Company and served as a director of Inergy Holdings GP, LLC from May 2006 until November 2010. Mr. O’Brien brings a strong and unique background and set of skills to the board, including over 20 years of broad financial executive and operational experience in the energy, power and natural resources businesses.

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 and previously served as a director of Commercial Federal Corporation. The breadth of Mr. Taylor’s operational, financial and business experience has developed through his experience as chief executive officer of Executive AirShare Corporation and makes him an important voice as an independent director on the board of directors of Inergy GP.

Independent Directors

Messrs. Gfeller, Krause and Taylor qualify as “independent” pursuant to independence standards established by the New York Stock Exchange (“NYSE”) as set forth in Section 303A.02 of its Listed Company Manual. To be considered an independent director under the NYSE listing standards, the board of directors must affirmatively

 

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determine that a director has no material relationship with the Partnership. In making this determination, the board of directors adheres to all of the specific tests for independence included in the NYSE listing standards and considers all other facts and circumstances it deems necessary or advisable.

Board Leadership Structure and Risk Oversight

Board Leadership Structure

The board has no policy that requires that the positions of the Chairman of the Board (the “Chairman”) and the Chief Executive Officer be separate or that they be held by the same individual. The board believes that this determination should be based on circumstances existing from time to time, including the composition, skills and experience of the board and its members, specific challenges faced by the company or the industry in which it operates, and governance efficiency. Based on these factors, John J. Sherman serves as our Chairman and Chief Executive Officer.

Our non-management directors will meet in regularly scheduled sessions. Our non-management directors have appointed Warren H. Gfeller as the lead director to preside at such meetings. We have established a procedure by which unitholders or interested parties may communicate directly with the board of directors, any committee of the board, any of the independent directors or any one director serving on the board of directors by sending written correspondence addressed to the desired person, committee or group to the attention of Laura Ozenberger at Inergy, L.P., Two Brush Creek Blvd., Suite 200, Kansas City, MO 64112. Communications are distributed to the board of directors, or to any individual director or directors as appropriate, depending on the facts and circumstances outlined in the communication.

Risk Oversight

We face a number of risks, including environmental and regulatory risks, and others, such as the impact of competition and weather conditions. Management is responsible for the day-to-day management of risks our company faces, while the board of directors, as a whole and through its committees, has responsibility for the oversight of risk management. In fulfilling its risk oversight role, the board of directors must determine whether risk management processes designed and implemented by our management are adequate and functioning as designed. Senior management regularly delivers presentations to the board of directors on strategic matters, operations, risk management and other matters, and is available to address any questions or concerns raised by the board. Specifically, at each quarterly board meeting, senior management delivers a presentation on risk management focused on one or more key aspects of our business as selected by the board or senior management. Board meetings also regularly include discussions with senior management regarding strategies, key challenges and risks and opportunities for our company.

Our board committees assist the board in fulfilling its oversight responsibilities in certain areas of risk. The audit committee assists with risk management oversight in the areas of financial reporting, internal controls and compliance with legal and regulatory requirements and our risk management policy relating to our hedging program. The compensation committee assists the board of directors with risk management relating to our compensation policies and programs.

Board Committees

Audit Committee

The members of the audit committee must meet the independence standards established by the NYSE. 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

 

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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 NYSE. 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, 2010, 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. Additionally, the board of directors has adopted corporate governance guidelines for the directors and the board. The code of ethics and corporate governance guidelines may be found on our website at www.inergylp.com.

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 served 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

 

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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 did receive awards of equity in Inergy Holdings, L.P.

For purposes of this Compensation Discussion and Analysis our named executive officers are John J. Sherman, R. Brooks Sherman, Jr., Phillip L. Elbert, William R. Moler and Andrew L. Atterbury.

Compensation Philosophy and Objectives

We employ a compensation philosophy that emphasizes pay for performance. The primary measure of our performance long-term is our ability to increase sustainable 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:

 

   

aligning executive compensation incentives with the creation of unitholder value and the growth of cash earnings on behalf of our unitholders;

 

   

balancing short and long-term performance;

 

   

tying short-and long-term compensation to the achievement of performance objectives (company, business unit, department and/or individual); and

 

   

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:

 

   

assisting in establishing business performance goals and objectives;

 

   

evaluating executive officer and company performance;

 

   

recommending compensation levels and awards for executive officers; and

 

   

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

 

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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.

   Cerner Corporation

Copano Energy, LLC

   DST Systems, Inc.

Energy Transfer Partners, L.P.

   Garmin Ltd.

Ferrellgas Partners, L.P.

   Great Plains Energy Incorporated

Markwest Energy Partners, L.P.

   Kansas City Southern

Plains All American Pipeline, L.P.

  

Regency Energy Partners, L.P.

  

Suburban Propane Partners, L.P.

  

Targa Resources 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:

 

   

amount of total compensation;

 

   

individual components of compensation; and

 

   

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 2010, 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.

 

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Elements of Compensation

The principal elements of compensation for the named executive officers are the following:

 

   

base salary;

 

   

incentive awards;

 

   

long-term incentive plan awards; and

 

   

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.

For fiscal 2010, 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. As a result, base salaries of each of our named executive officers remained $350,000, $225,000, $275,000, $200,000 and $200,000 for John J. Sherman, R. Brooks Sherman, Phillip L. Elbert, William R. Moler and Andrew L. Atterbury, respectively.

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 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 sole metric used to determine whether bonuses would be paid to the named executive officers in fiscal 2010 was our achievement of the target of earnings before income taxes, plus net interest expense, depreciation and amortization expense, further adjusted to exclude the gain or loss on derivative contracts associated with retail propane fixed price sales contracts, the gain or loss on the disposal of assets, long-term incentive and equity compensation expenses and transaction costs (“Adjusted EBITDA”). We selected this metric because we believe it closely aligns the focus of our named executive officers with the increase in unitholder value. In addition, this target was communicated to our unitholders and analysts as guidance at the beginning of the 2010 fiscal year.

The following table summarizes the incentive award targets and our actual results for the fiscal year ended September 30, 2010 (in millions):

 

     Target     Actual  

Adjusted EBITDA(1)

   $ 341.0 (2)    $ 325.6   

 

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(1)

Adjusted EBITDA represents EBITDA excluding (1) non-cash gains or losses on derivative contracts associated with retail propane fixed price sales contracts, (2) long-term incentive and equity compensation expenses, (3) gains or losses on disposals of assets and (4) transaction costs. For a reconciliation of EBITDA to Adjusted EBITDA refer to page 39 of this annual report on Form 10-K.

(2)

The compensation committee initially approved an Adjusted EBITDA target of $318.0 million, but increased the target to $341.0 million to account for the subsequent Liberty Propane, LP and MGS Corporation acquisitions.

As reflected in the table above, we did not meet the target for Adjusted EBITDA in fiscal 2010. Accordingly, in accordance with the terms of the employment agreements of the named executive officers, there were no short-term incentive awards for fiscal 2010.

Under the terms of Mr. Atterbury’s employment agreement entered into on October 1, 2007, he was eligible to receive a bonus equal in value to 50,000 Inergy Holdings, L.P. units (150,000 post-split) if certain acquisition, investment, unit price and distribution targets were met. Specifically, in order to receive the incentive award, by October 1, 2010, Mr. Atterbury must have played a significant role in the origination and execution of a transaction or series of transactions which are approved by the board of directors and have a purchase price or investment of at least $600 million; and one of the following conditions must also have been satisfied: (i) the closing price of an Inergy Holdings, L.P. common unit must have exceeded $90 ($30 post-split) for five consecutive days after the acquisition/investment goal is obtained; or (ii) Inergy Holdings pays an annualized distribution of $4.00 ($1.33 post-split) per unit by December 31, 2011.

The compensation committee selected these metrics due to Mr. Atterbury’s significant role in the origination and execution of transactions designed to accelerate the growth of the partnership. During the 2010 fiscal year, Mr. Atterbury achieved the aforementioned performance goals and was awarded a cash bonus amount of $4,677,857 in accordance with his employment agreement.

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 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.

 

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Prior equity awards were made in fiscal 2002, fiscal 2005 and fiscal 2008. Consistent with our general policy of not making systematic annual awards, we did not make broad based equity awards in fiscal 2010. On November 25, 2009, the compensation committee awarded William R. Moler 37,500 Inergy, L.P. restricted units and 37,500 (112,500 post-split) Inergy Holdings, L.P. restricted units. On February 1, 2010, the compensation committee awarded R. Brook Sherman, Jr. 55,000 Inergy, L.P. restricted units and 55,000 (165,000 post-split) Inergy Holdings, L.P. restricted units and awarded Phillip L. Elbert 70,000 Inergy, L.P. restricted units and 70,000 (210,000 post-split) Inergy Holdings, L.P. restricted units. Due to John Sherman’s significant ownership in us, he has requested that he receive no long-term equity incentive awards.

The awards to Messrs. Moler, Elbert and B. Sherman were partial consideration for entering into five-year employment agreements with the company, which include two-year noncompete provisions. The amount of the awards was determined based on a review of target total compensation levels for these key executive officers including base salary, short term incentive bonuses and these long term awards. The compensation committee then annualized these awards by dividing the total value by five in accordance with the ultimate vesting. The total annualized target compensation for these key executive officers was determined to be near the median of the “peer” group data considering their respective skills, experience and past performance.

These awards vest in three annual installments beginning on the third anniversary of the grant date. The awards are subject to forfeiture if Inergy, L.P. fails to maintain the same annualized distribution payment per common unit as in place on the date of grant.

Risk Assessment Related to our Compensation Structure.

We believe that the compensation plans and programs for our executive officers, as well as other employees, are appropriately structured and are not reasonably likely to result in a material risk. We believe these compensation plans and programs are structured in a manner that does not promote excessive risk-taking that could reward poor judgment. We also believe that we have allocated compensation among base salary and short and long-term compensation in such a way as to not encourage excessive risk-taking. In particular, we generally do not adjust base annual salaries for executive officers and other employees significantly from year to year, and therefore the annual base salary of our employees is not generally impacted by our overall financial performance or the financial performance of an operating segment. We generally determine whether, and to what extent, executive officers and other employees receive incentive cash bonuses based on achievement of specified financial performance objectives. For example, in fiscal 2010, Inergy announced EBITDA guidance that it believed was reasonable in light of past performance and market conditions, and the compensation committee took into account whether we met or exceeded that public guidance for the purpose of determining incentive cash bonuses for its executive officers following the completion of the fiscal year. Furthermore, we use restricted units rather than unit options for equity awards because restricted units retain value even in a depressed market so that employees are less likely to take unreasonable risks to get, or keep, options “in-the-money.” In addition, we believe the award of restricted units aligns the interests of the recipient with our unitholders because restricted units have upside and downside risk.

On certain limited occasions we have used metrics other than EBITDA to determine incentive awards. For example, as discussed above, Mr. Atterbury’s employment agreement provided for an incentive bonus if certain acquisition, investment, unit price and distribution targets were met. To mitigate the risks associated with incentive awards based on acquisition or investment goals, senior management conducts a rigorous underwriting review of all acquisitions and material investments. Prior to entering into any binding agreements, an underwriting committee comprised of senior management meets to review all material terms, financial projections and risks associated with any acquisition or investment. No acquisition or investment is allowed to be consummated without approval of the underwriting committee. Furthermore, any acquisition greater than $50 million (purchase price) must be brought to the board of directors for approval.

 

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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 ten 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.

 

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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 ten 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.

In connection with the Simplification Transaction, on November 5, 2010, each vested and unvested option to purchase Holdings common units granted under the Inergy Holdings Long Term Incentive Plan was assumed by Inergy and converted into an option to purchase Inergy, L.P. units to be issued pursuant to the Inergy Long Term Incentive Plan. Each Holdings unit option assumed by Inergy continues to have the same terms and conditions set forth in the Inergy Holdings Long Term Incentive Plan except that they are exercisable for that number of whole Inergy, L.P. units equal to the product of the number of Holdings common units that were subject to such Holdings unit option multiplied by 0.77, rounded down to the nearest whole number, and the per unit exercise price for the Inergy, L.P. units subject to such assumed Holdings unit option is equal to the quotient determined by dividing the exercise price per Holdings common unit of such Holdings unit option by 0.77, rounded up to the nearest whole cent.

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.

In connection with the Simplification Transaction, on November 5, 2010, each unvested Holdings restricted unit outstanding under the Inergy Holdings Long Term Incentive Plan was assumed by Inergy and converted into a restricted Inergy, L.P. unit to be issued pursuant to the Inergy Long Term Incentive Plan. Each Holdings restricted unit assumed continues to have the same terms and conditions set forth in the Inergy Holdings Long Term Incentive Plan except that they were converted into that number of restricted Inergy, L.P. equal to the product of the number of Holdings restricted units multiplied by 0.77, rounded down to the nearest whole number of Inergy, L.P. units.

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’

 

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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).

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, 2010.

Warren H. Gfeller

Arthur B. Krause

Members of the Compensation Committee

 

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Summary Compensation Table

The following table sets forth the cash and non-cash compensation earned for the years ended September 30, 2010, September 30, 2009, and September 30, 2008 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 2010.

 

Name and Principal Position

  Fiscal
Year
    Salary
($)
    Bonus
($)
    Stock
Awards
($)(1)
    Option
Awards
($)
    Non-Equity
Incentive Plan
Compensation
($)
    All Other
Compensation
($)
    Total
($)
 

John. J. Sherman

    2010        350,000        —          —          —          —          9,828        359,828   

President and Chief Executive Officer

    2009        350,000        —          —          —          350,000        7,137        707,137   
    2008        350,000        —          350,000        —          —          5,504        705,504   

R. Brooks Sherman, Jr.

    2010        225,000        —          5,669,950 (2)      —          —          416,382 (3)      6,311,332   

Executive Vice President and Chief Financial Officer

    2009        225,000        —          —          —          225,000        105,047        727,130   
    2008        225,000        —          1,889,950        —          —          86,404        2,201,354   

Phillip L. Elbert

    2010        275,000        —          7,216,300 (2)      —          —          549,038 (3)      8,040,338   

President and Chief Operating Officer—Propane Operations

    2009        275,000        —          —          —          275,000        148,388        917,283   
    2008        275,000        —          2,653,500        —          —          123,029        3,051,529   

William R. Moler

    2010        200,000        —          3,254,625 (2)      —          —          308,235 (3)      3,762,860   

Senior Vice President-Natural Gas Midstream Operations

    2009        200,000        55,000        —          —          200,000        98,633        675,029   
    2008        200,000        —          1,389,250        —          —          90,181        1,679,431   

Andrew L. Atterbury(5)

    2010        200,000        —          —          —          4,677,857 (4)      75,754 (3)      4,953,611   

Senior Vice President—Corporate Strategy

               

 

(1)

The material terms of our outstanding LTIP awards to our executive officers are described in “Compensation Discussion and Analysis—Long-Term Incentive Plans.” Equity award amounts reflect the aggregate grant date fair value of unit awards granted during the periods presented.

(2)

As discussed in the “Compensation Discussion and Analysis” on February 1, 2010, R. Brooks Sherman, Jr., was awarded 55,000 Inergy, L.P. restricted units and 55,000 Inergy Holdings, L.P. restricted units (165,000 post-split), and Phillip L. Elbert was awarded 70,000 Inergy, L.P. restricted units and 70,000 Inergy Holdings, L.P. restricted units (210,000 post-split). On November 25, 2009, William R. Moler was awarded 37,500 Inergy, L.P. restricted units and 37,500 Inergy Holdings, L.P. restricted units (112,500 post-split). These awards vest in annual installments (25%, 25%, 50%) beginning three years from the grant date and were awarded as partial consideration for such executive officers entering into new five year employment agreements with the company. The annualized value of each of these awards over the five year term of each employment agreement is $1,133,990 for R. Brooks Sherman, Jr., $1,443,260 for Mr. Elbert and $650,925 for Mr. Moler. The awards are subject to forfeiture if certain company financial performance metrics are not met.

(3)

Consists of: (i) distributions paid on restricted units granted under the Long-Term Incentive Plans (R. Brooks Sherman, Jr.—$408,575, Phillip L. Elbert—$540,650, William R. Moler—$300,075 and Andrew L. Atterbury—$75,700 in this fiscal year); (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, under the terms of Mr. Atterbury’s employment agreement he received an incentive bonus equal in value to 50,000 Inergy Holdings, L.P. units (150,000 post-split) based on the achievement of certain acquisition, investment, unit price and distribution targets.

(5)

Mr. Atterbury was not a named executive officer in 2008 or 2009.

 

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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.

 

     Estimated Future Payouts Under
Incentive Plan Awards
              

Name

   Threshold
($)
     Target
($)
     Maximum
($)(1)
     All Other  Stock
Awards(#)(2)
    Grant Date Fair
Value of Stock and
Option Awards ($)
 

John J. Sherman

     0         400,000         400,000         —          —     

R. Brooks Sherman, Jr.

     0         225,000         225,000        

 

55,000 (NRGY

165,000 (NRGP


)(3) 

   

 

1,980,000

3,689,950

  

  

Phillip L. Elbert

     0         275,000         275,000        

 

70,000 (NRGY

210,000 (NRGP


)(3) 

   

 

2,520,000

4,696,300

  

  

William R. Moler

     0         200,000         200,000        

 

37,500 (NRGY

112,500 (NRGP


)(3) 

   

 

1,255,125

1,999,500

  

  

Andrew L. Atterbury

     0         200,000         200,000         —          —     

 

(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)

These awards vest in annual installments (25%, 25%, 50%) beginning three years from the grant date. The awards for Mr. B. Sherman and Mr. Elbert were awarded on February 1, 2010, and are subject to forfeiture if on any vesting date the annualized distribution paid on Inergy, L.P. common units is less than $2.74. The awards for Mr. Moler were granted on November 25, 2009, and are subject to forfeiture if on any vesting date the annualized distribution paid on Inergy, L.P. common units is less than $2.70.

(3)

Adjusted to reflect a 3-for-1 unit split at Inergy Holdings, L.P. effective as of June 1, 2010. In connection with the Simplification Transaction, on November 5, 2010, Inergy Holdings, L.P. restricted units were converted into Inergy, L.P. restricted units based on the 0.77 exchange ratio.

Narrative Disclosure to Summary Compensation Table and Grants of Plan-Based Awards Table

A discussion of fiscal 2010 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:

 

   

John J. Sherman—President and Chief Executive Officer;

 

   

R. Brooks Sherman, Jr., Executive Vice President—Chief Financial Officer;

 

   

Phillip L. Elbert, President and Chief Operating Officer—Propane Operations;

 

   

William R. Moler, Senior Vice President—Natural Gas Midstream Operations; and

 

   

Andrew L. Atterbury, Senior Vice President—Corporate Strategy

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 five years. During the fiscal year, the annual salaries for these individuals are as follows:

 

   

John J. Sherman—$350,000. Mr. Sherman entered into a new five year employment agreement on November 24, 2010, which provides for an annual salary of $400,000.

 

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R. Brooks Sherman, Jr.—$225,000

 

   

Phillip L. Elbert—$275,000

 

   

William R. Moler—$200,000

 

   

Andrew L. Atterbury—$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 (except Mr. Atterbury), 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.

A copy of Mr. Atterbury’s employment agreement is included herewith as Exhibit 10.6.

Outstanding Equity Awards at Fiscal Year-End Table

The following table summarizes the options and restricted units outstanding as of September 30, 2010, for the named executive officers. The table includes unit options and restricted units of Inergy, L.P. (NYSE: NRGY) granted under the Inergy Long Term Incentive Plan and unit options and restricted units of Inergy Holdings, L.P. (NYSE: NRGP) granted under the Inergy Holdings Long Term Incentive Plan.

 

            OPTION AWARDS      UNIT AWARDS  

Name

   Security      Number of
Securities
Underlying
Unexercised
Options (#)

Exercisable(1)
    Number of
Securities
Underlying
Unexercised
Options (#)

Unexercisable
     Option
Exercise
Price($)(1)
     Option
Expiration
Date
     Number
of Units
That
Have Not
Vested
(#)(1)
     Market
Value of
Units That
Have Not
Vested ($)(4)
 

John J. Sherman

     —           —          —         $ —           —           —           —     

R. Brooks Sherman, Jr.

     NRGP         60,000 (2)      —           7.50         06/19/15         270,000         8,159,400   

Phillip L. Elbert

     NRGP         120,000 (2)      —           7.50         06/19/15         360,000         10,897,200   

William R. Moler

     NRGY         5,000 (3)      —           28.60         09/14/15         42,500         1,685,125   
     NRGP         15,000 (2)      —           11.11         06/19/15         187,500         5,666,250   
     NRGP         45,000 (3)      —           7.50         09/14/15         —           —     

Andrew L. Atterbury

     NRGP         90,000 (2)      —           7.50         06/19/15         60,000         1,813,200   

 

(1)

Adjusted to reflect a 3-for-1 unit split at Inergy Holdings, L.P. effective as of June 1, 2010.

(2)

Option vested in full on June 20, 2010.

(3)

Option vested in full on September 15, 2010.

(4)

Market value for NRGY units based on the NYSE closing price of $39.65 on September 30, 2010, and market value of NRGP units based on the NYSE closing price of $30.22 on September 30, 2010.

 

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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, 2010, for the named executive officers.

 

            Option Awards      Stock Awards  

Name

   Security      Number
of Units
Acquired
On
Exercise
(#)
     Value
Realized

on
Exercise
($)
     Number
of Units
Acquired
On
Vesting
(#)
     Value
Realized
on
Vesting
($)
 

John J. Sherman

     —           —           —           —           —     

R. Brooks Sherman, Jr.

     NRGP         60,000         1,000,990         —           —     

Phillip L. Elbert

     —           —           —           —           —     

William R. Moler

     NRGY         10,000         118,065         2,500         92,650   

Andrew L. Atterbury

     —           —           —           —           —     

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 (except for Mr. Atterbury) 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;

 

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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, 2010, our named executive officers would have been entitled to the following:

 

   

John J. Sherman’s employment agreement e