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, 2005

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
None	N/A

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

Common Units representing limited partnership interests

(Title of Class)

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

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act).  Yes x  No ¨

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 31,536,141 common units of the registrant held by non-affiliates computed by reference to the $28.32 closing price of such common units on November 1, 2005, was approximately $893.1 million. The aggregate market value of the 23,102,065 common units of the registrant held by non-affiliates computed by reference to the $32.37 closing price of such common units on March 31, 2005, the last business day of the registrant’s most recently completed second fiscal quarter, was approximately $747.8 million. As of November 21, 2005, the registrant had 35,311,329 common units outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

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

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” we are referring to Inergy Holdings, L.P. (Nasdaq symbol NRGP) itself, or to Inergy Holdings, L.P. and its subsidiaries collectively, as the context requires.

• We have a managing general partner and a non-managing general partner. Our managing general partner is responsible for the management of our company and its operations are governed by a board of directors. 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. Our non-managing general partner owns an approximate 1.2% non-managing general partner interest in our company.

INERGY, L.P.

INDEX TO ANNUAL REPORT ON FORM 10-K

		Page
PART I
Item 1.	Business	1
Item 2.	Properties	12
Item 3.	Legal Proceedings	12
Item 4.	Submission of Matters to a Vote of Security Holders	12
PART II
Item 5.	Market for the Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities	13
Item 6.	Selected Financial Data	14
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	17
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	32
Item 8.	Financial Statements and Supplementary Data	33
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	33
Item 9A.	Controls and Procedures	33
Item 9B.	Other Information	34
PART III
Item 10.	Directors and Executive Officers of the Registrant	34
Item 11.	Executive Compensation	38
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters	42
Item 13.	Certain Relationships and Related Transactions	46
Item 14.	Principal Accountant Fees and Services	47
PART IV
Item 15.	Exhibits and Financial Statement Schedules	47

PART I

Item 1. Business.

Recent Developments

On October 3, 2005, we acquired the assets of Atlas Gas Products, Inc. (“Atlas”), headquartered in Costonia, OH. Atlas delivers propane to approximately 7,000 customers from three retail locations.

On October 4, 2005, we acquired the assets of Dowdle Gas, Inc. (“Dowdle”) headquartered in Columbus, MS, effective as of October 1, 2005. Dowdle is the 12^th largest propane retailer in the U.S. and delivers in excess of 50 million gallons of retail propane to approximately 120,000 customers in Alabama, Florida, Georgia, Mississippi, and Tennessee from sixty-nine retail locations.

On October 14, 2005 we acquired the assets of Graeber Brothers, Inc. (“Graeber”), located in northern Mississippi, effective as of October 4, 2005. Graeber delivers retail propane to approximately 14,000 customers from six retail locations which are contiguous with the acquisition of Dowdle.

General

Inergy, L.P., a publicly traded Delaware limited partnership, was formed on March 7, 2001 but did not conduct operations until the closing of our initial public offering on July 31, 2001. We own and operate, principally through Inergy Propane, LLC, a rapidly growing geographically diverse retail and wholesale propane supply, marketing and distribution business. We also operate a midstream business that includes a natural gas storage facility and a natural gas liquids (“NGL”) business. Since our predecessor’s inception in November 1996 through September 30, 2005, we have acquired the assets and liabilities of 49 companies for an aggregate purchase price of approximately $1.2 billion, including working capital, assumed liabilities and acquisition costs. These acquisitions include the assets and liabilities of six propane companies and a natural gas storage facility acquired during fiscal 2005 for an aggregate purchase price of approximately $810 million. For the fiscal year ended September 30, 2005, we sold and physically delivered approximately 318 million gallons of propane to retail customers and approximately 391 million gallons of propane to wholesale customers.

The address of our principal executive offices is Two Brush Creek Boulevard, Suite 200, Kansas City, Missouri, 64112 and our telephone number at this location is 816-842-8181. Our common units trade on the Nasdaq National Market under the symbol “NRGY”. We electronically file certain documents with the Securities and Exchange Commission (“SEC”). We file annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K (as appropriate), along with any related amendments and supplements. From time-to-time, we also may file registration and related statements pertaining to equity or debt offerings. You may read and download our SEC filings over the internet from several commercial document retrieval services as well as at the SEC’s website at www.sec.gov. You may also read and copy our SEC filings at the SEC’s public reference room located at Judiciary Plaza, 450 Fifth Street, N.W., 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 as soon as reasonably practicable after the filing thereof on our website at www.inergypropane.com. Please note that any internet addresses provided in this Form 10-K are for information purposes only and are not intended to be hyperlinks. Accordingly, no information found and/or provided at such internet addresses is intended or deemed to be incorporated by reference herein.

We believe we are the fifth largest propane retailer in the United States, excluding cooperatives, 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 regional brand names including: Arrow Gas, Blue Flame, Bradley Propane, Burnwell Gas, Country Gas, Dowdle Gas, Gaylord Gas, Hancock Gas, Highland Propane, Hoosier Propane, Independent Propane, Maingas, McCracken, Modern Gas, Moulton Gas Service, Northwest Energy, Ohio Gas, Pearl Gas, Pro Gas, Pulver Gas, United Propane, and Tru-Gas. As of November 1, 2005 we serve approximately 700,000 retail customers in Alabama, Arkansas, Connecticut, Florida, Georgia, Illinois, Indiana, Kentucky, Maine, Maryland, Massachusetts, Michigan, Minnesota, Mississippi, New Hampshire, New Jersey, New York, North Carolina, Ohio, Oklahoma, Pennsylvania, Rhode Island, South Carolina, Tennessee, Texas, Vermont, Virginia, West Virginia, and Wisconsin from 342 customer service centers which have an aggregate of approximately 29 million gallons of above-ground propane storage capacity. 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 Southeast.

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We also own and operate a midstream operation including the following assets:

• The Stagecoach natural gas storage facility (“Stagecoach”), a high performance, multi-cycle natural gas storage facility with approximately 13.6 Bcf of working gas capacity, a maximum withdrawal capability of 500 MMcf/day, and a maximum injection capability of 250 MMcf/day. The facility is fee-based and is currently 100% committed primarily with investment grade rated companies with term contracts that have a weighted average maturity extending to March 2008. Located 150 miles northwest of New York City, the Stagecoach facility is among the closest natural gas storage facilities to the northeastern United States market. Stagecoach is connected to Tennessee Gas Pipeline Company’s 300-Line.

• an NGL business in Bakersfield, California which includes natural gas processing, NGL fractionation, NGL rail and truck terminals, bulk storage, trucking and marketing operations.

We have grown primarily through acquisitions of propane operations. Including our initial acquisition of McCracken Oil & Propane Company in 1996, and through September 30, 2005, we have completed 49 acquisitions (including 2 midstream businesses) in numerous states. On December 21, 2004 we closed on the purchase of Star Gas Propane, L.P., (“Star Gas”) our largest acquisition. When acquired, Star Gas was servicing approximately 345,000 customers from approximately 120 customer service centers in the Midwest, Northeast, Florida, and Georgia.

The following chart sets forth information about each business we acquired during the fiscal year ended September 30, 2005 and through the date of this filing:

Acquisition Date	Company	Location
November 2004	Moulton Gas Service, Inc.	Wapakoneta, OH
December 2004	Star Gas Propane L.P.	Stamford, CT
December 2004	Northwest Energy	Holly, MI
May 2005	Bayless Gas	Damascus, OH
May 2005	Propane Sales	Albion, PA
May 2005	Steinheiser Propane, Inc.	Butler, PA
August 2005	Stagecoach Natural Gas Storage Facility	Tioga County, NY
Acquisitions after September 30, 2005
October 2005	Atlas Gas Products, Inc.	Costonia, OH
October 2005	Dowdle Gas, Inc.	Columbus, MS
October 2005	Graeber Brothers, Inc.	Grenada, MS

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 three broad categories: residential, industrial and 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

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of handling in shipping and distribution. When the pressure is released or the temperature is increased, it is usable as a flammable gas. Propane is colorless and odorless; an odorant is added to allow its detection. Propane is clean-burning, producing negligible amounts of pollutants when consumed.

The retail market for propane is seasonal because it is used primarily for heating in residential and commercial buildings. Approximately 70% of our retail propane volume is sold during the peak heating season from October through March. Consequently, sales and operating profits are generated mostly in the first and fourth calendar quarters of each calendar year.

Propane competes primarily with natural gas, electricity and fuel oil as an energy source, principally on the basis of price, availability and portability. Propane is more expensive than natural gas on an equivalent BTU basis in locations served by natural gas, but serves as an alternative to natural gas in rural and suburban areas where natural gas is unavailable or portability of product is required. Historically, the expansion of natural gas into traditional propane markets has been inhibited by the capital costs required to expand pipeline and retail distribution systems. Although the extension of natural gas pipelines tends to displace propane distribution in areas affected, we believe that new opportunities for propane sales arise as more geographically remote neighborhoods are developed. Propane is generally less expensive to use than electricity for space heating, water heating, clothes drying and cooking. Although propane is similar to fuel oil in certain applications and market demand, propane and fuel oil compete to a lesser extent than propane and natural gas, primarily because of the cost of converting to fuel oil. The costs associated with switching from appliances that use fuel oil to appliances that use propane are a significant barrier to switching. By contrast, natural gas can generally be substituted for propane in appliances designed to use propane as a principal fuel source.

In addition to competing with alternative energy sources, we compete with other companies engaged in the retail propane distribution business. Competition in the propane industry is highly fragmented and generally occurs on a local basis with other large full-service multi-state propane marketers, smaller local independent marketers and farm cooperatives. Based on industry publications, we believe that the 10 largest retailers account for less than 37% of the total retail sales of propane in the United States, and that no single marketer has a greater than 10% share of the total retail market in the United States. Most of our customer service centers compete with several marketers or distributors. Each customer service center operates in its own competitive environment because retail marketers tend to locate in close proximity to customers. Our typical customer service center generally has an effective marketing radius of approximately 25 miles, although in certain rural areas the marketing radius may be extended by a satellite location.

The ability to compete effectively further depends on the reliability of service, responsiveness to customers and the ability to maintain competitive prices. We believe that our safety programs, policies and procedures are more comprehensive than many of our smaller, independent competitors and give us a competitive advantage over such retailers. We also believe that our service capabilities and customer responsiveness differentiate us from many of these smaller competitors. Our employees are on call 24-hours and seven-days-a-week for emergency repairs and deliveries.

Retail propane distributors typically price retail usage based on a per gallon margin over wholesale costs. As a result, distributors generally seek to maintain their operating margins by passing costs through to customers, thus insulating themselves from volatility in wholesale propane prices. During periods of sudden price increases in propane at the wholesale level, distributors may be unable or unwilling to pass entire cost increases through to customers. In these cases, significant decreases in per gallon margins may result.

The propane distribution industry is characterized by a large number of relatively small, independently owned and locally operated distributors. Each year a significant 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 or start-up operations in new markets.

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Midstream

We own, as part of our midstream operations, a high-performance, multi-cycle natural gas storage facility (Stagecoach) in New York which we acquired in August 2005. We also own a natural gas liquids business in California, which includes natural gas processing, NGL fractionation, NGL rail and truck terminals, bulk storage, trucking and marketing operations. We believe these businesses complement our existing wholesale and supply operations and provide the company with added long term strategic benefits.

Natural Gas Storage Business

According to the National Petroleum Council’s 2003 report Balancing Natural Gas Policy, natural gas supplies approximately 25% of U.S. energy, generating about 19% of electric power, supplying heat to over 60 million households, and providing over 40% of all primary energy for industries. In recent years there has been a fundamental shift in the natural gas supply and demand balance that has resulted in higher and more volatile prices. This is due in part to the following factors:

• the growing demand by more seasonal users such as the residential/commercial and the power generation customer segments; and

• conflicts in public policy that in certain instances prohibit or limit the exploration and access to gas-prone areas and hinder the pipeline and infrastructure development.

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 EIA, U.S. natural gas consumption is expected to grow at a compound annual growth rate of approximately 1.6% through 2025.

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 where gas is used principally for heating. These markets are very temperature sensitive with demand being highly variable both on a seasonal and a daily basis thus requiring that storage be capable of providing high maximum daily deliverability on the coldest days when storage due to infrastructure constraints provides as much as 50% of the market’s total requirement. Analysis has shown that seasonal winter demand has continued to show steady growth even though warmer winter temperature trends have muted the full impact of this increasing demand. Gas storage has facilitated the creation of a natural gas industry that is characterized by a production profile that is largely non-seasonal and a consumption profile that is highly seasonal and weather sensitive. Natural gas storage is essential in reallocating this inherent supply and demand imbalance.

In the natural gas storage business, there are significant barriers to entry, particularly in depleted reservoir storage such as the Stagecoach facility. Barriers include:

Geology: rock quality, depth, containment and reservoir size heavily influence development opportunities;

Geography: proximity to existing pipeline infrastructure, surface development, and complicated land ownership all combine to further increase the difficulty in developing and operating natural gas storage facilities;

Specialized skills: finding and retaining qualified and skilled natural gas storage professionals is a challenge in today’s competitive job market in the oil & gas sectors due to the specialized nature of the skills required; and

Development costs: costs for new natural gas storage capacity development have continued to increase.

Although there are significant barriers to entry within the natural gas storage industry, competition is robust. Competition for natural gas storage is primarily based on location, connectivity, and the ability to deliver natural gas in a timely and reliable manner. Our natural gas storage facility competes with other means of natural gas storage, including other depleted reservoir facilities, salt dome 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 (LDCs) 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

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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. LDCs 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 pure gas price arbitrage purposes, buying and injecting gas at times of low gas prices and withdrawing at times of higher prices as driven by the fundamentals of the natural gas market.

The value of natural gas storage is a reflection of its critical role in providing the North American natural gas market with a degree of supply reliability, flexibility, and seasonal and daily demand balancing.

NGL Business

In general, natural gas produced at the wellhead contains, along with methane, various NGLs. This “rich” natural gas in its raw form is usually not acceptable for transportation in the nation’s major natural gas pipeline systems or for commercial use as a fuel. Natural gas processing separates, for the most part, the NGLs from the methane, and delivers the methane to the local natural gas pipelines. NGLs are retained for further processing within our fractionation facility.

NGL fractionation facilities separate mixed NGL streams into discrete NGL products: ethane, propane, normal butane, isobutane, and 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 and, to a lesser extent, by railcar and truck.

NGL products (ethane, 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. Ethane is primarily used in the petrochemical industry as feedstock for ethylene production, one of the basic building blocks for a wide range of plastics and other chemical products. Propane is used both as a petrochemical feedstock in the production of ethylene and propylene and as a heating, engine and industrial fuel. Normal butane is used as a petrochemical feedstock in the production of ethylene and butadiene (a key ingredient of synthetic rubber), as a blendstock for motor gasoline and to derive isobutane through isomerization. Isobutane is fractionated from mixed butane (a mixed stream of normal butane and isobutane) or produced from normal butane through the process of isomerization, principally for use in refinery alkylation to enhance the octane content of motor gasoline, in the production of iso-octane and MTBE, 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 or as a petrochemical feedstock.

Our NGL business located near Bakersfield, CA 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 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.

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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 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, 2005, we have acquired and successfully integrated 49 companies, 47 propane companies and 2 midstream businesses. Our executive officers and key employees, who average more than 15 years experience in the propane and 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 Inergy common unitholders on a per unit basis;

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

• propane and midstream businesses in attractive market areas;

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

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

• retention of key employees in acquired businesses.

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, 2005, sales to residential customers represented approximately 70% of our retail propane gallons sold. Although overall demand for propane is affected by weather and other factors, we believe that residential propane consumption is not materially affected by general economic conditions because most residential customers consider home space heating to be an essential purchase. In addition, we own nearly 90% of the propane tanks located at our customers’ homes. In many states, fire safety regulations restrict the refilling of a leased tank solely to the propane supplier that owns the tank. These regulations, which require customers to switch propane tanks when they switch suppliers, help enhance the stability of our customer base because of the inconvenience and costs involved with switching tanks and suppliers.

Regional Branding

We believe that our success in maintaining customer stability at our customer service centers results from our 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 our 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.

Strong Wholesale Supply, Marketing and Distribution Business

One of our distinguishing strengths is our procurement and distribution expertise and capabilities. For the fiscal year ended September 30, 2005, we delivered approximately 391.3 million gallons of propane on a wholesale basis to independent dealers, multistate marketers, petrochemical companies, refinery and gas processors and a number of other NGL marketing and distribution companies. 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

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growing retail operations at prices that are generally available only to large wholesale purchasers. This purchasing scale and resulting expertise also helps us avoid shortages during periods of tight supply to an extent not generally available to other retail propane distributors.

Flexible Financial Structure

We have a $350 million revolving credit facility for acquisitions and a $75 million revolving working capital facility. As of November 1, 2005, we had available capacity of approximately $126 million under our facility. We believe our available capacity under these facilities combined with our ability to fund acquisitions through the issuance of additional partnership interests will provide us with a flexible financial structure that will facilitate our acquisition strategy.

Operations

Our operations reflect our two reportable segments: propane operations and midstream operations.

Propane Operations

Retail Propane

Customer Service Centers

At November 1, 2005, we distribute propane to approximately 700,000 retail customers from 342 customer service centers in 29 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	33
Arkansas	3
Connecticut	2
Florida	18
Georgia	13
Illinois	4
Indiana	29
Kentucky	3
Maine	4
Maryland	10
Massachusetts	4
Michigan	35
Minnesota	1
Mississippi	32
New Hampshire	3
New Jersey	4
New York	11
North Carolina	10
Ohio	32
Oklahoma	5
Pennsylvania	8
Rhode Island	1
South Carolina	3
Tennessee	9
Texas	36
Vermont	9
Virginia	8
West Virginia	3
Wisconsin	9
Total	342

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From our customer service centers, we also sell, install and service equipment related to our propane distribution business, including heating and cooking appliances. Typical customer service centers consist of an office and service facilities, with one or more 12,000 to 30,000 gallon bulk storage tanks. Some of our customer service centers also have an appliance showroom. We have several satellite facilities that typically contain only large capacity storage tanks. As of November 1, 2005 we have approximately 29.3 million gallons of above-ground propane storage capacity at our customer service centers and satellite locations.

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 ranges 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 approximately 10,000 gallons. These customers include industrial customers, large-scale heating accounts and large agricultural accounts.

During the fiscal year ended September 30, 2005, we delivered approximately 45% and 55% of our propane volume to retail and wholesale customers, respectively. Our retail volume sold to residential, industrial and commercial, and agricultural customers were as follows:

• approximately 70% to residential customers;

• approximately 23% to industrial and commercial customers; and

• approximately 7% to agricultural customers.

No single retail customer accounted for more than 1% of our revenue during the fiscal year ended September 30, 2005.

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: (i) residential and commercial demand for propane has been relatively unaffected by general economic conditions due to the largely non-discretionary nature of most propane purchases by our customers, (ii) loss of customers to competing energy sources has been low, (iii) 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 nearly 90% of the storage tanks utilized by our customers and (iv) our ability to offset customer losses through a combination of acquisitions and to a lesser extent sales to new customers in existing markets. Since home heating usage is the most sensitive to temperature, residential customers account for the greatest usage variation due to weather. Variations in the weather in one or more regions in which we operate, however, 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, Truck Fabrication and 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, 2005, we owned a fleet of approximately 69 tractors, 252 transports, 1,045 bobtail and rack trucks and 1,017 other service vehicles. In addition to supporting our retail and wholesale propane

8

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 fabrication and maintenance facilities located in Indiana, Florida, and Texas. We also have a trucking operation located in California as part of our NGL business. We believe that our ability to build and maintain the trucks we use in our propane operations significantly reduces the costs we would otherwise incur in purchasing and 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. Our most significant trade names that we operate under are “Arrow Gas”, “Blue Flame”, “Bradley Propane”, “Burnwell Gas”, “Country Gas”, “Dowdle Gas”, “Gaylord Gas”, “Hancock Gas”, “Highland Propane”, “Hoosier Propane”, “Independent Propane”, “Maingas”, “McCracken”, “Modern Gas”, “Moulton Gas Service”, “Northwest Energy”, “Ohio Gas”, “Pearl Gas”, “Pro Gas” , “Pulver Gas”, “United Propane”, and “Tru-Gas”. We regard our trademarks, trade names and other proprietary rights as valuable assets and believe that they have significant value in the marketing of our products.

Wholesale Supply, Marketing and Distribution Operations

We currently provide wholesale supply, marketing and distribution services to independent dealers, multi-state marketers, petrochemical companies, refinery and gas processors and a number of other NGL marketing and distribution companies, primarily in the Midwest and Southeast. While our wholesale supply, marketing and distribution operations accounted for approximately 31% of total revenue, this business represented only approximately 2% of our gross profit during the fiscal year ended September 30, 2005.

Marketing and Distribution

One of our distinguishing strengths is our procurement and distribution expertise and capabilities. Because of the size of our wholesale operations, we have developed significant procurement and distribution expertise. 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.

9

During the fiscal year ended September 30, 2005, Plains Marketing, L.P. accounted for approximately 6% of our wholesale revenue. No other single wholesale customer accounted for more than 5% of our revenue for the same period.

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, 2005, a majority of our sales volume was purchased pursuant to contracts that have a term of one year; 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.

Three suppliers, Sunoco, Inc. (15%), Dominion Transmission Inc. (13%), and Exxon Mobil Oil Corp. (13%), accounted for approximately 41% of propane purchases during the past fiscal year. We believe our contracts with these suppliers will enable us to purchase most of our supply needs at market prices and ensures adequate supply. No other single supplier accounted for more than 10% of our propane purchases in the current year.

Propane generally is transported from refineries, pipeline terminals, storage facilities and marine terminals to our approximately 500 storage 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 insure the availability of propane during periods of short supply. We are currently a party to propane futures transactions on the New York Mercantile Exchange and to 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

Our NGL business located near Bakersfield, CA, currently provides natural gas gathering/processing, liquids processing and fractionation, rail and truck terminalizing, propane storage, natural gas liquids transportation, and purchase and sale of LPG purity products.

Our natural gas storage facility (Stagecoach) was acquired on August 9, 2005 and is a high performance, multi-cycle natural gas storage facility with approximately 13.6 Bcf of working gas capacity, maximum withdrawal capability of 500 MMcf/day, and maximum injection capability of 250 MMcf/day. Located approximately 150 miles northwest of New York City, the Stagecoach facility is currently connected to Tennessee Gas Pipeline Company’s 300 Line and is a significant participant in the northeast United States natural gas distribution system.

For more information on our reportable business segments, see Note 10 to our Consolidated Financial Statements.

Employees

As of November 1, 2005, we had 2,862 full-time employees and 92 part-time employees. Of the 2,954 employees, 96 were general and administrative and 2,858 were operational. Of the operational employees, 147 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. Management believes that the procedures

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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.

With respect to our midstream operations, the Federal Energy Regulatory Commission (“FERC”) regulates the performance of interstate storage services and the rates charged for such services. Terms and conditions of such services are subject to tariffs approved by the FERC. For example, FERC Order Nos, 636, 637 and 637-A, require that interstate storage service providers must, among other things, have unbundled services with separate rates, and have tariff language complying with regulatory requirements regarding scheduling procedures and imbalance management services. Furthermore, FERC Order No. 2004 sets out Standards of Conduct that apply to interstate gas transmission pipelines and public utilities, governing their relationships with energy affiliates. FERC has found that we are a “transmission provider” and therefore subject to the requirements of Order No. 2004. However, FERC has granted us an exemption from these requirements based on the fact that we are an independent storage company that: (i) is not connected with facilities of affiliated pipelines, (ii) does not exercise market power, (iii) has no exclusive franchise, (iv) has no captive rate payers, (v) does not base its rates on its cost of service, (vi) has no guaranteed rate of return, and (vii) has no ability to cross-subsidize at-risk business with rate payer contributions.

Certain aspects of our midstream operations are also subject to the Pipeline Safety Act of 2002, which provides guidelines in the area of testing, education, training and communication. In addition to pipeline integrity tests, pipeline and storage companies are required to implement a qualification program to make certain that employees are properly trained. The United States Department of Transportation has approved our qualification program. We believe that we are in substantial compliance with these requirements and have integrated appropriate aspects of the law into our Operator Qualification Program, which is in place and functioning.

Additionally, we are subject to various federal, state and local environmental, health and safety laws and regulations related to our operations. Generally, these laws impose limitations on the discharge and emission of pollutants and establish standards for the handling of solid and hazardous wastes. These laws generally include the Resource Conservation and Recovery Act, the Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), the Clean Air Act, the Occupational Safety and Health Act, the Emergency Planning and Community Right to Know Act, the Clean Water Act and comparable state or local statutes. CERCLA, also known as the “Superfund” law, imposes joint and several liability without regard to fault or the legality of the original conduct on certain classes of persons that are considered to have contributed to the release or threatened release of a hazardous substance into the environment. While propane is not a hazardous substance within the meaning of CERCLA, other chemicals used in our operations may be classified as hazardous. The laws and regulations referred to above could result in the imposition of civil or criminal penalties in cases of non-compliance or the imposition of liability for remediation costs. We have not received any notices that we have violated these laws and regulations in any material respect and we have not otherwise incurred any material liability thereunder.

For acquisitions that involve the purchase of real estate, we conduct due diligence investigations to attempt to determine whether any substance 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 hazardous substance contamination, compliance violations and the existence of underground storage tanks.

Future developments, such as stricter environmental, health or safety laws and regulations, 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.

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Item 2. Properties.

As of November 1, 2005, we owned 222 of our 342 retail propane customer service centers and leased the balance. 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 approximately 40.2 million gallons of propane at seven locations under annual lease agreements. 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, 2005, we owned the following:

• approximately 1,087 bulk storage tanks at approximately 536 locations with typical capacities of 12,000 to 30,000 gallons,

• approximately 540,000 stationary customer storage tanks with typical capacities of 100 to 1,200 gallons, and

• approximately 150,000 portable propane cylinders with typical capacities of up to 35 gallons.

We believe that we have satisfactory title or valid rights to use all of our material properties. Although some of these properties are subject to liabilities and leases, liens for taxes not yet due and payable, encumbrances securing payment obligations under non-competition agreements entered in connection with acquisitions and immaterial encumbrances, easements and restrictions, we do not believe that any of these burdens will materially interfere with our continued use of these properties in our business, taken as a whole. Our obligations under our borrowings 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 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. In addition, the occurrence of an explosion may have an adverse effect on the public’s desire to use our products.

Item 4. Submission of Matters to a Vote of Security Holders.

No matter was submitted to a vote of the holders of our company’s common units during the fourth quarter of the fiscal year ended September 30, 2005.

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PART II

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

Since July 31, 2001 our company’s common units representing limited partner interests have been traded on Nasdaq’s National Market under the symbol “NRGY.” The following table sets forth the range of high and low bid prices of the common units, as reported by Nasdaq, as well as the amount of cash distributions paid per common unit for the periods indicated. All high and low bid prices of the common units as well as the amount of cash distributions paid per common unit for the periods below have been adjusted for the two-for-one split of the outstanding Limited Partnership units completed on January 12, 2004.

Quarters Ended:	Low		High		Cash Distribution Per Unit
Fiscal 2005:
September 30, 2005	$	26.72	$	33.34	$	0.520
June 30, 2005		29.29		34.04		0.510
March 31, 2005		27.81		34.70		0.500
December 31, 2004		24.60		31.25		0.475
Fiscal 2004:
September 30, 2004	$	23.04	$	27.45	$	0.425
June 30, 2004		19.80		24.28		0.415
March 31, 2004		17.61		25.00		0.405
December 31, 2003		20.51		25.00		0.395
Fiscal 2003:
September 30, 2003	$	18.55	$	21.13	$	0.385
June 30, 2003		15.66		20.00		0.375
March 31, 2003		14.16		16.44		0.365
December 31, 2002		13.73		14.73		0.358

As of November 21, 2005, our company had issued and outstanding 35,311,329 common units, which were held by approximately 23,000 unitholders. In addition, as of that date our company had 3,821,884 Senior Subordinated Units representing limited partner interests which were held of record by 36 unitholders, and 1,145,084 Junior Subordinated Units representing limited partner interests which were held of record by 16 unitholders. There is no established public trading market for our company’s subordinated units. In addition, our company had issued and outstanding 769,941 Special Units which were held by Inergy Holdings, LP.

Our company makes quarterly distributions to its partners within approximately 45 days after the end of each fiscal quarter in an aggregate amount equal to its 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 of Inergy, L.P. (as amended), which is incorporated by reference herein as an exhibit to this report.

During the subordination period referred to below, our common units will have the right to receive distributions of available cash from operating surplus in an amount equal to the minimum quarterly distribution of $0.30 per quarter, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any

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distributions of available cash from operating surplus may be made on any Junior or Senior Subordinated Units. The subordination period generally will not end earlier than June 30, 2006 with respect to the Senior Subordinated Units and June 30, 2008 with respect to the Junior Subordinated Units. The Junior Subordinated Units, however, may convert on or after June 30, 2006 if the Partnership has paid at least $1.40 per unit distribution for four consecutive quarters on all limited partner units outstanding. There is no guarantee that we will pay the minimum quarterly distribution on the common units in any quarter, and we will be prohibited from making any distributions to unitholders if it would cause an event of default under our credit facility. The information concerning restrictions on distributions required by this Item 5 is incorporated herein by reference to “Management’s Discussion and Analysis of Financial Condition and Results of Operation— Description of Credit Facility” under Item 7 and Note 4 to our Consolidated Financial Statements.

On August 12, 2005, after meeting the financial tests provided for in our partnership agreement, we completed the conversion of 1,656,684 Senior Subordinated Units into common units. The conversion of Senior Subordinated Units does not impact the amount of cash distributions paid or the total number of limited partnership units outstanding.

On September 28, 2004, a shelf registration statement (File No. 333-118941) was declared effective by the SEC for the periodic sale by us of up to $625 million 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 purposes identified in a prospectus supplement. In December 2004 we issued 5,060,000 common units and in separate transactions issued an additional 3,568,139 common units, representing limited partnership securities under the shelf registration statement. In addition in September 2005, we issued 6,500,000 common units representing limited partnership securities under the shelf registration statement. There is approximately $189 million remaining available under this shelf. No further partnership securities or debt securities have been offered under the shelf registration except as describe above. See “Management’s Discussion and Analysis of Financial Condition and Results of Operation — Liquidity and Sources of Capital” under Item 7.

We did not repurchase any units during the fourth quarter of the fiscal year.

The following table sets forth in tabular format, a summary of our company’s equity compensation plan information as of September 30, 2005:

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 (1)	1,112,564	$	14.87	622,536
Total	1,112,564	$	14.87	622,536

⁽¹⁾ The Inergy Long Term Incentive Plan did not require the approval of security holders.

Item 6. Selected Financial Data.

The following table sets forth selected consolidated financial data and other operating data of Inergy, L.P., and our predecessor, Inergy Partners, LLC. The selected historical consolidated financial data of Inergy, L.P. as of and for the years ended September 30, 2005, 2004, 2003, 2002 and 2001 are derived from the audited consolidated financial statements of Inergy Partners, LLC and Inergy, L.P. The historical consolidated financial data of Inergy Partners, LLC and Inergy, L.P. include the results of operations of its acquisitions from the effective date of the respective acquisitions. For fiscal year 2005, this includes the results of operations of Star Gas from December 1, 2004, the effective date of the acquisition, and the results of operations of Stagecoach Natural Gas Facility From August 9, 2005, the effective date of the acquisition.

“EBITDA” shown in the table below is defined as income before income taxes, plus net interest expense (inclusive of write off of deferred financing costs) and depreciation and amortization expense. Adjusted EBITDA represents EBITDA, excluding the $19.4 million non-cash gain on derivative contracts in 2005. 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

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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. EBITDA and Adjusted EBITDA, as we define it, may not be comparable to EBITDA and Adjusted EBITDA or similarly titled measures used by other corporations or partnerships.

The data in the following table 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. and Predecessor (a) Years Ended September 30,
	2005			2004			2003			2002			2001
	(in thousands except per unit data)
Statement of Operations Data:
Revenues	$	1,050,136		$	482,496		$	363,365		$	208,700		$	168,982
Cost of product sold (excluding depreciation and amortization as shown below)		724,223	(f)		359,053			267,010			134,999			128,926
Gross profit		325,913			123,443			96,355			73,701			40,056
Expenses:
Operating and administrative (b)		197,082			81,296			59,249			45,300			23,000
Depreciation and amortization		50,364			21,089			13,843			11,444			6,532
Operating income		78,467			21,058			23,263			16,957			10,524
Other income (expense):
Interest expense		(34,150	)		(7,878	)		(9,982	)		(8,365	)		(6,670	)
Interest expense related to write-off of deferred financing costs		(6,990	)		(1,216	)		—			(585	)		—
Interest expense related to make whole premium charge		—			(17,949	)(g)		—			—			—
Interest income related to swap value received		—			949			—			—			—
Gain (loss) on sale of property, plant and equipment		(679	)		(203	)		(91	)		140			37
Finance charges		1,817			704			339			115			290
Other		235			106			86			140			168
Income (loss) before income taxes		38,700			(4,429	)		13,615			8,402			4,349
Provision for income taxes		63			167			103			93			—
Net income (loss)	$	38,637		$	(4,596	)	$	13,512		$	8,309		$	4,349
Net income (loss) per limited partner unit:
Basic (c)	$	0.98		$	(0.26	)	$	0.77		$	0.61		$	(0.20	)
Diluted (c)	$	0.96		$	(0.26	)	$	0.76		$	0.60		$	(0.20	)
Weighted average limited partners’ units outstanding:
Basic (c)		31,143			22,027			16,676			13,317			11,452
Diluted (c)		31,853			22,027			16,942			13,520			11,452
Cash distributions per unit	$	1.91		$	1.60		$	1.45		$	1.28			—

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Balance Sheet Data (end of period):
Current assets	$	307,793		$	136,610		$	73,953		$	70,016		$	36,920
Total assets		1,502,244			503,819			362,393			288,232			155,653
Long-term debt, including current portion		559,731			137,601			131,127			124,462			54,132
Partners’ capital		663,894			252,043			178,983			120,916			72,754
Other Financial Data:
EBITDA (d) (unaudited)	$	130,204		$	42,754		$	37,440		$	28,796		$	17,551
Net cash provided by (used in) operating activities		87,669			32,156			34,428			7,779			4,659
Net cash used in investing activities		(840,655	)		(98,330	)		(33,667	)		(94,017	)		(64,025	)
Net cash provided by financing activities		760,162			64,884			670			86,155			60,164
Maintenance capital expenditures(e) (unaudited)		3,648			1,368			1,039			1,556			1,901
Other Operating Data (unaudited):
Retail propane gallons sold		318,367			140,742			119,697			88,515			46,750
Wholesale propane gallons delivered		391,296			368,320			284,721			256,893			147,258
Reconciliation of Net Income (Loss) to EBITDA:
Net income (loss)	$	38,637		$	(4,596	)	$	13,512		$	8,309		$	4,349
Plus:
Income taxes		63			167			103			93			—
Interest expense		34,150			7,878			9,982			8,365			6,670
Interest expense related to write-off of deferred financing costs		6,990			1,216			—			585			—
Interest expense related to make whole premium charge		—			17,949	(g)		—			—			—
Interest income related to swap value received		—			(949	)		—			—			—
Depreciation and amortization expense		50,364			21,089			13,843			11,444			6,532
EBITDA (d)	$	130,204		$	42,754		$	37,440		$	28,796		$	17,551
Non-cash gain on derivative contracts		19,410			—			—			—			—
Adjusted EBITDA	$	110,794		$	42,754		$	37,440		$	28,796		$	17,551

^(a) Represents selected financial data of Inergy Partners, LLC and its subsidiaries prior to July 31, 2001 and Inergy, L.P. thereafter. All acquisitions are reflected in our results from the effective date of acquisition.

^(b) The historical financial statements include non-cash charges related to amortization of deferred compensation of $234,000 for the year ended September 30, 2001.

^(c) Amounts relate to the net loss incurred by Inergy, L.P. and the weighted average limited partners’ units outstanding for the period from July 31, 2001 (the closing date of our initial public offering) through September 30, 2001.

^(d) EBITDA is defined as income before income taxes, plus net interest expense (inclusive of write off of deferred financing costs) and depreciation and amortization expense. Adjusted EBITDA represents EBITDA excluding the $19.4 million non-cash gain on derivative contracts in 2005. 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 accounting principles generally accepted in the United States as those items are used to measure operating performance, liquidity or ability to service debt obligations. We believe that EBITDA and Adjusted EBITDA provide additional information for evaluating our ability to make the minimum quarterly distribution and is presented solely as a supplemental measure. 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.

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

^(f) Includes $19.4 million non-cash gain on derivative financial instruments.

^(g) Represents the net charge associated with the early retirement of the senior secured notes.

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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 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 the natural gas storage facility (Stagecoach);

• 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; 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.

General

We are a Delaware limited partnership formed to own and operate a rapidly growing retail and wholesale propane supply, marketing and distribution business. For the fiscal year ended September 30, 2005, we sold approximately 318 million gallons of propane to retail customers and delivered approximately 391 million gallons of propane to wholesale customers. Our retail business includes the retail marketing, sale and distribution of propane, including the sale and lease of

17

propane supplies and equipment, to residential, commercial, industrial and agricultural customers. In addition to our retail business, we operate a wholesale supply, marketing and distribution business, providing propane procurement, transportation, 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. We also own and operate a growing midstream operation including a high performance, multicycle natural gas storage facility and an NGL business.

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.

Since the inception of our predecessor in November 1996 through September 30, 2005, we have acquired 49 companies, 47 propane companies and 2 midstream businesses, for an aggregate purchase price of approximately $1.2 billion, including working capital, assumed liabilities and acquisition costs.

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 highest from November through April when customers pay for propane purchased during the six-month peak heating season of October through March. We 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 weather impacting propane usage and are calculated for any given period by adding the difference between 65 degrees and the average temperature of each day in the period (if less than 65 degrees).

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 1976 through 2005. 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 and then on a partnership-wide basis.

The propane business is a “margin-based” business where the level of profitability is largely dependent on the difference between sales prices and product cost. The unit cost of propane is subject to volatile changes as a result of product supply or other market conditions. Propane unit cost changes can occur rapidly over a short period of time and can impact margins as sales prices may not change as rapidly. There is no assurance that we will be able to fully pass on product cost increases, particularly when product costs increase rapidly. We have generally been successful in passing on higher propane costs to our customers and have historically maintained or increased our gross margin per gallon in periods of rising costs. In periods of increasing costs, we have experienced a decline in our gross profit as a percentage of revenues. In periods of decreasing costs, we have experienced an increase in our gross profit as a percentage of revenues. Propane is a by-product of crude oil refining and natural gas processing and, therefore, its cost tends to correlate with the price fluctuations of these underlying commodities. The prices of crude oil and natural gas have maintained historically high costs in 2004 and 2005, and propane has also been at historically high costs. As such, our selling prices have been at higher levels in order to attempt to maintain our historical gross margin per gallon. We expect the historical high cost of crude oil and natural gas to remain for the foreseeable future and accordingly expect both our propane costs and our selling prices to remain at higher levels. Retail sales generate significantly higher margins than wholesale sales, and sales to residential customers generally generate higher margins than sales to our other retail customers.

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;

18

• 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.

Results of Operations

Fiscal Year Ended September 30, 2005 Compared to Fiscal Year Ended September 30, 2004

Volume. During fiscal 2005, we sold 318.4 million retail gallons of propane, an increase of 177.7 million gallons, or 126%, from the 140.7 million retail gallons sold in fiscal 2004. The increase in retail sales volume was principally due to the December 2004 acquisition of Star Gas and 5 other retail propane companies acquired in fiscal 2005, which combined resulted in a 197.5 million gallon increase. This increase was partially offset by an approximate 19.8 million gallon decline in comparable sales, which we believe is due primarily to a combination of warmer weather and conservation by our customers due to an approximate 24% higher propane cost in our retail operations (excluding the $19.4 million non-cash gain on derivative contracts discussed below) to $0.93 per gallon on average in 2005 compared with $0.75 in 2004. Our retail gallon sales will not fluctuate from year to year on a linear basis with the change in weather in our areas of operations. Reasons for this include comparability of geographic areas in which we operate and varying uses of propane (i.e. space heating, cooking and other applications), among others. Although the weather was only approximately 1% warmer in fiscal 2005 as compared to fiscal 2004 (and approximately 6% warmer than normal) in our retail areas of operations, we experienced erratic weather during the winter months of fiscal 2005 including the months of January and February of 2005 being approximately 12% and 15% warmer, respectively, than the same months of 2004 while the month of March 2005 was 28% colder than the month of March 2004.

Wholesale gallons delivered increased 23.0 million gallons, or 6%, to 391.3 million gallons in fiscal 2005 from 368.3 million gallons in fiscal 2004. This increase was primarily attributable to acquisition-related volume, which accounted for 13.2 million gallons of this increase. Additionally, increased sales volumes to new and existing customers, partially offset by the warmer weather in 2005 in our wholesale areas of operations accounted for a net increase of 9.8 million gallons.

The fractionation and throughput gallons of NGLs in our Bakersfield operations increased 40.1 million gallons, or 35%, to 154.9 million gallons in fiscal 2005 from 114.8 million gallons in fiscal 2004. These increases were all primarily attributable to increased sales volumes to new and existing customers. From August 9, 2005, the date of the Stagecoach acquisition, Stagecoach had 13.6 BCF of working gas capacity. Storage at Stagecoach was 85% contracted on average from August 9, 2005 to September 30, 2005.

Revenues. Revenues in fiscal 2005 were $1.05 billion, an increase of approximately $567.5 million, or 118%, from $482.5 million in fiscal 2004.

Revenues from retail propane sales were $526.5 million in fiscal 2005, an increase of $330.2 million, or 168%, from $196.3 million in fiscal 2004. This increase was primarily the result of $327.9 million of sales related to the Star Gas acquisition and other acquisitions together with an increase of approximately $36.4 million due to higher selling prices of propane due to the higher cost of propane in 2005. These increases were partially offset by a $34.1 million decline in revenues as a result of lower retail volume sales at our existing locations as discussed above.

Revenues from wholesale propane sales were $325.1 million in fiscal 2005, an increase of $90.2 million or 38%, from $234.9 million in fiscal 2004. Approximately $71.1 million of this increase was attributable to the higher cost of propane, approximately $14.7 million was attributable to acquisition-related volume, and $4.4 million was attributable to volume increases generated in our wholesale propane operations. The higher selling price in our wholesale division in 2005 compared to 2004 is the result of the higher cost of propane.

Revenues from other retail sales, primarily service, appliance, transportation, and distillates, were $121.5 million in fiscal 2005, an increase of $99.7 million or 457% from $21.8 million in fiscal 2004. This increase was primarily due to the Star Gas acquisition, which contributed approximately $90.2 million of this increase.

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Revenues from storage, fractionation and other midstream activities were $77.0 million in fiscal 2005, an increase of $47.5 million or 161% from $29.5 million in fiscal 2004. Approximately $43.7 million of this increase was due to increased volumes and sales prices of natural gas, butane, and isobutene. Approximately $3.8 million of this increase was due to the acquisition of the Stagecoach natural gas storage facility.

Cost of Product Sold. Retail propane cost of product sold in fiscal 2005 was $275.3 million, an increase of $170.2 million or 162%, from $105.1 million in fiscal 2004. Approximately $25.2 million of this increase was attributable to the higher average cost of propane (excluding the non-cash gain on derivative contracts discussed below) in our retail division and a net additional increase of approximately $164.4 million as a result of retail propane acquisition-related volume described above in excess of the lesser volumes from existing locations. These increases were offset by a non-cash gain on derivative contracts of $19.4 million which will reverse in the first two quarters of fiscal 2006 as the physical gallons are delivered to retail customers.

Wholesale propane cost of product sold in fiscal 2005 was $317.8 million, an increase of $88.7 million or 39%, from wholesale cost of product sold of $229.1 million in 2004. Approximately $70.0 million of this increase was a result of the higher average cost of product, approximately $14.4 million of this increase was a result of acquisition-related volume, and approximately $4.3 million of this increase was the result of higher volumes experienced in our wholesale propane areas of operations.

Other retail cost of product was $71.8 million, an increase of $64.7 million, from other retail cost of product of $7.1 in fiscal 2004. This increase was primarily due to acquisition-related volume.

Fractionation, storage, and other midstream cost of product sold was $59.3 million, an increase of $41.5 million, or 234%, from $17.8 million in fiscal 2004. Approximately $40.8 million of this increase was due to higher volumes and cost of natural gas, butane, and isobutane at the West Coast NGL operations, and approximately $0.7 million was due to acquisition-related volume from the Stagecoach natural gas storage facility.

Our retail cost of product sold consists primarily of tangible products sold including all propane, distillates and other natural gas liquids sold and all propane-related appliances sold. Other costs incurred in conjunction with the distribution of these products are included in operating and administrative expenses and consist primarily of wages to delivery personnel and delivery vehicle costs consisting of fuel costs, repair and maintenance and lease expense. These costs approximated $45.6 million and $23.5 million in 2005 and 2004, respectively. In addition, the depreciation expense associated with the delivery vehicles is reported within depreciation and amortization expense and amounted to $10.8 million and $4.7 million in 2005 and 2004, respectively. Since we include these costs in our operating and administrative expenses rather than in cost of product sold, our results may not be comparable to other entities in our lines of business if they include these costs in cost of product sold.

Gross Profit. Retail propane gross profit was $251.2 million in fiscal 2005 compared to $91.2 million in fiscal 2004, an increase of $160.0 million, or 175%. This increase was primarily attributable to an increase in retail gallons sold primarily as a result of acquisitions, which accounted for approximately $142.8 million, an increase attributable to a non-cash gain of $19.4 million on derivative contracts discussed above, as well as an increase in margin per gallon, which resulted in an increase of approximately $11.3 million. These increases were partially offset by lower retail propane gross profit of approximately $13.5 million at our existing locations as a result of lower volume sales discussed above. The increase in margin per gallon is primarily the result of our ability to increase our selling prices in certain markets in excess of our increased cost of propane.

Wholesale propane gross profit was $7.3 million in fiscal 2005 compared to $5.8 million in fiscal 2004, an increase of $1.5 million or 26%. Approximately $1.1 million of this increase was a result of increased margin per gallon from our existing business, with the balance of the increase attributable to acquisition-related volume, and increased wholesale volumes from our existing business.

Other retail gross profit was $49.7 million in fiscal 2005 compared to $14.7 million in fiscal 2004, an increase of $35.0 million, or 238%. This increase was due primarily to acquisition-related volume.

Fractionation, storage, and other midstream gross profit was $17.7 million in fiscal 2005 compared to $11.7 in fiscal 2004, an increase of $6.0 million, or 51%. This increase was due primarily to acquisition-related volume of $3.2 million and $2.8 million due to increased volumes and margins to existing customers.

Operating and Administrative Expenses. Operating and administrative expenses increased $115.8 million, or 142%, to $197.1 million in fiscal 2005 as compared to $81.3 million in fiscal 2004. The increase in our operating and administrative

20

expenses were primarily attributable to acquisition-related costs, including increases in personnel expenses of $70.3 million, general operating expenses of $32.9 million including insurance, professional services and facility costs, and increased vehicle costs of $12.6 million.

Depreciation and Amortization. Depreciation and amortization increased $29.3 million, or 139%, to $50.4 million in fiscal 2005 from $21.1 million in fiscal 2004 as a result of retail propane acquisitions and the acquisition of the Stagecoach natural gas storage facility.

Interest Expense. Interest expense increased $26.3 million, or 333%, to $34.2 million in fiscal 2005 as compared to $7.9 million in fiscal 2004. Interest expense increased primarily due to an increase of $368.8 million in average debt outstanding in 2005 compared to 2004 primarily as a result of net borrowings for acquisitions, and an approximate 1.4% higher average interest rate in 2005 compared to 2004.

Interest Expense and Income related to Make Whole Premium Charge, Write-off of Deferred Financing Costs, and Swap Value Received. During the fiscal year ended September 30, 2005, we recorded a charge of $7.0 million as a result of the write-off of deferred financing costs associated with the repayment of the previously existing credit agreement and the 364-day facility. During the fiscal year ended September 30, 2004, we repaid in full our $85.0 million senior secured notes before their scheduled maturity dates. As such, we were required to pay an additional amount of approximately $17.9 million as a make whole payment, which was recorded as a charge to earnings in the quarter ended March 31, 2004. We used proceeds from our January 2004 common unit offering and borrowings from our bank credit facility for this repayment. In addition, we also recorded a charge to earnings of approximately $1.2 million in the quarter ended March 31, 2004, to write-off deferred financing costs associated with the senior secured notes. Partially offsetting these charges was a $0.9 million gain from the cancellation of interest rate swap agreements also associated with the Senior Notes.

Net Income (loss). Net income for fiscal 2005 was $38.6 million compared to a net loss of $4.6 million in fiscal 2004. Net income for the fiscal year includes a non-cash gain on derivative contracts of $19.4 million. The net loss in fiscal 2004 was primarily a result of net charges of $18.2 million associated with the early retirement of the senior secured notes.

EBITDA. In fiscal 2005, income before interest, taxes, depreciation and amortization was $130.2 million compared to $42.8 million in fiscal 2004. The increase was primarily attributable to increased sales volumes, higher retail propane margins, and a non-cash gain on derivative contracts partially offset by an increase in operating and administrative expenses. EBITDA is defined as income before taxes, plus net interest expense (inclusive of write-off of deferred financing costs) and depreciation and amortization expense. 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. EBITDA, as we define it, may not be comparable to EBITDA or similarly titled measures used by other corporations or partnerships.

	Year Ended September 30,
	2005		2004
	(in thousands)
EBITDA:
Net income (loss)	$	38,637	$	(4,596	)
Interest expense, net		34,150		7,878
Write off of deferred financing costs		6,990		1,216
Interest expense related to make whole premium charge		—		17,949
Interest income related to swap value received		—		(949	)
Provision for income taxes		63		167
Depreciation and amortization		50,364		21,089
EBITDA	$	130,204	$	42,754

Fiscal Year Ended September 30, 2004 Compared to Fiscal Year Ended September 30, 2003

Volume. During fiscal 2004, we sold 140.7 million retail gallons of propane, an increase of 21.0 million gallons, or 18%, from the 119.7 million retail gallons sold in fiscal 2003. The increase in retail sales volume was principally due to the acquisition of sixteen retail propane companies acquired in fiscal 2004, which combined resulted in a 35.2 million gallon increase. This increase was partially offset by an approximate 14.2 million gallon decline in sales due to a combination of

21

warmer weather and conservation by our customers due to an approximate 14% higher propane cost in our retail operations to $0.75 per gallon on average in 2004 compared with $0.66 in 2003. The weather was approximately 12% warmer in fiscal 2004 as compared to fiscal 2003 in our retail areas of operations, and approximately 6% warmer than normal.

Wholesale gallons delivered increased 83.6 million gallons, or 29%, to 368.3 million gallons in fiscal 2004 from 284.7 million gallons in fiscal 2003. This increase was primarily attributable to a net increase of 47.2 million gallons in our sales volumes in our existing operations partially offset by the warmer weather in 2004 in our wholesale areas of operations. The remaining balance of the increase of 36.4 million gallons was attributable to acquisition related volume increases in wholesale sales volumes through our NGL business in Bakersfield, California acquired in fiscal 2004.

The fractionation and throughput gallons of NGLs in our Bakersfield operations were 114.8 million gallons in fiscal 2004. There were no related sales in fiscal 2003

Revenues. Revenues in fiscal 2004 were $482.5 million, an increase of approximately $119.1 million, or 33%, from $363.4 million in fiscal 2003.

Revenues from retail propane sales were $196.3 million in fiscal 2004, an increase of $42.9 million, or 28%, from $153.4 million in fiscal 2003. This increase was primarily the result of $47.5 million of sales related to the sixteen retail propane acquisitions together with an increase of approximately $13.6 million due to higher selling prices of propane due to the higher cost of propane in 2004. These increases were partially offset by a $18.2 million decline in revenues as a result of lower retail volume sales at our existing locations as discussed above and warmer weather in our retail propane areas of operations.

Revenues from wholesale propane sales were $234.9 million in fiscal 2004, an increase of $44.7 million or 24%, from $190.2 million in fiscal 2003. Approximately $28.0 million of this increase was attributable to volume increases from our wholesale propane operations, and an increase related to acquisition of our NGL business in California, of $25.3 million. These increases were partially offset by an $8.6 million decline in revenues arising from a lower per gallon selling price of propane in our wholesale division due to the lower cost of propane in addition to competitive pressure in certain markets.

Revenues from other retail sales, primarily service, appliance, transportation, and distillates, were $21.8 million in fiscal 2004, an increase of $2.0 million or 10% from $19.8 million in fiscal 2003. This increase was primarily due to acquisition related growth offset by lower comparable sales to new and existing customers at our existing locations as discussed above.

Revenues from storage, fractionation and other midstream activities were $29.5 million in fiscal 2004. This increase was due to the fiscal 2004 acquisition of our NGL business in California.

Cost of Product Sold. Retail propane cost of product sold in fiscal 2004 was $105.1 million, an increase of $26.1 million or 33%, from $79.0 million in fiscal 2003. Approximately $10.4 million of this increase was attributable to the higher average cost of propane in our retail division and a net additional increase of approximately $15.7 million as a result of retail propane acquisition-related volume described above in excess of the lesser volumes from existing locations.

Wholesale propane cost of product sold in fiscal 2004 was $229.1 million, an increase of $49.1 million or 27%, from wholesale cost of product sold of $180.0 million in 2003. Approximately $23.9 million of this increase was a result of the acquisition-related volume as a result of the acquisition of our NGL business in California, and an increase of $28.1 million the result of higher volumes experienced in our wholesale propane areas of operations. These increases were partially offset by a the average lower cost of product in our wholesale division resulting in an approximate $2.9 million decrease in costs.

Other retail cost of product was $7.1 million, a decrease of $0.9 million, from other retail cost of product of $8.0 in fiscal 2004. This net decrease was the result of acquisition related volume, offset by lower volume sales to existing customers.

Fractionation, storage, and other midstream cost of product sold was $17.8 million, due to acquisition-related volume from our NGL business in California. There were no such costs during fiscal 2003.

Our retail cost of product sold consists primarily of tangible products sold including all propane, distillates and other natural gas liquids sold and all propane-related appliances sold. Other costs incurred in conjunction with the distribution of these products are included in operating and administrative expenses and consist primarily of wages to delivery personnel and delivery vehicle costs consisting of fuel costs, repair and maintenance and lease expense. These costs approximated $23.5 million and $17.2 million in 2004 and 2003, respectively. In addition, the depreciation expense associated with the

22

delivery vehicles is reported within depreciation and amortization expense and amounted to $4.7 million and $3.6 million in 2004 and 2003, respectively. Since we include these costs in our operating and administrative expenses rather than in cost of product sold, our results may not be comparable to other entities in our lines of business if they include these costs in cost of product sold.

Gross Profit. Retail propane gross profit was $91.2 million in fiscal 2004 compared to $74.4 million in fiscal 2003, an increase of $16.8 million, or 23%. This increase was primarily attributable to an increase in retail gallons sold primarily as a result of acquisitions, which accounted for approximately $21.0 million, as well as an increase in margin per gallon, which resulted in an increase of approximately $3.2 million. These increases were partially offset by lower retail propane gross profit of approximately $7.4 million at our existing locations as a result of lower volume sales and the deferral of purchases by our customers due to higher cost of propane in 2004 as compared to 2003 as discussed above. The increase in margin per gallon is primarily the result of our ability to increase our selling prices in certain markets in excess of our increased cost of propane.

Wholesale propane gross profit was $5.8 million in fiscal 2004 compared to $10.2 million in fiscal 2003, an decrease of $4.4 million or 43%. Approximately $5.7 million of this increase was a result of decreased margin per gallon from our existing business, offset by an increase of $1.3 million attributable to acquisition-related volume.

Other retail gross profit was $14.7 million in fiscal 2004 compared to $11.8 million in fiscal 2003, an increase of $3.0 million, or 26%. This increase was due primarily to acquisition-related volume.

Fractionation, storage, and other midstream gross profit was $11.7 million in fiscal 2004. This increase was due primarily to acquisition-related volume of our NGL business in California.

Operating and Administrative Expenses. Operating and administrative expenses increased $22.1 million, or 37%, to $81.3 million in fiscal 2004 as compared to $59.2 million in fiscal 2003. The increase in our operating and administrative expenses were primarily attributable to acquisition-related costs, including increases in personnel expenses of $13.4 million, general operating expenses of $5.9 million including insurance, professional services and facility costs, and increased vehicle costs of $2.8 million.

Depreciation and Amortization. Depreciation and amortization increased $7.3 million, or 53%, to $21.1 million in fiscal 2004 from $13.8 million in fiscal 2003 as a result of retail propane acquisitions and the acquisition of our NGL business in California.

Interest Expense. Interest expense decreased $2.1 million, or 21%, to $7.9 million in fiscal 2004 as compared to $10.0 million in fiscal 2003. Interest expense decreased primarily due to a decrease of an approximate 2.15% lower average interest rate in fiscal 2004 compared to fiscal 2003, partially offset by an increase of $6.7 million in average debt outstanding in 2004 compared to 2003 primarily as a result of net borrowings for acquisitions.

Interest Expense and Income related to Make Whole Premium Charge, Write-off of Deferred Financing Costs, and Swap Value Received. During the fiscal year ended September 30, 2004, we repaid in full our $85.0 million senior secured notes before their scheduled maturity dates. As such, we were required to pay an additional amount of approximately $17.9 million as a make whole payment, which was recorded as a charge to earnings in the quarter ended March 31, 2004. We used proceeds from our January 2004 common unit offering and borrowings from our bank credit facility for this repayment. In addition, we also recorded a charge to earnings of approximately $1.2 million in the quarter ended March 31, 2004, to write-off deferred financing costs associated with the senior secured notes. Partially offsetting these charges was a $0.9 million gain from the cancellation of interest rate swap agreements also associated with the senior secured notes.

Net Income (loss). Net loss for fiscal 2004 was $(4.6) million compared to a net income of $13.5 million in fiscal 2003. The net loss in fiscal 2004 was primarily a result of net charges of $18.2 million associated with the early retirement of the senior secured notes which together with higher operating expenses and higher depreciation and amortization as a result of acquisitions offset the increased gross profit.

EBITDA. In fiscal 2004, income before interest, taxes, depreciation and amortization was $42.8 million compared to $37.4 million in fiscal 2003. The increase was primarily attributable to increased sales volumes, higher retail propane margins, partially offset by an increase in operating and administrative expenses. EBITDA is defined as income before taxes, plus net interest expense (inclusive of write-off of deferred financing costs) and depreciation and amortization expense. 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

23

and is presented solely as a supplemental measure. EBITDA, as we define it, may not be comparable to EBITDA or similarly titled measures used by other corporations or partnerships.

	Year Ended September 30,
EBITDA (in thousands)	2004			2003
EBITDA:
Net income	$	(4,596	)	$	13,512
Interest expense, net		7,878			9,982
Write-off of deferred financing costs		1,216			—
Interest expense related to make whole premium charge		17,949			—
Interest income related to swap value received		(949	)		—
Provision for income taxes		167			103
Depreciation and amortization		21,089			13,843
EBITDA	$	42,754		$	37,440

Liquidity and Sources of Capital

In December 2004, we issued 3,568,139 common units to unrelated third parties resulting in proceeds of $91.0 million. These proceeds were utilized to partially fund the acquisition of Star Gas.

Also in December 2004, we issued 4,400,000 common units in a public offering, resulting in proceeds of $121.3 million, net of underwriter’s discount, commission, and offering expenses. These funds were used to repay borrowings under our Credit Agreement (as defined below).

In January 2005, the underwriters of the December 2004 common unit offering exercised their over-allotment provision and we issued 660,000 common units in a follow-on offering, resulting in proceeds of approximately $17.9 million, net of underwriters’ discounts, commissions, and offering expenses. These funds were used to repay borrowings under our Credit Agreement.

On August 9, 2005, Inergy, L.P. issued for aggregate gross proceeds of $25 million, 769,941 special units (the “Special Units”), representing a new class of equity securities in us that are not entitled to a current cash distribution and will convert into common units representing limited partnership interests in us at a specified conversion rate upon the commercial operation of the Stagecoach expansion project as described below. The Special Units were issued to fund the announced $25 million acquisition of the rights to the Phase II expansion project of the Stagecoach natural gas storage facility in connection with the Stagecoach Acquisition and were issued to Inergy Holdings, L.P. (“Holdings”), a Delaware limited partnership, and an affiliate of Inergy, L.P.

In September 2005, Inergy, L.P. issued 6,500,000 common Units to unrelated third parties resulting in net proceeds after underwriters’ discounts, commissions, and offering expenses of $180.4 million. These proceeds were obtained to repay borrowings under our Credit Agreement, which were incurred to make certain acquisitions, including the acquisition of the Stagecoach natural gas storage facility.

Cash flows provided by operating activities of $87.7 million in fiscal 2005 consisted primarily of the following: net income of $38.6 million; net non-cash charges of $51.8 million, including depreciation and amortization of $50.3 million, net changes of ($10.0) million in price risk management activities due to acquisition-related growth and a recognized non-cash gain on derivative contracts, $7.0 million in write-offs of deferred financing costs related to the repayment of the previously existing credit agreement and 364-day credit facility and $4.5 million of other non-cash charges; and a decrease in cash flows of $2.7 million associated with the changes in operating assets and liabilities. Net cash used relating to changes in operating assets and liabilities was primarily due to the increase in accounts receivable and inventories due to acquisition-related growth, and the seasonal nature of the business and increased wholesale inventory volumes. These declines were partially offset by cash provided from an increase in customer deposits as a result of acquisition-related activity, an increase in accounts payable due to greater propane purchases due to increased propane sales volume and increased accrued expenses due to acquisition-related growth. Cash flows provided by operating activities of $32.2 million in fiscal 2004 consisted primarily of: net loss of $4.6 million; net non-cash charges of $52.0 million relating to depreciation and amortization of $21.1 million, interest expense related to make whole premium charge of $17.9 million associated with the early retirement of the senior secured notes, net changes of $9.7 million in price risk management activities which is consistent with the increase in wholesale inventory and $3.3 million of other non-cash charges; and a decrease in cash flows of $15.2 million associated with the changes in operating assets and liabilities. The cash used in the changes in operating assets and liabilities is primarily

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due to an increase in propane inventory as a result of building our inventory for the peak heating season and an increase in accounts receivable due to acquisition-related growth, the seasonal nature of the business and increased wholesale volumes, offset by an increase in accounts payable due to propane purchases.

Cash used in investing activities was $840.7 million in fiscal 2005 as compared to $98.3 million in fiscal 2004. Fiscal 2005 investing activities included a use of cash of $810.1 million, net of cash acquired, for the acquisition of six retail propane companies and our natural gas storage facility. Fiscal 2004 investing activities included a use of cash of $85.2 million, net of cash acquired, for the acquisition of sixteen retail propane companies and our NGL business in California. Additionally, in fiscal 2005 and 2004, we expended $34.1 million and $14.5 million, respectively for additions of property, plant and equipment to accommodate our growing operations. Deferred acquisition costs of $0.6 million and $0.9 million were incurred in fiscal 2005 and 2004, respectively, related to costs incurred for prospective acquisitions. Proceeds from sale of property, plant and equipment of $4.1 million and $2.3 million were received in fiscal 2005 and 2004, respectively.

Cash provided by financing activities was $760.2 million in fiscal 2005 and $64.9 million in fiscal 2004. Cash provided by financing activities in fiscal 2005 and fiscal 2004 included net borrowings of $415.9 million and $5.2 million, respectively, under debt agreements, including borrowings and repayments of our revolving working capital and acquisition credit facility and the issuance of our senior secured notes. In addition, net proceeds were received from the issuance of common units or special units of $435.6 million and $113.2 million in fiscal 2005 and 2004, respectively. Contributions from non-managing general partner of $1.8 million were received in fiscal 2004. Offsetting these cash sources were $67.8 million and $37.4 million of distributions in fiscal 2005 and fiscal 2004, respectively. Deferred financing costs of $23.5 million and $0.0 million were incurred in fiscal 2005 and fiscal 2004, respectively, related to debt incurred to complete the acquisitions. Additionally, the early repayment of our senior secured notes in fiscal 2004 resulted in interest expense related to make whole premium payment to the lenders in the amount of $17.9 million.

At September 30, 2005 and 2004, we had goodwill of $249.2 million and $75.6 million, representing approximately 17% and 15% of total assets, respectively. This goodwill is attributable to our acquisitions. We expect recovery of the goodwill through future cash flows associated with these acquisitions.

At September 30, 2005, we were in compliance with all debt covenants to our credit facilities.

The following table summarizes our company’s obligations as of September 30, 2005, in thousands of dollars:

	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)	$	874,973	$	46,180	$	79,442	$	191,731	$	557,620
Future minimum lease payments under noncancelable operating leases		18,576		5,751		8,247		2,749		1,829
Fixed price purchase commitments		232,385		231,253		1,132		—		—
Standby letters of credit		22,007		21,307		700		—		—

^(a) $226.8 million of our long-term debt is variable interest rate debt at prime rate or LIBOR plus an applicable spread. These rates plus their applicable spreads were between 6.19% and 7.75% at September 30, 2005. These rates have been applied for each period presented in the table.

In addition to it’s fixed price purchase commitments, the company also had forward purchase energy contracts. As of September 30, 2005, total energy contracts had an outstanding net fair value of $8.8 million, as compared to a net fair value of $(6.6) million as of September 30, 2004. The net change of $15.4 million includes a net decrease in fair value of $4.7 million from energy contracts settled during the 2005 fiscal year period, an increase of $1.9 million from contracts acquired during fiscal year 2005, and a net increase of $18.2 million from other changes in fair value related to net unrealized gains on energy contracts still outstanding at the end of fiscal 2005. Of the outstanding fair value as of September 30, 2005, all energy contracts mature within fifteen months. In addition, at September 30, 2005, the company has committed to purchase approximately 70 million gallons of propane at future dates at the prevailing market price.

On September 28, 2004, a shelf registration statement (File No. 333-118941) was declared effective by the SEC for the periodic sale by us of up to $625 million 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 purposes identified in a prospectus supplement. In December 2004 and January 2005 we issued a total of 5,060,000 Common units and in separate transactions issued an additional 3,568,139 common units, representing limited partnership securities under the shelf registration statement. In addition in September 2005, we issued 6,500,000 common units representing limited partnership securities under the shelf registration statement. There is approximately $189 million

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remaining available under this shelf. No further partnership securities or debt securities have been offered under the shelf registration except as describe above. See “Management’s Discussion and Analysis of Financial Condition and Results of Operation — Liquidity and Sources of Capital” under Item 7.

We believe that anticipated cash from operations and borrowings under our amended and restated credit facility 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 any acquisitions, we may need to raise additional capital. We may not be able to raise additional funds or may not be able to raise such funds on favorable terms.

Description of Credit Facility

On December 17, 2004, Inergy entered into a 5-Year Credit Agreement (the “Credit Agreement”) with its existing lenders in addition to others. The Credit Agreement consists of a $75 million revolving working capital facility (“Working Capital Facility”) and a $350 million revolving acquisition facility (“Acquisition Facility”). The Credit Agreement carries terms, conditions and covenants substantially similar to the previous credit agreement. The Credit Agreement is secured by a first priority lien on substantially all of Inergy’s assets and those of its domestic subsidiaries and the pledge of all of the equity interests or membership interests in its domestic subsidiaries. In addition, the Credit Agreement is guaranteed by each of Inergy’s domestic subsidiaries. The Credit Agreement accrues interest at either prime rate or LIBOR plus applicable spreads, resulting in interest rates between 6.19% and 7.75% at September 30, 2005. At September 30, 2005, borrowings outstanding under the Credit Agreement were $126.8 million, including $20 million under the Working Capital Facility. Of the outstanding Credit Agreement balance of $126.8 million, $111.8 million is classified as long-term in the accompanying 2005 consolidated balance sheet. At November 1, 2005, the borrowings outstanding under the Credit Agreement were $299.2 million, including $41.6 million under the Working Capital Facility.

During each fiscal year beginning October 1, the outstanding balance of the Working Capital Facility must be reduced to $5.0 million or less for a minimum of 30 consecutive days during the period commencing March 1 and ending September 30 of each calendar year.

At Inergy’s 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. Inergy also pays a fee based on the average daily unused commitments under the Credit Agreement.

Inergy is 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 Inergy and its domestic subsidiaries, and the sale or disposition of obsolete or worn-out equipment) to reduce borrowings under the Credit Agreement during any fiscal year in which unapplied net cash proceeds are in excess of $50 million. Any such mandatory prepayments are first applied to reduce borrowings under the Acquisition Facility and then under the Working Capital Facility.

In addition, the Credit Agreement contains various covenants limiting the ability of Inergy and its subsidiaries 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 in 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 $20 million in any fiscal year;

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• 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 Inergy or its subsidiaries have actual exposure;

• enter into put agreements granting put rights with respect to equity interests of Inergy or its subsidiaries;

• prepay, redeem, defease or otherwise acquire any permitted junior debt or make certain amendments to permitted junior debt; and

• modify their respective organizational documents.

“Permitted junior debt” consists of:

• Inergy’s $425 million 6.875% senior notes due December 15, 2014 that were issued on December 22, 2004;

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

• other debt of Inergy and its 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 Inergy’s total funded debt to consolidated EBITDA is less than 5.0 to 1.0 on a pro forma basis;

• the debt does not mature, and no installments of principal are due and payable on the debt, prior to the maturity date of the Credit Agreement; and

• other than in connection with the 6.875% 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 Inergy’s 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 5.50 to 1.0 as of the end of the fiscal quarters ending December 31, 2004, March 31, 2005, June 30, 2005, and September 30, 2005 and no greater than 4.75 to 1.0 as of the end of each fiscal quarter thereafter.

• the ratio of Inergy’s senior secured funded debt (as defined in the Credit Agreement) to consolidated EBITDA for the four fiscal quarters most recently ended determined as of the end of each fiscal quarter ending on and after December 31, 2005 for the period of four consecutive fiscal quarters ending with the end of such fiscal quarter must be no greater than 3.75 to 1.0.

• the ratio of Inergy’s 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.

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;

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• bankruptcy and other insolvency events of Inergy or its material subsidiaries;

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

• judgments exceeding $2.5 million (to the extent not covered by insurance) against Inergy or any of its subsidiaries are undischarged or unstayed for 30 consecutive days;

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

• the occurrence of certain change of control events with respect to Inergy.

On November 7, 2005, we amended the Credit Agreement with existing lenders to, among other changes, have the following impact to the credit provisions of the agreement:

• Lowered the applicable margin in the leverage-based pricing grid;

• Extended the maturity from December 17, 2009 to November 10, 2010;

• Increased to $75.0 million the effective amount of working capital borrowings available through the utilization of the acquisition revolver; and

• Other terms, conditions and covenants remained materially unchanged.

Senior Unsecured Notes

On December 22, 2004, Inergy and its wholly owned subsidiary, Inergy Finance Corp. (“Finance Corp.” and together with Inergy, the “Issuers”), completed a private placement of $425 million in aggregate principal amount of the Issuers’ 6.875% senior unsecured notes due 2014 (the “Senior Notes”). Inergy used the net proceeds from the $425 million private placement of 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 Inergy, with the $39.9 million remaining balance of the net proceeds being applied to the Acquisition Facility.

The Senior Notes represent senior unsecured obligations of Inergy and rank pari passu in right of payment with all other present and future senior indebtedness of Inergy. The Senior Notes are effectively subordinated to all of Inergy’s 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 Inergy’s non-guarantor subsidiaries. The Senior Notes rank senior in right of payment to all of Inergy’s future subordinated indebtedness.

The Senior Notes are jointly and severally guaranteed by all of Inergy’s current 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 Inergy). The subsidiaries guarantees rank senior in right of payment to all of Inergy’s future subordinated indebtedness.

Before December 15, 2007, Inergy may, at any time or from time to time, redeem up to 35% of the aggregate principal amount of the Senior Notes with the net proceeds of a public or private equity offering at 106.875% of the principal amount of the Senior Notes, plus any accrued and unpaid interest, if at least 65% of the aggregate principal amount of the notes remains outstanding after such redemption and the redemption occurs within 120 days of the date of the closing of such equity offering.

The Senior Notes are redeemable, at Inergy’s option, in whole or in part, at any time on or after December 15, 2009, in each case at the redemption prices described in the table below, together with any accrued and unpaid interest to the date of the redemption.

Year	Percentage
2009	103.438	%
2010	102.292	%
2011	101.146	%
2012 and thereafter	100.000	%

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Subsequently, on October 26, 2005, Inergy completed an offer to exchange our existing Senior Notes for $425 million of 6.875% senior notes due 2014 (the “Exchange Notes”) that are registered and do not carry transfer restrictions, registration rights and provisions for additional interest. The Exchange Notes did not provide us with any additional proceeds and satisfied our obligations under the registration rights agreement.

On June 7, 2002, we entered into a note purchase agreement with a group of institutional lenders pursuant to which we issued $85.0 million aggregate principal amount of senior secured notes with a weighted average interest rate of 9.07% and a weighted average maturity of 5.9 years. The funds from a public unit offering, together with net new borrowings under a then-existing revolving credit facility were used to repay in full $85.0 million aggregate principal amount of senior secured notes, plus interest expense related to a make whole premium charge of approximately $17.9 million in January 2004. All interest rate swap agreements were cancelled in conjunction with the repayment of $85 million of senior secured notes. The interest expense related to the make whole premium charge of $17.9 million was recorded as a charge to earnings in the quarter ended March 31, 2004 together with the write-off of the $1.2 million deferred financing costs associated with the senior secured notes, partially offset by a $0.9 million gain from the cancellation of the interest rate swaps.

Recent Accounting Pronouncements

On December 16, 2004, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 123 (revised 2004), Share-Based Payment, which is a revision of SFAS No. 123, Accounting for Stock-Based Compensation. SFAS 123(R) supersedes APB Opinion No. 25, Accounting for Stock Issued to Employees, and amends FASB Statement No. 95, Statement of Cash Flows. Generally, the approach in SFAS No. 123(R) is similar to the approach described in SFAS No. 123. However, SFAS No. 123(R) requires all share-based payments to employees, including grants of employee stock options, to be recognized in the income statement based on their fair values. Pro forma disclosure is no longer an alternative.

SFAS No. 123(R) permits public companies to adopt its requirements using one of two methods:

A “modified prospective” method in which compensation cost is recognized beginning with the effective date (a) based on the requirements of SFAS No. 123(R) for all share-based payments granted after the effective date and (b) based on the requirements of SFAS No. 123 for all awards granted to employees prior to effective date of SFAS No. 123(R) that remain unvested as of the effective date.

A “modified retrospective” method which includes the requirements of the modified prospective described above, but also permits entities to restate based on the amounts previously recognized under SFAS No. 123 for purposes of pro forma disclosures either (a) all prior periods presented or (b) prior interim periods of the year of adoption.

On October 1, 2005, the company adopted SFAS No. 123(R) using the modified prospective method.

As permitted by SFAS No. 123, during the fiscal year ended September 30, 2005, the Company accounted for share-based payments to employees using Opinion 25’s intrinsic value method and, as such, generally recognizes no compensation cost for employee stock options. The impact of adoption of SFAS No. 123(R) will depend on levels of share-based payments granted in the future. However, had we adopted SFAS No. 123(R) in prior periods, the impact would have approximated the impact of SFAS No. 123 as described in the disclosure of pro forma net income and earnings per share in the footnotes to the consolidated financial statements. The adoption of SFAS No. 123(R)’s fair value method is not expected to have a significant impact on our results of operations or on our overall financial position.

SFAS No. 151, “Inventory Costs, an amendment of ARB No. 43, Chapter 4,” amends the existing standard that provides guidance on accounting for inventory costs and specifically clarifies that abnormal amounts of costs should be recognized as period costs. This statement is effective for the fiscal year beginning after June 15, 2005. The adoption of SFAS No. 151 is not expected to have a material effect on the Company’s consolidated financial statements.

SFAS No. 153, “Exchanges of Nonmonetary Assets, an amendment of APB Opinion No. 29, Accounting for Nonmonetary Transactions” eliminates the narrow exception for nonmonetary exchanges of similar productive assets and replaces it with a broader exception for exchanges of nonmonetary assets that do not have commercial substance. Further, the amendments made by SFAS No. 153 are based on the principle that exchanges of nonmonetary assets should be measured based on the fair value of the assets exchanged. Previously, Opinion No. 29 required that the accounting for an exchange of a productive asset for a similar productive asset or an equivalent interest in the same or similar productive asset should be based on the recorded amount of the asset relinquished. The statement is effective for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005. Earlier application is permitted for nonmonetary asset exchanges in

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fiscal periods beginning after the date of issuance. The provisions of this statement shall be applied prospectively. The adoption of SFAS No. 153 is not expected to have a material effect on the Company’s consolidated financial statements.

SFAS No. 154, “Accounting Changes and Error Corrections” is a replacement of APB Opinion No. 20, Accounting Changes, and FASB Statement No. 3, Reporting Accounting Changes in Interim Financial Statements. Statement 154 applies to all voluntary changes in accounting principle and changes the accounting for and a reporting of a change in accounting principle. Statement 154 requires retrospective application to the prior periods’ financial statements of a voluntary change in accounting principle unless it is impracticable. Statement 154 is effective for the accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. The adoption of SFAS No. 154 is not expected to have a material effect on the Company’s consolidated financial statements.

In March 2005, the FASB issued FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations – an interpretation of FASB Statement No. 143 (“FIN 47”). FIN 47 clarifies that the term conditional retirement obligation, as used in FASB Statement No. 143, Asset Retirement Obligations, refers to a legal obligation to perform an asset retirement activity in which the timing or method of settlement, or both, are conditional on a future event that may or may not be within the control of the entity. An entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. FIN 47 is required to be adopted by Inergy for the fiscal year ended September 30, 2006 and we are currently assessing the impact on our financial statements.

Critical Accounting Policies

Accounting for Price Risk Management. Inergy utilizes certain derivative financial instruments to (i) manage its exposure to commodity price risk, specifically, the related change in the fair value of inventories, as well as the variability of cash flows related to forecasted transactions; (ii) to ensure adequate physical supply of commodity will be available; and (iii) manage its exposure to interest rate risk. Inergy records all derivative instruments on the balance sheet as either assets or liabilities measured at fair value under the provisions of Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”), as amended. 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 hedge transaction.

On the date the derivative contract is entered into, Inergy designates the derivative as either a hedge of the fair value of a recognized asset or liability or of an unrecognized firm commitment (fair value hedge), or a hedge of a forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability (cash flow hedge). Inergy documents all relationships between hedging instruments and hedged items, as well as its risk-management objective and strategy for undertaking various hedge transactions. Inergy uses regression analysis and 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, Inergy discontinues hedge accounting prospectively. When hedge accounting is discontinued because it is determined that the derivative no longer qualifies as an effective hedge, Inergy continues to carry the derivative on the balance sheet at its fair value, and recognized changes in the fair value of the derivative through current-period earnings.

Inergy is party to certain commodity derivative financial instruments that are designated as hedges of selected inventory positions, and qualify as fair value hedges, as defined in SFAS No. 133. Inergy’s overall objective for entering into fair value hedges is to manage its exposure to fluctuations in commodity prices and changes in the fair market value of its inventories as well as to ensure an adequate physical supply will be available. These derivatives are recorded at fair value on the balance sheets 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.

Inergy also enters into derivative financial instruments that qualify as cash flow hedges, which hedge the exposure of variability in expected future cash flows attributable to a particular risk. 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 closes. Any ineffective portion of the gain or loss is recognized as cost of product sold in the current period.

Furthermore, Inergy has elected to use the special hedge accounting rules in SFAS No. 133 and hedge the fair value of certain of its inventory positions, whereby the hedged inventory is marked to market. Inventories purchased under energy contracts subsequent to October 25, 2002, and not otherwise designated as being hedged are carried at the lower-of-cost or market.

The cash flow impact of financial instruments is reflected as cash flows from operating activities in the consolidated statements of cash flows.

Revenue Recognition. Sales of propane and other liquids 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 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 it is earned.

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Impairment of Long-Lived Assets. Pursuant to SFAS No. 142, “Goodwill and Other Intangible Assets,” (“SFAS 142”) 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.

Under the provisions of SFAS 142, we completed the valuation of each of our reporting units and determined no impairment existed as of September 30, 2005.

Statement of Financial Accounting Standards No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (“SFAS 144”) modifies the financial accounting and reporting for long-lived assets to be disposed of by sale and it broadens the presentation of discontinued operations to include more disposal transactions. We implemented SFAS 144 beginning in the fiscal year ending September 30, 2003, with no material effect on our financial position, results of operations and cash flows.

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 workers’ compensation claims, general, product and vehicle liability, and environmental exposures. Losses are accrued based upon management’s estimates of the aggregate liability for claims incurred using certain assumptions followed in the insurance industry and based on past experience.

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.

• 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.

• Terrorist attacks, such as the attacks that occurred on September 11, 2001, have resulted in increased costs, and future war or risk of war may adversely impact our results of operations.

• 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.

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• 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.

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, 2005, we had floating rate obligations totaling approximately $226.8 million for amounts borrowed under our Credit Agreement and swaps associated with our Senior Notes. These floating rate obligations expose us to the risk of increased interest expense in the event of increases in short-term interest rates.

If the floating rate were to fluctuate by 100 basis points from September 2005 levels, our combined interest expense would change by a total of approximately $2.3 million per year.

Commodity Price, Market and Credit Risk

Inherent in the resulting 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. Inergy monitors market risk through a variety of techniques, including daily reporting of the portfolio’s value to senior management. Inergy provides for such risks at the time derivative financial instruments are adjusted to fair value and when specific risks become known. Inergy attempts to minimize credit risk exposure through credit policies and periodic monitoring procedures as well as through customer deposits and letters of credit, as deemed appropriate. The counterparties associated with assets from price risk management activities as of September 30, 2005 and 2004 are generally propane users, retailers and resellers, and 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 transactions, including various types of forward contracts, options, swaps and future 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 purchase obligations and our sales commitments.

Notional Amounts and Terms

The notional amounts and terms of these financial instruments at September 30, 2005 and 2004 include fixed price payor for 12.9 million and 4.9 million barrels, respectively, and fixed price receiver for 14.6 million and 6.5 million barrels, respectively.

Notional amounts reflect the volume of the transactions, but do not represent the amounts exchanged by the parties to the financial instruments. Accordingly, notional amounts do not accurately measure Inergy’s exposure to market or credit risks.

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Fair Value

The fair value of all derivative instruments related to price risk management activities as of September 30, 2005 and 2004 was assets of $58.4 million and $23.0 million, respectively, and liabilities of $49.6 million and $29.6 million, respectively.

The net change in unrealized gains and losses related to all price risk management activities and propane based financial instruments for the years ended September 30, 2005, 2004 and 2003 of $24.1 million, $(1.2) million, and $0.8 million, respectively, are included in cost of product sold in the accompanying consolidated statements of operations. The Company recognized a non-cash gain of $19.4 million on price risk management activities and propane based financial instruments for the year ended September 30, 2005, no similar gain was recognized in the years ended September 30, 2004, and 2003. The market prices used to value these transactions reflect management’s best estimate considering various factors including closing exchange and over-the-counter quotations, recent transactions, time value and volatility factors underlying the commitments.

The following table summarizes the change in the unrealized fair value of energy contracts related to risk management activities for the years ended September 30, 2005 and 2004 where settlement has not yet occurred (in thousands of dollars):

	Year Ended September 30, 2005			Year Ended September 30, 2004
Net unrealized gains and (losses) in fair value of contracts outstanding at beginning of period	$	(6,626	)	$	3,104
Initial recorded value of new contracts entered into during the period		1,881			2,723
Other unrealized gains and (losses) recognized		18,197			(13,148	)
Less: realized gains and (losses) recognized		(4,668	)		695
Net unrealized gains and (losses) in fair value of contracts outstanding at end of period	$	8,784		$	(6,626	)

Of the outstanding unrealized gain (loss) as of September 30, 2005 and 2004, all energy contracts matured within fifteen months.

Sensitivity Analysis

A theoretical change of 10% in the underlying commodity value would result in no significant change in the market value of the contracts as there were approximately 0.5 million gallons of net unbalanced positions at September 30, 2005.

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 ensure 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 adequate and effective as of September 30, 2005.

There have been no changes in our internal controls over financial reporting (as defined in Rule 13(e)-15 or Rule 15d-15(f) of the Exchange Act) or in other factors during the fiscal year covered by this report that has materially affected, or is reasonably likely to materially affect, the internal controls over financial reporting.

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Management’s Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, pursuant to Exchange Act Rules 13a-15(f). Our internal control system was designed to provide reasonable assurance to management and our board of directors regarding the preparation and fair presentation of published financial statements in accordance with generally accepted accounting principles.

Management recognizes that there are inherent limitations in the effectiveness of any system of internal control, and accordingly, even effective internal control can provide only reasonable assurance with respect to financial statement preparation and fair presentation. Further, because of changes in conditions, the effectiveness of internal control may vary over time.

Management’s assessment of and conclusion on the effectiveness of internal control over financial reporting did not include the operations resulting from the acquisition of Star Gas Propane, L.P. or Stagecoach Holdings, LLC, Stagecoach Energy, LLC, Stagecoach Holding II, LLC, and certain assets of Moulton Gas Service, Inc., Northwest Propane, Inc., (collectively “the Acquisitions”) which were acquired during fiscal 2005 and are included in the 2005 consolidated financial statements. The financial reporting systems of the Acquisitions were integrated into the company’s financial reporting systems throughout 2005. 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 $596.6 million and $401.2 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, 2005. 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, 2005, 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 December 8, 2005 on our assessment and on the effectiveness of our internal control over financial reporting, which is included herein.

Item 9B. Other Information

None.

PART III

Item 10. Directors and Executive Officers of the Registrant.

Our Managing General Partner Manages Inergy, L.P.

Inergy GP, LLC, our managing general partner, manages our operations and activities. Our managing general partner is not elected by our unitholders and will not be subject to re-election on a regular basis in the future. Our managing general partner may not be removed unless that removal is approved by the vote of the holders of not less than 66 2/3% of the outstanding units, including units held by the general partners and their affiliates, and we receive an opinion of counsel regarding limited liability and tax matters. Any removal of the managing general partner is also subject to the approval of a successor managing general partner by the vote of the holders of a majority of the outstanding common units and subordinated units, voting as separate classes. 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.

Our managing general partner may appoint two independent directors to serve on a conflicts committee to review specific matters which the board of directors believes may involve conflicts of interest. A conflicts committee will determine if the resolution of any conflict of interest submitted to it is fair and reasonable to us. In addition to satisfying certain other requirements, the members of the conflicts committee must meet the independence standards for service on an audit committee of a board of directors, which standards are established by the Nasdaq National Market. Any matters approved by

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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. 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 Arthur B. Krause and Warren H. Gfeller. The members of the audit committee must meet the independence standards established by the Nasdaq national market. The members of the audit committee are Warren H. Gfeller, Arthur B. Krause and Robert D. Taylor. The board of directors of our managing general partner has determined that Mr. Gfeller is an audit committee financial expert based upon the experience stated in his biography. We believe that he is independent of management. The audit committee’s primary responsibilities are to monitor: (a) the integrity of our financial reporting process and internal control system; (b) the independence and performance of the outside auditors; and (c) the disclosure controls and procedures established by management.

As is commonly the case with publicly-traded limited partnerships, we are managed and operated by our officers 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 non-managing general partner and our managing general partner. As the sole member of our managing general partner, Inergy Holdings has the power to elect our board of directors.

In January 2001, a group of investors in our predecessor acquired the contractual right to elect one member of our board of directors until certain events occurred related to the subordination period of our senior subordinated units. Warren H. Gfeller was the board designee of this investor group. Mr. Gfeller is affiliated with Clayton-Hamilton, LLC, and a member of this investor group.

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	50	President, Chief Executive Officer and Director
Phillip L. Elbert	47	Executive Vice President - Propane Operations and Director
David G. Dehaemers, Jr.	45	Executive Vice President - Corporate Development
R. Brooks Sherman, Jr.	40	Senior Vice President and Chief Financial Officer
Carl A. Hughes	51	Vice President - Business Development
Laura L. Ozenberger	47	Vice President - General Counsel and Secretary
Andrew L. Atterbury	32	Vice President - Corporate Strategy
Warren H. Gfeller	53	Director
Arthur B. Krause	64	Director
Robert A. Pascal	71	Director
Robert D. Taylor	58	Director

John J. Sherman. Mr. Sherman has served as President, Chief Executive Officer and a director since March 2001, and of our predecessor from 1997 until July 2001. Prior to joining our predecessor, he was a vice president with Dynegy Inc. from 1996 through 1997. He was responsible for all downstream propane marketing operations, which at the time were the country’s largest. From 1991 through 1996, Mr. Sherman was the president of LPG Services Group, Inc., a company he co-founded and grew to become one of the nation’s largest wholesale marketers of propane before Dynegy acquired LPG Services in 1996. From 1984 through 1991, Mr. Sherman was a vice president and member of the management committee of Ferrellgas, which is one of the country’s largest retail propane marketers. He also serves as President, Chief Executive Officer and director of Inergy Holdings GP, LLC.

Phillip L. Elbert. Mr. Elbert has served as 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,

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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.

David G. Dehaemers, Jr. Mr. Dehaemers has served as Executive Vice President – Corporate Development since September 2003. Prior to joining Inergy, Mr. Dehaemers served as the Vice President-Corporate Development of Kinder Morgan G.P., Inc. (the general partner of Kinder Morgan Energy Partners, L.P.) and Kinder Morgan, Inc. from 2000 until 2003. He served as Vice President and Chief Financial Officer of Kinder Morgan, Inc. from 1999 until 2000. He served as Vice President, Chief Financial Officer and Treasurer of Kinder Morgan G.P., Inc. from 1997 until 2000.

R. Brooks Sherman, Jr. Mr. Brooks Sherman, Jr. (no relation to Mr. John Sherman) has served as Senior Vice President since September 2002 and Chief Financial Officer since March 2001. Mr. Sherman previously served as Vice President from March 2001 until September 2002. He joined our predecessor in December 2000 as Vice President and Chief Financial Officer. From 1999 until joining our predecessor, he served as Chief Financial Officer of MCM Capital Group. From 1996 through 1999, Mr. Sherman was employed by National Propane Partners, a publicly traded master limited partnership, first as its controller and chief accounting officer and subsequently as its chief financial officer. From 1995 to 1996, Mr. Sherman served as chief financial officer for Berthel Fisher & Co. Leasing Inc. and prior to 1995, Mr. Sherman was in public accounting with Ernst & Young and KPMG Peat Marwick. He also serves as Senior Vice President and Chief Financial Officer of Inergy Holdings GP, LLC.

Carl A. Hughes. Mr. Hughes has served as 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 Midwest 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 Vice President—General Counsel & 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, including Assistant Corporate Secretary from 1996 through 2003. Prior to 1990, Ms. Ozenberger was in a private legal practice. She also serves as Vice President – General Counsel and Secretary of Inergy Holdings GP, LLC.

Andrew L. Atterbury. Mr. Atterbury has served as Vice President—Corporate Strategy since 2003. Prior to that, Mr. Atterbury served as the Director of Corporate Development from 2002 to 2003. From 1999 to 2001, Mr. Atterbury worked in the Corporate Development Group of Kinder Morgan, Inc. and Kinder Morgan G.P., Inc. From 1996 through 1998, Mr. Atterbury was employed by Lehman Brothers, Inc. in its Real Estate Finance Group. Mr. Atterbury earned a B.A. from Dartmouth College and earned an MBA from Columbia University.

Warren H. Gfeller. Mr. Gfeller has been a member of our managing general partner’s board of directors since March 2001. He was a member of our predecessor’s board of directors from January 2001 until July 2001. He has engaged in private investments since 1991. From 1984 to 1991, Mr. Gfeller served as president and chief executive officer of Ferrellgas, Inc., a retail and wholesale marketer of propane and other natural gas liquids. Mr. Gfeller began his career with Ferrellgas in 1983 as an executive vice president and financial officer. Prior to joining Ferrellgas, Mr. Gfeller was the Chief Financial Officer of Energy Sources, Inc. and a CPA at Arthur Young & Co. He also serves as a director of Inergy Holdings GP, LLC, Zapata Corporation and Duckwall-ALCO Stores, Inc.

Arthur B. Krause. Mr. Krause has been a member of our managing general partner’s board of directors since May 2003. Mr. Krause retired from Sprint Corporation in 2002, where he served as Executive Vice President and Chief Financial Officer from 1988 to 2002. He was President of United Telephone-Eastern Group from 1986 to 1988. From 1980 to 1986, he was Senior Vice President of United Telephone System. He also serves as a director of Inergy Holdings GP, LLC and Westar Energy.

Robert A. Pascal. Mr. Pascal joined our managing general partner’s board of directors in July 2003, upon our acquisition of the assets of United Propane, Inc. As the owner and Chief Executive Officer of United Propane, he has 40 years of industry experience.

Robert D. Taylor. Mr. Taylor joined our managing general partner’s board of directors in May 2005. Mr. Taylor, a CPA since 1971, has served as president and chief executive officer of Executive AirShare Corporation, an aircraft fractional ownership company, since November 2001. From August 1998 until September 2001, Mr. Taylor was president of Executive Aircraft Corporation, which sold, maintained and refurbished corporate jets. In August 2002, Executive Aircraft Corporation

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filed a petition for Chapter 11 protection in the U.S. Bankruptcy Court for the District of Kansas and has subsequently emerged from court protection. Mr. Taylor serves as a director of Commercial Federal Corporation and Elecsys Corporation. Mr. Taylor is also a trustee of the University of Kansas Endowment Fund and a member of the Advisory Board for the University of Kansas School of Business.

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, 2005, all section 16(a) filing requirements applicable to our directors, executive officers and greater than 10% unitholders, were met with the exception that Warren H. Gfeller and Robert A. Pascal were each late in filing one statement of changes in beneficial ownership on Form 4 for the conversion of senior subordinated units.

Code of Ethics

We have adopted a code of ethics that applies to our principal executive officer, principal financial officer, principal accounting officer or controller or persons performing similar functions, as well as to all of our other employees. This code of ethics may be found on our website at www.inergypropane.com.

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Item 11. Executive Compensation.

Executive Compensation

The following table sets forth for the periods indicated, the compensation paid or accrued (by us or our affiliates) to the chief executive officer of our managing general partner and four other executive officers for services rendered to us and our subsidiaries. In this report, we refer to these five individuals as the “named executive officers.”

Summary Compensation Table

										Long Term Compensation
		Annual Compensation								Awards			Payouts
Name and Principal Position	Fiscal Year	Salary			Bonus			Other Annual Compen- sation ($) (2)		Restricted Stock Awards ($)		Securities Underlying Options/ SARs (#)	LTIP Payouts ($)		All Other Compen- sation ($)
John. J. Sherman President and Chief Executive Officer	2005 2004 2003	$ $ $	251,506 250,000 250,000		$ $ $	300,000 —   150,000		$ $ $	—   —   —	$ $ $	—   —   —	—   —   —	$ $ $	—   —   —	$ $ $	—   —   —
Phillip L. Elbert Executive Vice President Propane Operations	2005 2004 2003	$ $ $	236,667 200,000 200,000		$ $ $	365,000 125,000 100,000	(3) (3)	$ $ $	—   —   —	$ $ $	—   —   —	—   —   —	$ $ $	—   —   —	$ $ $	—   —   —
David G. Dehaemers, Jr. Executive Vice President- Corporate Development	2005 2004 2003	$ $ $	200,000 200,000 8,333	(1)	$ $ $	200,000 —   —		$ $ $	—   —   —	$ $ $	—   —   —	—   —   50,000	$ $ $	—   —   —	$ $ $	—   —   —
R. Brooks Sherman, Jr. Senior Vice President and Chief Financial Officer	2005 2004 2003	$ $ $	178,409 170,000 170,000		$ $ $	350,000 50,000 100,000	(4,5) (4)	$ $ $	—   —   —	$ $ $	—   —   —	—   —   —	$ $ $	—   —   —	$ $ $	—   —   —
Laura L. Ozenberger Vice President, General Counsel and Secretary	2005 2004 2003	$ $ $	155,637 155,000 99,856	(1)	$ $ $	275,000 —   33,333	(5)	$ $ $	—   —   —	$ $ $	—   —   —	—   —   50,000	$ $ $	—   —   —	$ $ $	—   —   —

⁽¹⁾ Salary for David Dehaemers, Jr. and Laura Ozenberger in fiscal 2003 represents the pro rata portion of his or her annual salary from the date of employment with us.

⁽²⁾ Excludes perquisites and other benefits, unless the aggregate amount of such compensation is equal to the lesser of $50,000 or 10% of the total annual salary and bonus reported for the named executive officer.

⁽³⁾ Includes a payment of $125,000 in partial payment of a bonus conditioned upon the conversion of subordinated units.

⁽⁴⁾ Includes a payment of $50,000 in partial payment of a bonus conditioned upon the conversion of subordinated units.

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⁽⁵⁾ Includes a non-recurring payment of a bonus of $100,000 paid by Inergy Holdings, LP as a result of the completion of the initial public offering of Inergy Holdings, LP.

There were no grants of unit options under the Inergy Long Term Incentive Plan to a named executive officer during fiscal 2005. However, the following named executive officers were granted 40,000 unit options under the Inergy Holdings Long Term Incentive Plan: Phillip L. Elbert, R. Brooks Sherman and Laura L. Ozenberger.

The following table sets forth information with respect to each named executive officer concerning the number and value of exercisable and unexercisable unit options held under the Inergy Long Term Incentive Plan as of September 30, 2005.

Aggregated Option/SAR Exercises in last Fiscal Year and September 30, 2005 Option Values

	Units Acquired on Exercise (#)	Value Realized ($)	Number of Securities Underlying Unexercised Options at September 30, 2005		Value of Unexercised In-the-Money Options at September 30, 2005 (1)
Name			Exercisable	Unexercisable	Exercisable	Unexercisable
John J. Sherman	—	—	—	—	—	$	—
Phillip L. Elbert	—	—	—	111,000	—	$	1,909,200
David G. Dehaemers, Jr.	—	—	—	50,000	—	$	403,750
R. Brooks Sherman, Jr.	—	—	—	75,500	—	$	1,224,200
Laura L. Ozenberger	—	—	—	50,000	—	$	625,000

⁽¹⁾ Based on the $28.20 per unit fair market value of our common units on September 30, 2005, the last trading day of fiscal 2005, less the option exercise price.

Employment Agreements

The following named executive officers have entered into employment agreements with our company:

• John J. Sherman, President and Chief Executive Officer;

• Phillip L. Elbert, Executive Vice President—Propane Operations;

• David G. Dehaemers, Jr., Executive Vice President—Corporate Development;

• R. Brooks Sherman, Jr., Senior Vice President—Chief Financial Officer; and

• Laura L. Ozenberger, Vice President—General Counsel and Secretary

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 approximately three or five years. The annual salaries for these individuals are as follows:

•      John J. Sherman	$	300,000
•      Phillip L. Elbert	$	240,000
•      David G. Dehaemers, Jr.	$	200,000
•      R. Brooks Sherman, Jr.	$	200,000
•      Laura L. Ozenberger	$	175,000

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 members of executive management and any other benefits agreed to by the managing general partner. Each of these employees is eligible to participate in the Inergy Long Term Incentive Plan.

Mr. Brooks Sherman and Ms. Laura Ozenberger are each eligible for annual performance bonuses in an amount up to his or her annual salary upon meeting certain established criteria for each year during the term of his or her employment.

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Likewise Messrs. Phillip Elbert and David Dehaemers may receive annual performance bonuses primarily based upon attaining certain levels of distributable cash flow.

Some of the employment agreements provide for additional bonuses conditioned upon the conversion of subordinated units into common units. To the extent not already paid, Messrs. Brooks Sherman and Phillip Elbert will be entitled to bonuses in the amounts of $200,000 and $500,000, respectively, payable upon, and in the same proportion as the conversion of the subordinated units. Ms. Laura Ozenberger will be entitled to a bonus of $200,000 upon the conversion of the subordinated units.

Finally, Mr. John Sherman may receive performance bonuses at the discretion of the board of directors in an amount up to his annual salary and will be entitled to a bonus in the amount of $625,000 at the end of the subordination period.

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, (ii) the performance bonus, or (iii) the bonus tied to the subordination period, 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 Mr. John Sherman, Mr. Phillip Elbert, Mr. Brooks Sherman, and Ms. Laura Ozenberger, 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.

With respect to Mr. Dehaemers, in the event his employment is terminated without cause, Mr. Dehaemers will be entitled to the lesser of $100,000 or the amount due for the remainder of the term of his employment agreement.

Pursuant to the partnership agreement, we will reimburse Inergy Holdings or its affiliates for all expenses of the employment of these individuals related to our activities.

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 summary of the long-term incentive plan contained herein does not purport to be complete but outlines its material provisions. The long-term incentive plan permits the grant of awards covering an aggregate of 1,735,100 common units which are granted in the form of unit options and/or restricted units; however not more than 565,600 restricted units may be granted under the plan. Through September 30, 2005, we have granted an aggregate of 1,112,564 unit options outstanding pursuant to the Inergy Long-Term Incentive Plan. We have not granted any restricted units pursuant to the Inergy Long-Term Incentive Plan. The plan is administered by the compensation committee of the managing general partner’s board of directors.

Restricted Units. A restricted unit is a “phantom” unit that entitles the grantee to receive a common unit upon the vesting of the restricted unit, or in the discretion of the compensation committee, the cash equivalent to the value of a common unit. The compensation committee may make grants under the plan to employees and directors containing such terms as the compensation committee shall determine under the plan. In general, restricted units granted to employees will vest three years from the date of grant; provided, however, that restricted units will not vest before the conversion of any Senior Subordinated Units and will only vest upon, and in the same proportion as, the conversion of Senior Subordinated Units into common units. In addition, the restricted units will vest upon a change of control of the managing general partner or us.

If a grantee’s employment or membership on the board of directors terminates for any reason, the grantee’s restricted units will be automatically forfeited unless, and to the extent, the compensation committee provides otherwise. common units to be delivered upon the vesting of restricted units may be common units acquired by the managing general partner in the open market, common units already owned by the managing general partner, common units acquired by the managing general partner directly from us or any other person or any combination of the foregoing. The managing general partner will be entitled to reimbursement by us for the cost incurred in acquiring common units. If we issue new common units upon vesting of the restricted units, the total number of common units outstanding will increase. Following the subordination period, the compensation committee, in its discretion, may grant tandem distribution equivalent rights with respect to restricted units. Distribution equivalent rights entitle the holder to receive “distributions” with respect to the restricted unit in the same amount as if the holder owned a common unit.

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We intend the issuance of the common units pursuant to the restricted unit portion of the long-term incentive plan to serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation of the common units. Therefore, plan participants will not pay any consideration for the common units they receive, and we will receive no remuneration for such units.

Unit Options. The long-term incentive plan currently permits, and our managing general partner has made, grants of options covering common units. Pursuant to the plan, the compensation committee determines which employees and directors shall be granted options and the number of units that will be granted to such individual. 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 period determined by the compensation committee. In addition, under most unit option grants, the unit options will become exercisable upon a change of control of the managing general partner or us. Generally, unit options will expire after 10 years.

Upon exercise of a unit option, the 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.

Termination and Amendment. The managing general partner’s board of directors in its discretion may terminate the 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 the long-term incentive plan or any part of the 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.

Unit Purchase Plan

Our managing general partner sponsors a unit purchase plan for its employees and the employees of its affiliates. The unit purchase plan permits participants to purchase common units in market transactions from us, our general partners or any other person. All purchases made have been in market transactions, although our plan allows us to issue additional units. We have reserved 100,000 units for purchase under the unit purchase plan. As determined by the compensation committee, the managing general partner may match each participant’s cash base pay or salary deferrals by an amount up to 10% of such deferrals and have such amount applied toward the purchase of additional units. The managing general partner has also agreed to pay the brokerage commissions, transfer taxes and other transaction fees associated with a participant’s purchase of common units. The maximum amount that a participant may elect to have withheld from his or her salary or cash base pay with respect to unit purchases under this plan in any calendar year may not exceed 10% of his or her base salary or wages for the year. Units purchased on behalf of a participant under the unit purchase plan generally are to be held by the participant for at least one year. To the extent a participant desires to sell or dispose of such units prior to the end of this one year holding period, the participant will be ineligible to participate in the unit purchase plan again until the one year anniversary of the date of such sale. The unit purchase plan is intended to serve as a means for encouraging participants to invest in our common units. Common units purchased through the unit purchase plan for the fiscal years ended September 30, 2005, 2004 and 2003 were 10,496 units, 9,518 units, and 10,277 units, respectively.

Reimbursement of Expenses of the Managing General Partner

Our managing general partner does not receive any management fee or other compensation for its management of Inergy, L.P. Our managing general partner and its affiliates are reimbursed for expenses incurred on our behalf. These expenses include the costs of employee, officer and director compensation and benefits properly allocable to us and all other expenses necessary or appropriate to the conduct of the business of, and allocable to, us. Our partnership agreement provides that our managing general partner will determine the expenses that are allocable to us in any reasonable manner determined by our managing general partner in its sole discretion.

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Compensation of Directors

Officers of our managing general partner who also serve as directors will not receive additional compensation. Mr. Gfeller received an option under our long term incentive plan for 44,400 common units at an exercise price of $11.00 (based on the initial public offering price – split adjusted). Upon joining the board of directors, Mr. Krause received an option under our long-term incentive plan for 40,000 common units at an exercise price of $16.87 (split adjusted) and upon joining the board of directors Mr. Taylor received an option under our long-term incentive plan for 20,000 common units at an exercise price of $31.32 (equal to the closing trading price on the Nasdaq National Market of our common units on the grant date). In addition, each director receives cash compensation of $18,000 per year for attending our regularly scheduled quarterly board meetings. Each non-employee director receives $1,000 for each special meeting of the board of directors attended. Non-employee directors receive $500 per compensation or audit committee meeting attended and $1,000 per conflicts committee meeting attended. Each non-employee director is reimbursed for out-of-pocket expenses in connection with attending meetings of the board of directors or committees. Each director is fully indemnified for actions associated with being a director to the extent permitted under Delaware law.

Compensation Committee Interlocks and Insider Participation

The compensation committee of the board of directors of our managing general partner oversees the compensation of our executive officers. Arthur B. Krause and Warren H. Gfeller serve as the members of the compensation committee, and neither of them was an officer or employee of our company or any of its subsidiaries during fiscal 2005.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters.

The following table sets forth certain information as of November 1, 2005, regarding the beneficial ownership of our units by:

• each person who then beneficially owned more than 5% of such units then outstanding,

• each of the named executive officers of our managing general partner,

• each of the directors of our managing general partner, and

• all of the directors and named executive officers of our managing general partner as a group.

All information with respect to beneficial ownership has been furnished by the respective directors, officers or 5% or more unitholders, as the case may be.

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Name of Beneficial Owner (1)	Common Units Beneficially Owned	Percentage of Common Units Beneficially Owned		Senior Subordinated Units Beneficially Owned	Percentage of Senior Subordinated Units Beneficially Owned		Junior Subordinated Units Beneficially Owned	Percentage of Junior Subordinated Units Beneficially Owned		Percentage of Total Units Beneficially Owned
Inergy Holdings, L.P. (2)	1,717,551	5.0	%	1,093,865	28.6	%	975,924	85.2	%	10.7	%
Bonavita, Inc. (fka United Propane, Inc.) (9) 28 Floral Avenue Key West, FL 33040	2,015,950	5.9	%	272,380	7.1	%	—	—		5.7	%
Country Partners, Inc. (3) 4010 Highway 14 Crystal Lake, IL 60014	—	—		438,246	11.5	%	—	—			*
KCEP Ventures II, L.P. (4) 253 West 47th Street Kansas City, MO 64112	—	—		423,637	11.1	%	—	—			*
Tortoise Energy Infrastructure and Tortoise Capital Advisors, LLC (10) 10801 Mastin, Suite 222 Overland Park, KS 66210	1,837,903	5.2	%	82,495	2.2	%	—	—			*
Kayne Anderson Capital Advisors, LP and Richard A. Kayne (10) 1800 Avenue of the Stars, 2nd FL Los Angeles, CA 90067	3,281,270	9.3	%	—	—		—	—		8.2	%
DIL, Inc. (5) P.O. Box 9 Kendallville, IN 46755	—	—		360,434	9.4	%	—	—			*
Rocky Mountain Mezzanine Fund (6) 1125 17th Street, Suite 2260 Denver, CO 80202	—	—		259,052	6.8	%	—	—			*
John J. Sherman Trusts (7)	1,744,725	5.1	%	1,093,865	28.6	%	975,924	85.2	%	10.7	%
Phillip L. Elbert (5)	—	—		—	—		—	—			*
David G. Dehaemers, Jr.	—	—		—	—		—	—		—
R. Brooks Sherman, Jr.	3,160		*	160		*	—	—			*
Laura L. Ozenberger	1,288		*	268		*	—	—			*
Warren H. Gfeller (8)	5,910		*	6,818		*	—	—			*
Arthur B. Krause	2,500		*	—	—		—	—		—
Robert D. Taylor	1,655		*	—	—		—	—		—
Robert A. Pascal (9)	2,015,950	5.9	%	272,380	7.1	%	—	—		5.7	%
All directors and named executive officers as a group (9 persons)	3,775,188	11.0	%	1,373,491	35.9	%	975,924	85.2	%	16.5	%

 * less than 1%

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⁽¹⁾ Unless otherwise indicated, the address of each person listed above is: Two Brush Creek Boulevard, Suite 200, Kansas City, Missouri 64112. All persons listed have sole voting power and investment power with respect to their units unless otherwise indicated.

⁽²⁾ Of the senior and junior subordinated units indicated as beneficially owned by Inergy Holdings 986,588 senior subordinated units and 975,126 junior subordinated units are held by New Inergy Propane, LLC, a wholly-owned subsidiary of Inergy Holdings and 107,277 senior subordinated units and 798 junior subordinated units are held by Inergy Holdings. Of the common units indicated as beneficially owned by Inergy Holdings, 875,320 units are held by New Inergy Propane, 789,202 units are held by IPCH Acquisition Corp., a wholly-owned subsidiary of Inergy Holdings, and 53,029 are held directly by Inergy Holdings. In addition, Inergy Holdings holds 769,941 Special Units that will convert to common units at a specified conversion rate upon the commercial operations of the Phase II expansion project of our natural gas storage facility (Stagecoach).

⁽³⁾ Country Partners owns less than 5% of our common units.

⁽⁴⁾ KCEP Ventures II, LP owns 423,637 senior subordinated units and owns less than 5% of our common units.

⁽⁵⁾ The Hoosier Propane Group consisted of Domex, Inc., Investors, Inc. and L&L Leasing, Inc., each of which was merged into DIL, Inc. (collectively, the “Hoosier Entities”). DIL, Inc. owns less than 5% of our common units. Each of Jerry Boman, Glen Cook and Wayne Cook own 31.8% of the Hoosier Entities. Mr. Elbert, one of our executive officers, holds the remaining ownership interest in the Hoosier Entities. He disclaims beneficial ownership of the units held by the Hoosier Entities.

⁽⁶⁾ Rocky Mountain Mezzanine Fund owns less than 5% of our common units.

⁽⁷⁾ Mr. Sherman holds an ownership interest in and has voting control of Inergy Holdings GP, LLC, as indicated in the following tables, and therefore may be deemed to beneficially own the units held by Inergy Holdings.

⁽⁸⁾ Mr. Gfeller in his capacity as managing member of Clayton-Hamilton, LLC may be deemed to beneficially own 5,910 common units and 6,818 senior subordinated units held by Clayton-Hamilton.

⁽⁹⁾ United Propane, Inc., a Maryland corporation, now known as Bonavita, Inc, and Inergy Propane, LLC entered into an asset purchase agreement for substantially all the propane assets of United Propane, Inc. in exchange for common and senior subordinated units in Inergy, LP. Mr. Robert A. Pascal, as sole shareholder of United Propane, Inc., is deemed beneficial owner of the partnership units in Inergy, LP held by United Propane, Inc.

⁽¹⁰⁾ Information as to the number of common units is furnished in reliance upon the Schedule 13G’s of the corresponding entities or individuals.

The following table shows the beneficial ownership as of November 1, 2005 of Inergy Holdings, L.P. of the directors and named executive officers of the managing general partner. As reflected above, Inergy Holdings owns our managing general partner, non-managing general partner, the incentive distribution rights and, through subsidiaries, approximately 5% of our outstanding units.

Name of Beneficial Owner (1)	Inergy Holdings, L.P. Percent of Class
John J. Sherman Trusts(2)	42.72	%
Phillip L. Elbert(3)	5.35	%
David G. Dehaemers, Jr. (4)	7.60	%
R. Brooks Sherman Jr.	2.31	%
Laura L. Ozenberger	*
Warren H. Gfeller	*
Arthur B. Krause	*
Robert A. Pascal	*
Robert D. Taylor	—
All directors and executive officers as a group (11 persons)	67.96	%

* less than 1%.

⁽¹⁾ The address of each person listed above is Two Brush Creek Boulevard, Suite 200, Kansas City, Missouri 64112.

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⁽²⁾ John Sherman’s ownership interest in Inergy Holdings is held through the John J. Sherman Revocable Trust and the John J. Sherman 2005 Grantor Retained Annuity Trusts I and II.

⁽³⁾ Phillip L. Elbert’s ownership in Inergy Holdings is held individually and through the Phillip L. Elbert 2005 Grantor Retained Annuity Trust, the Charles W. Elbert Trust, and the Lauren E. Elbert Trust.

⁽⁴⁾ David G. Dehaemers, Jr.’s ownership in Inergy Holdings is held individually and though the David G. Dehaemers, Jr. 2005 Grantor Retained Annuity Trust.

We refer you to Item 5 of this report for certain information regarding securities authorized for issuance under equity compensation plans.

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Item 13. Certain Relationships and Related Transactions.

Related Party Transactions

In connection with our acquisition of assets from United Propane, Inc. on July 31, 2003, we entered into ten leases of real property formerly used by United Propane (now known as Bonavita, Inc.) in its business. We entered into five of these leases with United Propane, three of these leases with Pascal Enterprises, Inc. and two of these leases with Robert A. Pascal. Each of these leases provides for an initial five-year term, and is renewable by us for up to two additional terms of five years each. During the initial term of these leases we are required to make monthly rental payments totaling $59,167, of which $17,167 is payable to United Propane, $16,800 is payable to Pascal Enterprises, and $25,200 is payable to Mr. Pascal.

On May 1, 2004, Inergy Propane, LLC entered into a lease agreement with United Leasing, Inc. to lease a propane rail terminal known as the Curtis Bay Terminal for the base monthly rent of $15,000.

Robert A. Pascal is the sole shareholder of Bonavita, Inc., Pascal Enterprises and United Leasing and is on our managing general partner’s board of directors.

In connection with the financing of our Phase II expansion rights on the Stagecoach natural gas storage facility, our board of directors established an independent committee to determine whether the issuance of Special Units, as described below, was in our best interest. The independent committee engaged an independent legal advisor and an independent financial advisor, who issued an opinion that the transaction was fair from a financial point of view. On August 9, 2005 we entered into the Special Unit Purchase Agreement with Inergy Holdings L.P. Inergy Holdings purchased 769,941 special units (the “Special Units”) for $25,000,000 in cash from us. These units are not entitled to current cash distributions, but are convertible to our common units at a special conversion ratio upon the Phase II expansion becoming commercially operational. The purchase price was based on the ten-day average closing price for the common units ending August 8, 2005.

On August 9, 2005, we also entered into a separate Registration Rights Agreement with Inergy Holdings relating to the Special Units that allows for the registered resale of the units. Pursuant to the Registration Rights Agreement, we have agreed to file a shelf registration statement for the resale of the common units issuable upon conversion of the Special Units within 180 days after the issue date of the Special Units and to use commercially reasonable efforts to cause the shelf registration statement to be declared effective by the SEC within 240 days after the issue date.

On occasion, Inergy Holdings reimburses us for expenses paid on behalf of Inergy Holdings. At September 30, 2005, we had a receivable from Inergy Holdings of $280,368 which is included in prepaid expenses and other current assets on our consolidated balance sheet.

Distributions and Payments to the Managing General Partner and the Non-managing General Partner

Distributions and payments are made by us to our managing general partner and its affiliates in connection with our ongoing operation. These distributions and payments were determined by and among affiliated entities and are not the result of arm’s length negotiations.

Cash distributions will generally be made 98.8% to the unitholders, including affiliates of the managing general partner as holders of common units and senior and junior subordinated units, and approximately 1.2% to the non-managing general partner. In addition, when distributions exceed the target levels in excess of the minimum quarterly distribution, Inergy Holdings is entitled to receive increasing percentages of the distributions, up to 48% of the distributions above the highest target level.

Assuming we have sufficient available cash to pay the full minimum quarterly distribution on all of our outstanding units for four quarters, our non-managing general partner and its affiliates would receive a distribution of approximately $0.6 million on the approximate 1.2% general partner interest and a distribution of approximately $4.5 million on their common, senior subordinated and junior subordinated units.

Our managing general partner and its affiliates will not receive any management fee or other compensation for the management of us. Our managing general partner and its affiliates will be reimbursed, however, for direct and indirect expenses incurred on our behalf. For the fiscal years ended September 30, 2005, 2004 and 2003 the expense reimbursement to our managing general partner and its affiliates was approximately $3.0, $2.9, and $2.1 million, respectively, with the reimbursement related primarily to personnel costs.

If our managing general partner withdraws in violation of the partnership agreement or is removed for cause, a successor general partner has the option to buy the general partner interests and incentive distribution rights from our non-managing general partner for a cash price equal to fair market value. If our managing general partner withdraws or is

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removed under any other circumstances, our non-managing general partner has the option to require the successor general partner to buy its general partner interests and incentive distribution rights for a cash price equal to fair market value.

If either of these options is not exercised, the general partner interests and incentive distribution rights will automatically convert into common units equal to the fair market value of those interests. In addition, we will be required to pay the departing general partner for expense reimbursements.

Upon our liquidation, the partners, including our non-managing general partner, will be entitled to receive liquidating distributions according to their particular capital account balances.

Rights of our Managing General Partner and our Non-managing General Partner

Inergy Holdings owns an aggregate 10.7% interest in us inclusive of ownership of all of our non-managing general partner and our managing general partner. Our managing general partner manages our operations and activities.

Item 14. Principal Accountant Fees and Services

The following table presents fees billed for professional audit services rendered by Ernst & Young LLP for the audit of our annual financial statements and for other services for the years ended September 30, 2005 and 2004.

For the fiscal year ended September 30,	2005		2004
	(in thousands)
Audit fees (1)	$	1,427	$	435
Audit related fees (2)		146		33
Total	$	1,573	$	468

⁽¹⁾ Audit fees consist of assurance and related services that are reasonably related to the performance of the audit or review of our financial statements. This category includes fees related to the review of our quarterly and other SEC filings and services related to internal control assessments.

⁽²⁾ Audit-related fees consist of due diligence fees associated with acquisition transactions, financial accounting and reporting consultations and benefit plan audits.

The Audit Committee of our general partner reviewed and approved all audit and non-audit services provided to us by Ernst & Young during fiscal year 2005 prior to the commencement of such services. For information regarding the Audit Committee’s pre-approval policies and procedures related to the engagement by us of an independent accountant, see our Audit Committee charter on our website at www.inergypropane.com.

PART IV

Item 15. Exhibits and Financial Statement Schedules

(a) Exhibits, Financial Statements and Financial Statement Schedules:

1. Financial Statements:

See Index Page for Financial Statements located on page 52.

2. Financial Statement Schedules:

Valuation and Qualifying Accounts

Other financial statement schedules have been omitted because they either are not required, are immaterial or are not applicable or because equivalent information has been included in the financial statements, the notes thereto or elsewhere herein.

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3. Exhibits:

Exhibit Number	Description
*2.1	Purchase Agreement dated as of July 8, 2005, among Inergy Acquisition Company, LLC, Inergy Storage, Inc., Inergy Stagecoach II, LLC, Stagecoach Holding, LLC, Stagecoach Energy, LLC and Stagecoach Holding II, LLC (incorporated herein by reference to Exhibit 2.1 to Inergy, L.P.’s Form 8-K filed on July 12, 2005)
*2.2	Interest Purchase Agreement, dated November 18, 2004, among Star Gas Partners, L.P., Star Gas LLC, Inergy Propane, LLC and Inergy, L.P. (incorporated herein by reference to Exhibit 2.1 to Inergy L.P.’s Form 8-K filed on November 24, 2004)
*3.1	Certificate of Limited Partnership of Inergy, L.P. (incorporated herein by reference to Exhibit 3.1 to Inergy, L.P.’s Registration Statement on Form S-1 (Registration No. 333-56976) filed on March 14, 2001)
*3.1 A	Certificate of Correction of Certificate of Limited Partnership of Inergy, L.P. (incorporated herein by reference to Exhibit 3.1 to Inergy, L.P.’s Form 10-Q (Registration No. 000-32543) filed on May 12, 2003)
*3.2	Form of Amended and Restated Agreement of Limited Partnership of Inergy, L.P. (incorporated herein by reference to Exhibit 3.2 to Inergy, L.P.’s Registration Statement on Form S-1 (Registration No. 333-56976) filed on March 14, 2001)
*3.2 A	Amendment No. 1 to Amended and Restated Agreement of Limited Partnership of Inergy, L.P. (incorporated herein by reference to Exhibit 3.2A to Inergy, L.P.’s Registration Statement on Form S-1/A (Registration No. 333-89010) filed on June 13, 2002)
*3.2 B	Second Amended and Restated Agreement of Limited Partnership of Inergy, L.P. (incorporated herein by reference to Exhibit 3.1 to Inergy, L.P.’s Form 10-Q (Registration No. 000-32453) filed on February 13, 2004)
*3.2 C	Amendment No. 1 to Second Amended and Restated Agreement of Limited Partnership of Inergy L.P. (incorporated herein by reference to Exhibit 3.1 to Inergy, L.P.’s Form 10-Q (Registration No. 000-32453) filed on May 14, 2004)
*3.2 D	Amendment No. 2 to Second Amended and Restated Agreement of Limited Partnership of Inergy, L.P. (incorporated herein by reference to Exhibit 3.1 to Inergy, L.P.’s Form 8-K filed on January 24, 2005)
*3.2 E	Amendment No. 3 to Second Amended and Restated Agreement of Limited Partnership of Inergy, L.P. (incorporated herein by reference to Exhibit 3.1 to Inergy, L.P.’s Form 8-K/A filed on August 17, 2005)
*3.3	Certificate of Formation as relating to Inergy Propane, LLC, as amended (incorporated herein by reference to Exhibit 3.3 to Inergy, L.P.’s Registration Statement on Form S-1/A (Registration No. 333-56976) filed on May 7, 2001)
*3.4	Third Amended and Restated Limited Liability Company Agreement of Inergy Propane, LLC, dated as of July 31, 2001 (incorporated herein by reference to Exhibit 3.4 to Inergy, L.P.’s Registration Statement on Form S-1 (Registration No. 333-89010 filed on May 24, 2002)
*3.5	Certificate of Formation of Inergy GP, LLC (incorporated herein by reference to Exhibit 3.5 to Inergy, L.P.’s Registration Statement on Form S-1/A (Registration No. 333-56976) filed on May 7, 2001)
*3.6	Limited Liability Company Agreement of Inergy GP, LLC (incorporated herein by reference to Exhibit 3.6 to Inergy, L.P.’s Registration Statement on Form S-1/A (Registration No. 333-56976) filed on May 7, 2001)
*3.7	Certificate of Formation as relating to Inergy Partners, LLC, as amended (incorporated herein by reference to Exhibit 3.7 to Inergy, L.P.’s Registration Statement on Form S-1/A (Registration No. 333-56976) filed on May 7, 2001)
*3.8	Second Amended and Restated Limited Liability Company Agreement of Inergy Partners, LLC, dated as of July 31, 2001 (incorporated herein by reference to Exhibit 3.8 to Inergy, L.P.’s Registration Statement on Form S-1 (Registration No. 333-89010) filed on May 24, 2002)

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*4.1	Specimen Unit Certificate for Senior Subordinated Units (incorporated herein by reference to Exhibit 4.1 to Inergy L.P.’s Registration Statement on Form S-1/A (Registration No. 333-56976) filed on May 7, 2001)
*4.2	Specimen Unit Certificate for Junior Subordinated Units (incorporated herein by reference to Exhibit 4.2 to Inergy L.P.’s Registration Statement on Form S-1/A (Registration No. 333-56976) filed on May 7, 2001)
*4.3	Specimen Unit Certificate for Common Units (incorporated herein by reference to Exhibit 4.3 to Inergy L.P.’s Registration Statement on Form S-1/A (Registration No. 333-56976) filed on May 7, 2001)
*4.4	Registration Rights Agreement dated as of November 29, 2004 between Inergy, L.P. and Kayne Anderson MLP Investment Company (incorporated herein by reference to Exhibit 4.1 to Inergy L.P.’s Form 8-K filed on December 3, 2004)
*4.5	Registration Rights Agreement dated as of November 29, 2004 between Inergy, L.P. and Tortoise Energy Infrastructure Corporation (incorporated herein by reference to Exhibit 4.2 to Inergy L.P.’s Form 8-K filed on December 3, 2004)
*4.6	Registration Rights Agreement (incorporated herein by reference to Exhibit 4.1 to Inergy, L.P.’s Form 8-K filed on December 27, 2004)
*4.7	Indenture (incorporated herein by reference to Exhibit 4.2 to Inergy, L.P.’s Form 8-K filed on December 27, 2004)
*4.8	Registration Rights Agreement dated August 9, 2005 between Inergy, L.P. and Inergy Holdings, L.P. (incorporated herein by reference to Exhibit 4.1 to Inergy, L.P.’s Form 8-K filed on August 12, 2005)
*10.1	Sixth Amended and Restated Credit Agreement by and among Inergy Propane, LLC and the lenders named therein, dated as of May 27, 2004 (incorporated herein by reference to Exhibit 10.1 to Inergy, L.P.’s Form 10-Q (Registration No. 000-32453) filed on August 13, 2004)
*10.2	Securities Purchase Agreement by and among Inergy Partners, LLC and various investors, dated as of January 12, 2001 (incorporated herein by reference to Exhibit 10.3 to Inergy, L.P.’s Registration Statement on Form S-1/A (Registration No. 333-56976) filed on May 7, 2001)
*10.3	Investor Rights Agreement by and among Inergy Partners, LLC and various investors, dated as of January 12, 2001 (incorporated herein by reference to Exhibit 10.4 to Inergy, L.P.’s Registration Statement on Form S-1/A (Registration No. 333-56976) filed on May 7, 2001)
*10.4	Inergy Employee Long-Term Incentive Plan (incorporated herein by reference to Exhibit 10.6 to Inergy, L.P.’s Registration Statement on Form S-1/A (Registration No. 333-56976) filed on July 2, 2001)***
*10.4 A	Amendment to Inergy Long-Term Incentive Plan adopted April 4, 2003. (incorporated herein by reference to Exhibit 10.1 to Inergy, L.P.’s Form 10-Q (Registration No. 000-32543) filed on May 12, 2003)***
*10.5	Employment Agreement—John J. Sherman (incorporated herein by reference to Exhibit 10.8 to Inergy, L.P.’s Registration Statement on Form S-1/A (Registration No. 333-56976) filed on July 2, 2001)***
*10.5 A	First Amendment to Employment Agreement – John J. Sherman (incorporated herein by reference to Exhibit 10.1 to Inergy L.P.’s Form 8-K filed on September 23, 2005)***
*10.6	Employment Agreement—Phillip L. Elbert (incorporated herein by reference to Exhibit 10.9 to Inergy, L.P.’s Registration Statement on Form S-1/A (Registration No. 333-56976) filed on May 7, 2001)***
*10.6 A	First Amendment to Employment Agreement—Phillip L. Elbert (incorporated herein by reference to Exhibit 10.9A to Inergy, L.P.’s Registration Statement on Form S-1/A (Registration No. 333-56976) filed on July 20, 2001)***
*10.6 B	Second Amendment to Employment Agreement – Phillip L. Elbert (incorporated herein by reference to Exhibit 10.1 to Inergy L.P.’s Form 10-Q (Registration No. 000-32453 filed on February 9, 2005)***

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*10.7	Employment Agreement—Carl A. Hughes (incorporated herein by reference to Exhibit 10.11 to Inergy, L.P.’s Registration Statement on Form S-1/A (Registration No. 333-56976) filed on July 2, 2001)***
*10.7 A	First Amendment to Employment Agreement—Carl A. Hughes (incorporated herein by reference to Exhibit 10.2 to Inergy, L.P.’s Form 8-K filed on September 23, 2005)***
**10.8	Employment Agreement – Laura L. Ozenberger***
**10.8 A	First Amendment to Employment Agreement – Laura L. Ozenberger***
*10.9	Intercreditor and Collateral Agency Agreement entered into as of June 7, 2002, by and among Wachovia Bank, National Association, the lenders named therein and the noteholders named therein (incorporated herein by reference to Exhibit 10.19 to Inergy, L.P.’s Registration Statement on Form S-1/A (Registration No. 333-89010) filed on June 13, 2002)
*10.10	Employment Agreement—R. Brooks Sherman, Jr. (incorporated herein by reference to Exhibit 10.20 to Inergy, L.P.’s Form 10-K (Registration No. 000-32453) filed on December 26, 2002)***
*10.10 A	First Amendment to Employment Agreement, dated as of June 20, 2005, by and between Inergy GP, LLC and R. Brooks Sherman, Jr. (incorporated herein by reference to Exhibit 10.1 to Inergy, L.P.’s Form 8-K filed on June 24, 2005)***
*10.11	Separation Agreement and Release with Dean Watson dated August 27, 2005 (incorporated herein by reference to Exhibit 10.1 to Inergy L.P.’s Form 8-K filed on August 29, 2005)***
*10.12	Amended and Restated Inergy Unit Purchase Plan***
*10.13	Employment Agreement—David G. Dehaemers, Jr. (incorporated herein by reference to Exhibit 10.5 to Inergy, L.P.’s Form 10-K (Registration No. 000-32453) filed on December 9, 2004)***
*10.14	5-Year Credit Agreement dated as of December 17, 2004, among Inergy, L.P., the lenders party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Lehman Commercial Paper, Inc. and Wachovia Bank, National Association, as Co-Syndication Agents, and Fleet National Bank and Bank of Oklahoma, National Association, as Co-Documentation Agents (incorporated herein by reference to Exhibit 10.1 to Inergy, L.P.’s Form 8-K filed on December 22, 2004)
*10.14 A	Amendment to the 5-Year Credit Agreement dated as of December 17, 2004, among Inergy, L.P., the lenders party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Lehman Commercial Paper, Inc. and Wachovia Bank, National Association, as Co-Syndication Agents, and Fleet National Bank and Bank of Oklahoma, National Association, as Co-Documentation Agents (incorporated herein by reference to Exhibit 10.2 to Inergy, L.P.’s Form 8-K filed on November 14, 2005).
*10.15	364-Day Credit Agreement dated as of December 17, 2004, among Inergy, L.P., the lenders party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Lehman Commercial Paper, Inc. and Wachovia Bank, National Association, as Co-Syndication Agents, and Fleet National Bank and Bank of Oklahoma, National Association, as Co-Documentation Agents (incorporated herein by reference to Exhibit 10.2 to Inergy, L.P.’s Form 8-K filed on December 22, 2004)
*10.16	Guaranty dated as of December 17, 2004 among Inergy Propane, LLC, L & L Transportation, LLC, Inergy Transportation, LLC, Inergy Sales & Service, Inc., Inergy Finance Corp., Inergy Acquisition Company, LLC, Stellar Propane Service, LLC and Inergy Gas, LLC in favor of JPMorgan Chase Bank, N.A., as Administrative Agent for the benefit of the Holders of Secured Obligations under the Credit Agreements (incorporated herein by reference to Exhibit 10.3 to Inergy, L.P.’s Form 8-K filed on December 22, 2004)
*10.17	Pledge and Security Agreement dated as of December 17, 2004 among Inergy, L.P. and the other Subsidiaries of Inergy, L.P. listed on the signature pages thereto, and JPMorgan Chase Bank, N.A., as administrative agent for the lenders party to the Credit Agreements (incorporated herein by reference to Exhibit 10.4 to Inergy, L.P.’s Form 8-K filed on December 22, 2004)

50

*10.18	Trademark Security Agreement dated as of December 17, 2004 among Inergy, L.P. and the subsidiaries of Inergy, L.P. listed on the signature page attached thereto and JPMorgan Chase Bank, N.A., as administrative agent on behalf of itself and on behalf of the Holders of Secured Obligations under the Credit Agreements (incorporated herein by reference to Exhibit 10.5 to Inergy, L.P.’s Form 8-K filed on December 22, 2004)
*10.19	Noncompetition Agreement, dated December 17, 2004, among Inergy Propane, LLC, Star Gas Partners, L.P. and Star Gas LLC (incorporated herein by reference to Exhibit 10.6 to Inergy, L.P.’s Form 8-K filed on December 22, 2004)
*10.20	Special Unit Purchase Agreement dated August 9, 2005 by and between Inergy, L.P. and Inergy Holdings, L.P. (incorporated herein by reference to Exhibit 10.1 to Inergy, L.P.’s Form 8-K filed on August 12, 2005)
*10.21	Common Unit Purchase Agreement dated as of November 29, 2004 between Inergy, L.P. and Kayne Anderson MLP Investment Company (incorporated herein by reference to Exhibit 10.1 to Inergy L.P.’s Form 8-K filed on December 3, 2004)
*10.22	Common Unit Purchase Agreement dated as of November 29, 2004 between Inergy, L.P. and Tortoise Energy Infrastructure Corporation (incorporated herein by reference to Exhibit 10.2 to Inergy L.P.’s Form 8-K filed on December 3, 2004)
**12.1	Computation of ratio of earnings to fixed charges
*14.1	Inergy’s Code of Business Ethics and Conduct
**21.1	List of subsidiaries of Inergy, L.P.
**23.1	Consent of Ernst & Young LLP
**31.1	Certification of the Chief Executive Officer pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended
**31.2	Certification of Chief Financial Officer pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended
**32.1	Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
**32.2	Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

* Previously filed

** Filed herewith

*** Management contracts or compensatory plans or arrangements required to be identified by Item 15(a).

(b) Exhibits.

See exhibits identified above under Item 15(a)3.

(c) Financial Statement Schedules.

See financial statement schedules identified above under Item 15(a)2.

51

Inergy, L.P. and Subsidiaries

Consolidated Financial Statements

September 30, 2005 and 2004 and each of the

Three Years in the Period Ended

September 30, 2005

Contents

Report of Independent Registered Public Accounting Firm	53
Report of Independent Registered Public Accounting Firm on Internal Controls	54
Audited Consolidated Financial Statements
Consolidated Balance Sheets	55
Consolidated Statements of Operations	56
Consolidated Statements of Partners’ Capital	57
Consolidated Statements of Cash Flows	58
Notes to Consolidated Financial Statements	59

52

Report of Independent Registered Public Accounting Firm

The Board of Directors and Unitholders of Inergy, L.P.

We have audited the accompanying consolidated balance sheets of Inergy, L.P. and Subsidiaries (the Partnership) as of September 30, 2005 and 2004, and the related consolidated statements of operations, partners’ capital, and cash flows for each of the three years in the period ended September 30, 2005. Our audits also included the financial statement schedule listed at Item 15(a). These financial statements and schedule are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Inergy, L.P. and Subsidiaries at September 30, 2005 and 2004, and the consolidated results of their operations and their cash flows for each of the three years in the period ended September 30, 2005 in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Inergy, L.P. and Subsidiaries’ internal control over financial reporting as of September 30, 2005, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated December 8, 2005 expressed an unqualified opinion thereon.

/s/ ERNST & YOUNG LLP

Kansas City, Missouri

December 8, 2005

53

Report of Independent Registered Public Accounting Firm on Internal Controls

The Board of Directors and Unitholders of Inergy, L.P. and Subsidiaries

We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control over Financial Reporting, that Inergy, L.P. and Subsidiaries maintained effective internal control over financial reporting as of September 30, 2005, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Inergy, L.P. and Subsidiaries’ management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

As indicated in the accompanying Management’s Report on Internal Control over Financial Reporting appearing on page 38 and as permitted by the Securities and Exchange Commission, management’s assessment of and conclusion on the effectiveness of internal control over financial reporting did not include the internal controls of its 2005 acquisitions which are included in the 2005 consolidated financial statements of Inergy, L.P. and Subsidiaries and constituted $596.6 million and $401.2 million in total assets and revenues, respectively. Our audit of internal control over financial reporting of Inergy, L.P. and Subsidiaries also did not include an evaluation of the internal control over financial reporting of its 2005 acquisitions.

In our opinion, management’s assessment that Inergy, L.P. and Subsidiaries maintained effective internal control over financial reporting as of September 30, 2005, is fairly stated, in all material respects, based on the COSO criteria. Also, in our opinion, Inergy, L.P. and Subsidiaries maintained, in all material respects, effective internal control over financial reporting as of September 30, 2005, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Inergy, L.P. and Subsidiaries as of September 30, 2005 and 2004, and the related consolidated statements of operations, partners’ capital, and cash flows for each of the three years in the period ended September 30, 2005 of Inergy, L.P. and Subsidiaries and our report dated December 8, 2005 expressed an unqualified opinion thereon.

/s/ ERNST & YOUNG LLP

Kansas City, Missouri

December 8, 2005

54

Inergy, L.P. and Subsidiaries

Consolidated Balance Sheets

	September 30,
	2005			2004
	(In Thousands)
Assets
Current assets:
Cash	$	9,500		$	2,256
Accounts receivable, less allowance for doubtful accounts of $2,356 and $1,078 at September 30, 2005 and 2004, respectively		94,876			49,441
Inventories		122,387			56,404
Prepaid expenses and other current assets		22,674			5,494
Assets from price risk management activities		58,356			23,015
Total current assets		307,793			136,610
Property, plant and equipment:
Land and buildings		156,823			20,246
Office furniture and equipment		18,088			10,173
Vehicles		68,783			32,719
Tanks and plant equipment		556,505			189,519
		800,199			252,657
Less accumulated depreciation		(72,756	)		(37,404	)
Property, plant and equipment, net		727,443			215,253
Intangible assets (Note 2):
Covenants not to compete		30,606			11,498
Deferred financing costs		20,444			5,242
Deferred acquisition costs		725			104
Trademarks		32,845			2,500
Customer accounts		161,000			74,154
		245,620			93,498
Less accumulated amortization		(30,972	)		(17,398	)
Intangible assets, net		214,648			76,100
Goodwill		249,173			75,628
Other assets		3,187			228
Total assets	$	1,502,244		$	503,819
Liabilities and partners’ capital
Current liabilities:
Accounts payable	$	104,148		$	54,621
Accrued expenses		54,685			13,937
Customer deposits		68,567			15,977
Liabilities from price risk management activities		49,572			29,640
Current portion of long-term debt (Note 4)		17,931			23,615
Total current liabilities		294,903			137,790
Long-term debt, less current portion (Note 4)		541,800			113,986
Other long-term liabilities		1,647			—
Partners’ capital (Notes 1 and 6):
Common unitholders (34,411,329 and 17,626,506 units issued and outstanding as of September 30, 2005 and 2004, respectively)		623,861			224,600
Senior subordinated unitholders (3,821,884 and 5,478,568 units issued and outstanding as of September 30, 2005 and 2004, respectively)		14,276			25,352
Junior subordinated unitholders (1,145,084 and 1,145,084 units issued and outstanding as of September 30, 2005 and 2004, respectively)		(3,163	)		(2,296	)
Special unitholders (769,941 units issued and outstanding as of September 30, 2005)		25,000			—
Non-managing general partners and affiliate		3,920			4,387
Total partners’ capital		663,894			252,043
Total liabilities and partners’ capital	$	1,502,244		$	503,819

See accompanying notes.

55

Inergy, L.P. and Subsidiaries

Consolidated Statements of Operations

(In Thousands, Except Per Unit Data)

	Year Ended September 30,
	2005			2004			2003
Revenue:
Propane	$	851,613		$	431,202		$	343,578
Other		198,523			51,294			19,787
		1,050,136			482,496			363,365
Cost of product sold (excluding depreciation and amortization as shown below)
Propane		593,148			334,231			258,986
Other		131,075			24,822			8,024
		724,223			359,053			267,010
Gross profit		325,913			123,443			96,355
Expenses:
Operating and administrative		197,082			81,296			59,249
Depreciation and amortization		50,364			21,089			13,843
Operating income		78,467			21,058			23,263
Other income (expense):
Interest expense, net		(34,150	)		(7,878	)		(9,982	)
Write-off of deferred financing costs		(6,990	)		(1,216	)		—
Make whole premium charge		—			(17,949	)		—
Swap value received		—			949			—
Gain (loss) on sale of property, plant and equipment		(679	)		(203	)		(91	)
Finance charges		1,817			704			339
Other		235			106			86
Income (loss) before income taxes		38,700			(4,429	)		13,615
Provision for income taxes		63			167			103
Net income (loss)	$	38,637		$	(4,596	)	$	13,512
Partners’ interest information
Non-managing general partners and affiliate’s interest in net income	$	8,133		$	1,182		$	617
Limited partners’ interest in net income (loss):
Common unit interest	$	24,235		$	(3,664	)	$	6,820
Senior subordinated unit interest		5,147			(1,814	)		5,190
Junior subordinated unit interest		1,122			(300	)		885
Total limited partners’ interest in net income (loss)	$	30,504		$	(5,778	)	$	12,895
Net income (loss) per limited partner unit:
Basic	$	0.98		$	(0.26	)	$	0.77
Diluted	$	0.96		$	(0.26	)	$	0.76
Weighted average limited partners’ units outstanding:
Basic		31,143			22,027			16,676
Diluted		31,853			22,027			16,942

See accompanying notes.

56

Inergy, L.P. and Subsidiaries

Consolidated Statements of Partners’ Capital

(In Thousands)

	Common Unit Capital			Senior Subordinated Unit Capital			Junior Subordinated Unit Capital			Non-Managing General Partners and Affiliate			Special Unit Capital		Total Partners’ Capital
Balance at September 30, 2002	$	76,762		$	41,292		$	607		$	2,255		$	—	$	120,916
Common and Senior Subordinated Units issued in acquisition of retail propane companies		35,100			10,000			—			—			—		45,100
Net proceeds from issuance of Common Units		23,339			—			—			—			—		23,339
Return and cancellation of Common Units originally issued in the IPC acquisition		(106	)		—			—			—			—		(106	)
Contribution from non-managing general partners		—			—			—			1,430			—		1,430
Members’ distributions		(12,935	)		(9,783	)		(1,658	)		(841	)		—		(25,217	)
Comprehensive income:
Net income		6,820			5,190			885			617			—		13,512
Foreign currency translation		3			4			2			—			—		9
Comprehensive income																13,521
Balance at September 30, 2003		128,983			46,703			(164	)		3,461			—		178,983
Net proceeds from issuance of Common Units		113,219			—			—			—			—		113,219
Contribution from non-managing general partners		—			—			—			1,791			—		1,791
Senior Subordinated Units converted to Common Units		8,127			(8,127	)		—			—			—		—
Members’ distributions		(22,076	)		(11,416	)		(1,833	)		(2,047	)		—		(37,372	)
Comprehensive income:
Net income (loss)		(3,664	)		(1,814	)		(300	)		1,182			—		(4,596	)
Foreign currency translation		11			6			1			—			—		18
Comprehensive income																(4,578	)
Balance at September 30, 2004		224,600			25,352			(2,296	)		4,387			—		252,043
Net proceeds from issuance of Common Units		410,554			—			—			—			—		410,554
Net proceeds from issuance of Special Units		—			—			—			—			25,000		25,000
Senior Subordinated Units converted to Common Units		6,099			(6,099	)		—			—			—		—
Distributions		(45,909	)		(11,034	)		(2,187	)		(8,681	)		—		(67,811	)
Comprehensive income:
Net income (loss)		24,235			5,147			1,122			8,133			—		38,637
Unrealized gain on derivative instruments		4,229			898			196			80					5,403
Foreign currency translation		53			12			2			1			—		68
Comprehensive income																44,108
Balance at September 30, 2005	$	623,861		$	14,276		$	(3,163	)	$	3,920		$	25,000	$	663,894

See accompanying notes.

57

Inergy, L.P. and Subsidiaries

Consolidated Statements of Cash Flows

(In Thousands)

	Year Ended September 30,
	2005			2004			2003
Operating activities
Net income (loss)	$	38,637		$	(4,596	)	$	13,512
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation		37,328			15,325			9,856
Amortization		13,036			5,764			3,987
Amortization of deferred financing costs		1,825			1,686			1,506
Write-off of deferred financing costs		6,990			1,216			—
Provision for doubtful accounts		1,966			214			719
Make whole premium charge		—			17,949			—
(Gain) loss on disposal of property, plant and equipment		679			201			91
Net assets (liabilities) from price risk management activities		(10,008	)		9,730			(7,757	)
Changes in operating assets and liabilities, net of effects from acquisitions:
Accounts receivable		(19,722	)		(23,157	)		(7,420	)
Inventories		(34,669	)		(19,048	)		7,038
Prepaid expenses and other current assets		482			(1,524	)		(73	)
Other assets		(599	)		37			42
Accounts payable		19,393			24,550			6,981
Accrued expenses		13,820			(280	)		2,981
Customer deposits		18,511			4,089			2,965
Net cash provided by operating activities		87,669			32,156			34,428
Investing activities
Acquisitions, net of cash acquired		(810,053	)		(85,154	)		(26,063	)
Purchases of property, plant and equipment		(34,122	)		(14,521	)		(6,230	)
Deferred acquisition costs incurred		(621	)		(900	)		(2,094	)
Proceeds from sale of property, plant and equipment		4,141			2,245			720
Net cash used in investing activities		(840,655	)		(98,330	)		(33,667	)
Financing activities
Proceeds from issuance of long-term debt	$	1,614,579		$	372,407		$	174,794
Principal payments on long-term debt		(1,198,682	)		(367,238	)		(172,855	)
Deferred financing costs incurred		(23,478	)		26			(821	)
Payment of make whole premium charge		—			(17,949	)		—
Contribution from non-managing general partner		—			1,791			1,430
Net proceeds from issuance of Common Units		410,554			113,219			23,339
Net proceeds from issuance of Special Units		25,000			—			—
Distributions		(67,811	)		(37,372	)		(25,217	)
Net cash provided by financing activities		760,162			64,884			670
Effect of foreign exchange rate changes on cash		68			18			9
Net increase (decrease) in cash		7,244			(1,272	)		1,440
Cash at beginning of year		2,256			3,528			2,088
Cash at end of year	$	9,500		$	2,256		$	3,528
Supplemental disclosure of cash flow information
Cash paid during the year for interest	$	28,549		$	6,251		$	8,705
Supplemental schedule of noncash investing and financing activities
Additions to covenants not to compete through the issuance of noncompete obligations	$	7,881		$	2,569		$	1,953
Acquisitions through the issuances of Common Units and Senior Subordinated Units		—			—		$	45,100
Acquisition of retail propane companies through the assumption of seller debt		—			—		$	2,218
Increase (decrease) in the fair value of long-term debt and the related interest rate swap	$	(1,647	)	$	(316	)	$	556
Acquisitions, net of cash acquired:
Current assets	$	76,655		$	6,304		$	3,687
Property, plant and equipment		520,215			60,503			37,089
Intangible assets		138,799			19,079			21,164
Goodwill		171,046			11,531			18,473
Other assets		2,359			—			—
Current liabilities		(91,140	)		(9,694	)		(5,079	)
Non-compete liabilities		(7,881	)		(2,569	)		(1,953	)
Long-term debt		—			—			(2,218	)
Partner’s capital		—			—			(45,100	)
	$	810,053		$	85,154		$	26,063

See accompanying notes.

58

Inergy, L.P. and Subsidiaries

Notes to Consolidated Financial Statements

1. Accounting Policies

Organization

Inergy, L.P. (Inergy, the Partnership or the Company) was formed on March 7, 2001 as a Delaware limited partnership. The Partnership and its subsidiaries, including Inergy Propane, LLC (Inergy Propane or the Operating Company), were formed to acquire, own and operate the propane business and substantially all the assets and liabilities (other than a portion of the cash and deferred income tax liabilities) of Inergy Partners, LLC and subsidiaries (Inergy Partners or the Non-managing General Partner). In addition, Inergy Sales and Service, Inc. (Services), a subsidiary of the Operating Company, was formed to acquire and operate the service work and appliance parts and sales business of Inergy Partners. The Partnership, the Operating Company, and Services are collectively referred to hereinafter as the Partnership Entities. In order to simplify the Partnership’s obligations under the laws of several jurisdictions in which the Partnership conducts business, the Partnership’s activities are conducted through the Operating Company.

In July 2001, the Partnership Entities consummated an initial public offering (the Offering) of 3,680,000 common units representing limited partner interests in the Partnership (the common units) for an offering price of $11.00 per Common Unit aggregating $40.5 million before approximately $6.2 million of underwriting discounts and commissions and other expenses related to the Offering. In conjunction with the Offering, an additional 4,012,912 Senior Subordinated Units were issued to holders of the certain redeemable Class A preferred interests of Inergy Partners, representing a 34.3% limited partner interest in the Partnership Entities. At the same time, the Operating Company assumed the Non-managing General Partner’s obligation under its funded debt in connection with the conveyance in July 2001 (the Partnership Conveyance) by Inergy GP, LLC (the Managing General Partner) and the Non-managing General Partner (together referred to as the General Partners), of substantially all of their assets and liabilities (excluding $1.9 million of cash and the deferred tax liabilities associated with the subsidiaries of Wilson Oil Company of Johnston County, Inc. (Wilson) and Rolesville Gas & Oil Company, Inc. (Rolesville)). Both the Managing and Non-Managing General Partners are 100%-owned subsidiaries of Inergy Holdings L.P. (“Holdings”).

The Partnership is managed by Inergy GP, LLC (Inergy G.P.). Pursuant to the Partnership Agreement, Inergy G.P. or any of its affiliates is entitled to reimbursement for all direct and indirect expenses incurred or payments it makes on behalf of the Partnership, and all other necessary or appropriate expenses allocable to the Partnership or otherwise reasonably incurred by Inergy G.P. in connection with operating the Partnership business. These costs, which totaled approximately $3.0 million, $2.9 million, and $2.1 million for the years ended September 30, 2005, 2004, and 2003, respectively, include compensation and benefits paid to officers and employees of Inergy G.P. and its affiliates.

As of September 30, 2005, Holdings owns an aggregate 10.7% interest in Inergy, L.P., inclusive of ownership of all of our non-managing general partner and our managing general partner. This ownership is comprised of an approximate 1.2% general partnership interest and a 9.5% limited partnership interest.

Basis of Presentation

The accompanying consolidated financial statements include the accounts of Inergy, L.P. and its subsidiaries, Inergy Propane as well as all of Inergy Propane’s wholly-owned subsidiaries. All significant intercompany balances and transactions have been eliminated in consolidation.

Nature of Operations

Inergy is engaged primarily in the sale, distribution, storage, marketing, trading, processing and fractionation of propane, natural gas and other natural gas liquids. The retail market is seasonal because propane is used primarily for heating in residential and commercial buildings, as well as for agricultural purposes. Inergy’s operations are primarily concentrated in the Midwest, Northeast, and Southeast regions of the United States.

59

Inergy, L.P. and Subsidiaries

Notes to Consolidated Financial Statements – (Continued)

Financial Instruments and Price Risk Management

Inergy utilizes certain derivative financial instruments to (i) manage its exposure to commodity price risk, specifically, the related change in the fair value of inventories, as well as the variability of cash flows related to forecasted transactions; (ii) to ensure adequate physical supply of commodity will be available; and (iii) manage its exposure to interest rate risk. Inergy records all derivative instruments on the balance sheet as either assets or liabilities measured at fair value under the provisions of Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”), as amended. 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 hedge transaction. Gains and losses on derivative instruments designated as cash flow hedges are reported in other comprehensive income and reclassified into earnings in the periods in which earnings are impacted by the variability of the cash flow of the hedged item. The ineffective portion of all hedge transactions is recognized in current period earnings.

On the date the derivative contract is entered into, Inergy designates the derivative as either a hedge of the fair value of a recognized asset or liability or of an unrecognized firm commitment (fair value hedge), or a hedge of a forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability (cash flow hedge). Inergy documents all relationships between hedging instruments and hedged items, as well as its risk-management objective and strategy for undertaking various hedge transactions. Inergy uses regression analysis and 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, Inergy discontinues hedge accounting prospectively. When hedge accounting is discontinued because it is determined that the derivative no longer qualifies as an effective hedge, Inergy continues to carry the derivative on the balance sheet at its fair value, and recognized changes in the fair value of the derivative through current-period earnings.

Inergy is party to certain commodity derivative financial instruments that are designated as hedges of selected inventory positions, and qualify as fair value hedges, as defined in SFAS No. 133. Inergy’s overall objective for entering into fair value hedges is to manage its exposure to fluctuations in commodity prices and changes in the fair market value of its inventories as well as to ensure an adequate physical supply will be available. These derivatives are recorded at fair value on the balance sheets 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.

Inergy also enters into derivative financial instruments that qualify as cash flow hedges, which hedge the exposure of variability in expected future cash flows attributable to a particular risk. 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 closes. Any ineffective portion of the gain or loss is recognized as cost of product sold in the current period. Derivative financial instruments which hedge the variability in expected cash flows but do not qualify as cash flow hedges are recorded to earnings in the current period as cost of product sold.

Furthermore, Inergy has elected to use the special hedge accounting rules in SFAS No. 133 and hedge the fair value of certain of its inventory positions, whereby the hedged inventory is marked to market. Inventories purchased under energy contracts subsequent to October 25, 2002, and not otherwise designated as being hedged are carried at the lower-of-cost or market.

The cash flow impact of derivative financial instruments is reflected as cash flows from operating activities in the consolidated statements of cash flows.

Revenue Recognition

Sales of propane and other liquids 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 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 it is earned.

Expense Classification

Cost of products sold consists of tangible products sold including all propane and other natural gas liquids sold and all propane related appliances sold. Operating and administrative expenses consist of all expenses incurred by Inergy other than

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Notes to Consolidated Financial Statements – (Continued)

those described above in cost of products sold and depreciation and amortization. Certain of Inergy’s operating and administrative expenses and depreciation and amortization are incurred in the distribution of our product sales but are not included in cost of product sold. These amounts were $56.4 million, $28.2 million and $20.8 million during the years ended September 30, 2005, 2004, and 2003, respectively.

Credit Risk and Concentrations

Inergy is both a retail and wholesale supplier of propane gas. Inergy generally extends unsecured credit to its wholesale customers in the United States and Canada. Credit is generally extended to retail customers through delivery into Company and customer owned propane gas storage tanks. Provisions for doubtful accounts receivable are based on specific identification and historical collection results and have generally been within management’s expectations. Finance charges on trade receivables are generally recognized upon billing of customers.

Three suppliers, Sunoco, Inc. (15%), Dominion Transmission Inc. (13%), and Exxon Mobil Oil Corp. (13%), accounted for approximately 41% of propane purchases during the past fiscal year. We believe our contracts with these suppliers will enable us to purchase most of our supply needs at market prices and ensures adequate supply. No other single supplier accounted for more than 10% of our propane purchases in the current year.

No single customer represents 10% or more of consolidated revenues. In addition, nearly all of Inergy’s revenues are derived from sources within the United States, and all of its long-lived assets are located in the United States.

Use of Estimates

The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amount of assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the year. Actual results could differ from those estimates.

Inventories

Inventories for retail operations, which mainly consist of propane gas and other liquids, are stated at the lower of cost or market and are computed using the average-cost method or first-in, first-out basis. Wholesale propane inventories are stated at the lower of cost, determined by either using the average-cost method or market unless designated as being hedged by forward sales contracts. Wholesale propane inventories being hedged and carried at market at September 30, 2005 and 2004 amount to $85.8 million and $40.7 million, respectively.

Inventories consist of (in thousands):

	September 30, 2005		September 30, 2004
Propane gas and other liquids	$	114,660	$	53,295
Appliances, parts and supplies		7,727		3,109
	$	122,387	$	56,404

Shipping and Handling Costs

Shipping and handling costs are recorded as part of cost of products sold at the time product is shipped or delivered to the customer except as discussed in “Expense Classification”.

Property, Plant, and Equipment

Property, plant, and equipment are stated at cost. Depreciation is computed by the straight-line method over the estimated useful lives of the assets, as follows:

	Years
Buildings and improvements	25–40
Office furniture and equipment	3–10
Vehicles	5–10
Tanks and plant equipment	5–30

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Notes to Consolidated Financial Statements – (Continued)

Inergy reviews its long-lived assets for impairment in accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If such events or changes in circumstances are present, a loss is recognized if the carrying value of the asset is in excess of the sum of the undiscounted cash flows expected to result from the use of the asset and its eventual disposition. An impairment loss is measured as the amount by which the carrying amount of the asset exceeds the fair value of the asset. Inergy has determined that no impairment exists as of September 30, 2005.

Identifiable Intangible Assets

The Company has recorded certain identifiable intangible assets, including covenants not to compete, customer accounts, trademarks, deferred financing costs and deferred acquisition costs. Covenants not to compete, customer accounts and trademarks have arisen from the various acquisitions by Inergy and are discussed in Note 2. Deferred financing costs represent financing costs incurred in obtaining financing and are being amortized over the term of the debt. Deferred acquisition costs represent costs incurred on acquisitions that Inergy is actively pursuing, most of which relate to the acquisitions completed subsequent to year end, as discussed in Note 12. Additionally, an acquired intangible asset should be separately recognized if the benefit of the intangible asset is obtained through contractual or other legal rights, or if the intangible asset can be sold, transferred, licensed, rented or exchanged, regardless of the acquirer’s intent to do so.

Certain intangible assets are amortized on a straight-line basis over their estimated economic lives, as follows:

	Years
Covenants not to compete	2–10
Deferred financing costs	1–10
Customer accounts	15
Trademarks	—

Trademarks have been assigned an indefinite economic life and are thereafter not being amortized. However, they are subject to an impairment evaluation explained below.

Estimated amortization, including amortization of deferred financing cost reported as interest expense, for the next five years ending September 30, in thousands of dollars is as follows:

2006	$	18,902
2007		16,032
2008		15,608
2009		13,938
2010		13,398

Goodwill

Goodwill is recognized pursuant to SFAS No. 142, “Goodwill and Other Intangible Assets,” (SFAS No. 142) from various acquisitions by Inergy as discussed in Note 2. Under SFAS No. 142, goodwill is subject to at least an annual assessment for impairment by applying a fair-value-based test.

In connection with the goodwill impairment evaluation, the reporting units are identified, which for the Company are the same as its operating segments, and the carrying value of each reporting unit is determined by assigning the assets and liabilities, including the existing goodwill and intangible assets, to those reporting units as of the date of the evaluation. To the extent a reporting unit’s carrying value exceeds its fair value, an indication exists that the reporting unit’s goodwill may be impaired and the second step of the impairment test must be performed. In the second step, the implied fair value of the goodwill is determined by allocating the fair value to all of its assets (recognized and unrecognized) and liabilities in a manner similar to a purchase price allocation in accordance with SFAS No. 141, “Business Combinations” to its carrying amount.

Under the provisions of SFAS No. 142, Inergy completed the valuation of each of its reporting units and determined no impairment existed as of September 30, 2005.

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Notes to Consolidated Financial Statements – (Continued)

Income Taxes

The earnings of the Partnership and Operating Company are included in the Federal and state income tax returns of the individual partners. Federal and state income taxes are, however, provided on the earnings of Services. The effect of temporary differences between Services’ basis of assets and liabilities for income tax and financial statement purposes is immaterial. The provision for income tax for the years ended September 30, 2005, 2004 and 2003 was $63,000, $167,000 and $103,000, respectively. Net earnings for financial statement purposes may differ significantly from taxable income reportable to unitholders as a result of differences between the tax basis and the financial reporting basis of assets and liabilities and the taxable income allocation requirements under the partnership agreement.

Customer Deposits

Customer deposits primarily represent cash received by Inergy from wholesale and retail customers for propane purchased that will be delivered at a future date.

Fair Value

The carrying amounts of cash, accounts receivable and accounts payable approximate their fair value. Based on the estimated borrowing rates currently available to Inergy for long-term debt with similar terms and maturities, the aggregate fair value of Inergy’s long-term debt was approximately $540 million and $138 million as of September 30, 2005 and 2004, respectively. See Note 3 for the fair value of our derivative financial instruments.

Comprehensive Income (Loss)

Comprehensive income includes net income and other comprehensive income, which includes, but is not limited to, foreign currency translation adjustments, and unrealized gains and losses on derivative financial instruments.

Pursuant to SFAS No. 133, Inergy records deferred hedge gains and losses on its derivative financial instruments that qualify as cash flow hedges as other comprehensive income.

Accounting for Unit-Based Compensation

Inergy has a unit-based employee compensation plan, which is accounted for under the recognition and measurement principles of APB Opinion No. 25, “Accounting for Stock Issued to Employees” for all periods presented and presents the fair value method pro forma disclosures required under the provisions of SFAS No. 123, “Accounting for Stock-Based Compensation,” as amended by SFAS No. 148 “Accounting for Stock-Based Compensation – Transition and Disclosure.” No unit-based employee compensation cost is reflected in net income (loss), as all options granted under the plan had an exercise price equal to the market value of the underlying common units on the date of grant. The following table illustrates the effect on net income (loss) and net income (loss) per limited partner unit as if Inergy had applied the fair value recognition provisions of SFAS No. 123, “Accounting for Stock-Based Compensation,” to unit-based employee compensation. For purposes of pro forma disclosures, the estimated fair value of an option is amortized to expense over the option’s vesting period. Inergy’s pro forma information for each of the three years in the period ended September 30, 2005 is as follows (in thousands, except per unit data):

	2005		2004			2003
Net income (loss) as reported	$	38,637	$	(4,596	)	$	13,512
Deduct: Total unit-based employee compensation expense determined under fair value method for all awards		195		227			164
Pro forma net income (loss)	$	38,442	$	(4,823	)	$	13,348
Deduct: Non-managing general partners and affiliate’s interest in net income (loss)	$	8,133	$	1,182		$	617
Pro forma limited partners’ interest in net income (loss)	$	30,309	$	(6,005	)	$	12,731
Net income (loss) per limited partner unit
Basic – as reported	$	0.98	$	(0.26	)	$	0.77
Basic – pro forma	$	0.97	$	(0.27	)	$	0.76
Diluted – as reported	$	0.96	$	(0.26	)	$	0.76
Diluted – pro forma	$	0.95	$	(0.27	)	$	0.75

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Notes to Consolidated Financial Statements – (Continued)

Income (Loss) Per Unit

Basic net income (loss) per limited partner unit is computed by dividing net income (loss), after considering Holdings and the Non-Managing General Partner’s interest and incentive distribution allocation, by the weighted average number of Common and Subordinated Units outstanding. Diluted net income (loss) per limited partner unit is computed by dividing net income (loss), after considering Holdings and the Non-Managing General Partner’s interest, by the weighted average number of Common and Subordinated Units outstanding and the dilutive effect of unit options granted under the long-term incentive plan. The following table presents the calculation of basic and dilutive income (loss) per limited partner unit (in thousands, except per unit data):

	Year Ended September 30,
	2005		2004			2003
Numerator:
Net income (loss)	$	38,637	$	(4,596	)	$	13,512
Less: Non-managing general partners and affiliates interest in net income (loss)		8,133		1,182			617
Limited partners’ interest in net income (loss) – basic and diluted	$	30,504	$	(5,778	)	$	12,895
Denominator:
Weighted average limited partners’ units outstanding – basic		31,143		22,027			16,676
Effect of dilutive units		710		—			266
Weighted average limited partners’ units outstanding – dilutive		31,853		22,027			16,942
Net income (loss) per limited partner unit
Basic	$	0.98	$	(0.26	)	$	0.77
Diluted	$	0.96	$	(0.26	)	$	0.76

For the year ended September 30, 2004, 468,412 outstanding options were excluded from the determination of diluted net income (loss) per limited partner unit because their inclusion would be anti-dilutive.

Segment Information

SFAS No. 131, “Disclosures about Segments of an Enterprise and Related Information” (SFAS No. 131) establishes standards for reporting information about operating segments, as well as related disclosures about products and services, geographic areas, and major customers. Further, SFAS No. 131 defines operating segments as components of an enterprise for which separate financial information is available that is evaluated regularly by the chief operating decision-maker in deciding how to allocate resources and assessing performance. In determining reportable segments under the provisions of SFAS No. 131, Inergy examined the way it organizes its business internally for making operating decisions and assessing business performance. See Note 10 for disclosures related to Inergy’s propane and midstream segments.

Recently Issued Accounting Pronouncements

On December 16, 2004, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 123 (revised 2004), Share-Based Payment, which is a revision of SFAS No. 123, Accounting for Stock-Based Compensation. SFAS 123(R) supersedes APB Opinion No. 25, Accounting for Stock Issued to Employees, and amends FASB Statement No. 95, Statement of Cash Flows. Generally, the approach in SFAS No. 123(R) is similar to the approach described in SFAS No. 123. However, SFAS No. 123(R) requires all share-based payments to employees, including grants of employee stock options, to be recognized in the income statement based on their fair values. Pro forma disclosure is no longer an alternative.

SFAS No. 123(R) must be adopted no later than October 1, 2005. Early adoptions will be permitted in periods in which financial statements have not yet been issued. The Company will adopt SFAS No. 123(R) on October 1, 2005.

SFAS No. 123(R) permits public companies to adopt its requirements using one of two methods:

A “modified prospective” method in which compensation cost is recognized beginning with the effective date (a) based on the requirements of SFAS No. 123(R) for all share-based payments granted after the effective date and (b) based on

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Notes to Consolidated Financial Statements – (Continued)

the requirements of SFAS No. 123 for all awards granted to employees prior to effective date of SFAS No. 123(R) that remain unvested as of the effective date.

A “modified retrospective” method which includes the requirements of the modified prospective described above, but also permits entities to restate based on the amounts previously recognized under SFAS No. 123 for purposes of pro forma disclosures either (a) all prior periods presented or (b) prior interim periods of the year of adoption.

The Company will adopt SFAS No. 123(R) using the modified prospective method.

As permitted by SFAS No. 123, during the fiscal year ended September 30, 2005, the Company accounted for share-based payments to employees using Opinion 25’s intrinsic value method and, as such, generally recognized no compensation cost for employee stock options. The impact of adoption of SFAS No. 123(R) will depend on levels of share-based payments granted in the future. However, had we adopted SFAS No. 123(R) in prior periods, the impact would have approximated the impact of SFAS No. 123 as described in the disclosure of pro forma net income and earnings per share in Note 1. The adoption of SFAS No. 123(R)’s fair value method is not expected to have a significant impact on our results of operations or on our overall financial position.

SFAS No. 151, “Inventory Costs, an amendment of ARB No. 43, Chapter 4,” amends the existing standard that provides guidance on accounting for inventory costs and specifically clarifies that abnormal amounts of costs should be recognized as period costs. This statement is effective for the fiscal year beginning after June 15, 2005. The adoption of SFAS No. 151 is not expected to have a material effect on the Company’s consolidated financial statements.

SFAS No. 153, “Exchanges of Nonmonetary Assets, an amendment of APB Opinion No. 29, Accounting for Nonmonetary Transactions” eliminates the narrow exception for nonmonetary exchanges of similar productive assets and replaces it with a broader exception for exchanges of nonmonetary assets that do not have commercial substance. Further, the amendments made by SFAS No. 153 are based on the principle that exchanges of nonmonetary assets should be measured based on the fair value of the assets exchanged. Previously, Opinion No. 29 required that the accounting for an exchange of a productive asset for a similar productive asset or an equivalent interest in the same or similar productive asset should be based on the recorded amount of the asset relinquished. The statement is effective for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005. Earlier application is permitted for nonmonetary asset exchanges in fiscal periods beginning after the date of issuance. The provisions of this statement shall be applied prospectively. The adoption of SFAS No. 153 is not expected to have a material effect on the Company’s consolidated financial statements.

SFAS No. 154, “Accounting Changes and Error Corrections” is a replacement of APB Opinion No. 20, Accounting Changes, and FASB Statement No. 3, Reporting Accounting Changes in Interim Financial Statements. Statement 145 applies to all voluntary changes in accounting principle and changes the accounting for and a reporting of a change in accounting principle. Statement 154 requires retrospective application to the prior periods’ financial statements of a voluntary change in accounting principle unless it is impracticable. Statement 154 is effective for the accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. The adoption of SFAS No. 154 is not expected to have a material effect on the Company’s consolidated financial statements.

In March 2005, the FASB issued FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations – an interpretation of FASB Statement No. 143 (“FIN 47”). FIN 47 clarifies that the term conditional retirement obligation, as used in FASB Statement No. 143, Asset Retirement Obligations, refers to a legal obligation to perform an asset retirement activity in which the timing or method of settlement, or both, are conditional on a future event that may or may not be within the control of the entity. An entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. FIN 47 is required to be adopted by Inergy for the fiscal year ended September 30, 2006 and Inergy is currently assessing the impact on its financial statements.

Reclassifications

Certain prior year amounts have been reclassified to conform to the current year presentation. These reclassifications had no effect on net income.

2. Acquisitions

During the fiscal year ended September 30, 2005, Inergy made seven acquisitions. In November 2004, Inergy acquired the propane assets of Moulton Gas Service, Inc., headquartered in Wapakoneta, OH. In December 2004, Inergy acquired Star Gas Propane, L.P. (“Star Gas”) headquartered in Stamford, CT and the propane assets of Northwest Propane, Inc, headquartered in Holly, MI. In May 2005, Inergy acquired the assets of three other retail propane companies, and in August 2005 acquired the membership interests of the entities that own the Stagecoach natural gas storage facility (“Stagecoach”) located in Tioga County, New York. The aggregate purchase price for these acquisitions, net of cash acquired was $810.1 million. The operating results for all the fiscal 2005 acquisitions are included in our consolidated results of operations from the dates of acquisition through September 30, 2005.

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Notes to Consolidated Financial Statements – (Continued)

The purchase price of Star Gas approximated $489.7 million, net of cash acquired. In connection with this acquisition, on December 17, 2004 Inergy entered into a 364-day credit facility and borrowed $375.0 million under this facility to partially fund the acquisition. This 364-day credit facility was repaid using the net proceeds from the private placement of $425 million of senior unsecured notes as further described in Note 4. Inergy also issued 3,568,139 common units to unrelated third parties to partially fund the acquisition.

Stagecoach is a natural gas storage facility with approximately 13.6 Bcf of working gas capacity. In addition to the approximate $205 million purchase price for the in-service Stagecoach facility, Inergy, L.P. has purchased the rights to the Phase II expansion project of Stagecoach for $25 million through the issuance of 769,941 Special units to Inergy Holdings, L.P. (See Note 6). The Phase II expansion is expected to add approximately 13 Bcf of additional working gas capacity.

The allocation of the total consideration for the Star Gas and Stagecoach acquisitions is as follows (in millions):

	Star Gas			Stagecoach
Current assets, net of cash acquired	$	54.6		$	4.6
Property, plant and equipment		276.4			200.5
Intangible assets		98.5			5.0
Goodwill		111.9			22.6
Other assets		1.4			1.0
Current liabilities		(52.0	)		(15.0	)
Non-compete liabilities		(1.1	)		0.0
	$	489.7		$	218.7

The purchase price allocation of Stagecoach has been prepared on a preliminary basis, and changes are expected when the appraisals are completed and additional information becomes available.

Intangible assets include $30.3 million of trademarks that are not subject to amortization. The weighted average amortization period of amortizable intangible assets acquired is approximately 15 years.

The following unaudited pro forma data summarizes the results of operations for the period indicated as if the Star Gas acquisition and the Stagecoach Natural Gas Facility had been completed as of October 1, 2003 and October 1, 2004, the beginning of the 2004 and 2005 fiscal years, since both meet the criteria of a significant subsidiary. Pro forma information is not presented for other acquisitions as they do not qualify as significant subsidiaries. The pro forma data gives effect to actual operating results prior to the acquisition and adjustments to interest expense, customers’ account amortization expense and depreciation expense. These pro forma results are not necessarily indicative of the results for the periods presented, had the acquisitions actually occurred on October 1, 2003 and 2004, nor are they indicative of projected results for future periods.

	Year Ended September 30,
	2005		2004
	(in thousands, except per unit data)
Revenues	$	1,136,333	$	863,471
Net income (loss)		13,999		(18,892	)
Non–managing general partners and affiliate’s interest in net income (loss)		7,766		922
Limited partners’ interest in net income (loss)		6,233		(19,814	)
Net income (loss) per limited partner unit:
Basic	$	0.20	$	(0.90	)
Diluted	$	0.20	$	(0.90	)

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Notes to Consolidated Financial Statements – (Continued)

3. Price Risk Management and Financial Instruments

Commodity Derivative Instruments and Price Risk Management

Inergy, through its wholesale operations, sells propane and offers price risk management services to energy related businesses through a variety of financial and other instruments including forward contracts involving physical delivery of propane. In addition, Inergy manages its own trading portfolio using forward physical and futures contracts. Inergy attempts to balance its contractual portfolio in terms of notional amounts and timing of performance and delivery obligations. However, net unbalanced positions can exist or are established based on assessment of anticipated short-term needs or market conditions.

The price risk management services offered to propane users, retailers and resellers, and other related businesses utilize a variety of financial and other instruments including forward contracts involving physical delivery of propane, swap agreements, which require payments to (or receipt of payments from) counterparties based on the differential between a fixed and variable price for propane, options and other contractual arrangements.

As discussed in Note 1, all of these financial instruments are accounted for under SFAS 133. Inergy has entered into these derivative financial instruments to manage its exposure to fluctuations in commodity prices and to the variability of future cash flows. The effects of commodity price volatility have generally been mitigated by Inergy’s attempts to maintain a balanced portfolio of derivative financial instruments and inventory positions in terms of notional amounts and timing of performance.

Notional Amounts and Terms

The notional amounts and terms of these financial instruments at September 30, 2005 and 2004 include fixed price payor for 12.9 million and 4.9 million barrels, respectively, and fixed price receiver for 14.6 million and 6.5 million barrels, respectively.

Notional amounts reflect the volume of the transactions, but do not represent the amounts exchanged by the parties to the financial instruments. Accordingly, notional amounts do not accurately measure Inergy’s exposure to market or credit risks.

Fair Value

The fair value of all derivative instruments related to price risk management activities as of September 30, 2005 and 2004 was assets of $58.4 million and $23.0 million, respectively, and liabilities of $49.6 million and $29.6 million, respectively.

The net change in unrealized gains and losses related to all price risk management activities and propane based financial instruments for the years ended September 30, 2005, 2004 and 2003 of $24.1 million, $(1.2) million, and $0.8 million, respectively, are included in cost of product sold in the accompanying consolidated statements of operations. The Company recognized a non-cash gain of $19.4 million on price risk management activities and propane based financial instruments for the year ended September 30, 2005, no similar gain was recognized in the years ended September 30, 2004, and 2003.

The following table summarizes the change in the unrealized fair value of energy contracts related to risk management activities for the years ended September 30, 2005 and 2004 where settlement has not yet occurred (in thousands of dollars):

	Year Ended September 30, 2005			Year Ended September 30, 2004
Net unrealized gains and (losses) in fair value of contracts outstanding at beginning of period	$	(6,626	)	$	3,104
Initial recorded value of new contracts entered into during the period		1,881			2,723
Other unrealized gains and (losses) recognized		18,197			(13,148	)
Less: realized gains and (losses) recognized		(4,668	)		695
Net unrealized gains and (losses) in fair value of contracts outstanding at end of period	$	8,784		$	(6,626	)

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Of the outstanding unrealized gain (loss) as of September 30, 2005 and 2004, contracts with a maturity of less than one year totaled $8.8 million and ($6.6) million, respectively. Contracts with a maturity of greater than one year were not significant in 2005. There were no contracts maturing in excess of fifteen months in 2005 and no contracts maturing in excess of one year in 2004.

During the years ended September 30, 2005, 2004, and 2003 Inergy recognized a net loss of $0.8 million, $0.1 million, and $0.2 million, respectively, related to the ineffective portion of its fair value commodity hedging instruments and a net loss of $0.6 million, $1.0 million, and $0.5 million, respectively, related to the portion of the fair value commodity hedging instruments excluded from the assessment of hedge effectiveness. Changes in the fair value of derivative instruments that are not designated as hedges are recorded in current period earnings in accordance with SFAS No. 133.

As of September 30, 2005, the total amount of deferred net gains recorded in other comprehensive income is expected to be reclassified to future earnings, contemporaneously with the related physical purchase or delivery of the underlying commodity. During the year ended September 30, 2005, there was no ineffectiveness related to cash flow hedges and no amounts were reclassified to earnings from other comprehensive income in connection with forecasted transactions that were no longer considered probable of occurring. The net gain deferred in other comprehensive income at September 30, 2005 is expected to be reclassified into earnings in the next twelve months. Since a portion of these amounts is based on market prices at the current period end, actual amounts to be reclassified will differ and could vary materially as a result of changes in market conditions.

Market and Credit Risk

Inherent in the resulting 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. Inergy monitors market risk through a variety of techniques, including daily reporting of the portfolio’s value to senior management. Inergy provides for such risks at the time derivative financial instruments are adjusted to fair value and when specific risks become known. Inergy attempts to minimize credit risk exposure through credit policies and periodic monitoring procedures as well as through customer deposits and letters of credit, as deemed appropriate. The counterparties associated with assets from price risk management activities as of September 30, 2005 and 2004 are generally propane users, retailers and resellers, and energy marketers and dealers.

4. Long-Term Debt

Long-term debt consisted of the following (in thousands):

	September 30,
	2005		2004
Credit agreement	$	126,800	$	132,153
Senior unsecured notes		423,352		—
Obligations under noncompetition agreements and notes to former owners of businesses acquired		9,579		5,446
Other		—		2
		559,731		137,601
Less current portion		17,931		23,615
	$	541,800	$	113,986

On December 17, 2004, Inergy entered into a 5-Year Credit Agreement (the “Credit Agreement”) with its existing lenders in addition to others. The Credit Agreement consists of a $75 million revolving working capital facility (the “Working Capital Facility”) and a $350 million revolving acquisition facility (the “Acquisition Facility”). The Credit Agreement carries terms, conditions and covenants substantially similar to the previous credit agreement. The Credit Agreement is secured by a first priority lien on substantially all of Inergy’s assets and those of its domestic subsidiaries and the pledge of all of the equity interests or membership interests in its domestic subsidiaries. In addition, the Credit Agreement is guaranteed by each of Inergy’s domestic subsidiaries. Inergy has the option to use up to $25.0 million of available borrowing capacity from its Acquisition Facility for working capital purposes.

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Inergy is required to reduce the principal outstanding on the Working Capital Facility to $5 million or less for a minimum of 30 consecutive days during the period commencing March 1 and ending September 30. As such, $5 million and $4 million of the outstanding balance at September 30, 2005 and 2004, respectively, have been classified as a long-term liability in the accompanying consolidated balance sheets. At September 30, 2005, the balance outstanding under the Credit Agreement was $126.8 million, including $20 million under the Working Capital Facility. At September 30, 2004, borrowings under the previous credit facility were $132.2 million, including $26.4 million under the revolving working capital facility. The prime rate and LIBOR plus the applicable spreads were between 6.19% and 7.75% at September 30, 2005, and between 3.77% and 4.75% at September 30, 2004, for all outstanding debt under the respective credit agreement.

The Credit Agreement contains several covenants which, among other things, require the maintenance of various financial performance ratios, restrict the payment of distributions to unitholders, and require financial reports to be submitted periodically to the financial institutions. Unused borrowings under the Credit Agreement amounted to $276.2 million at September 30, 2005. Unused borrowings under the previous credit facility were $162.2 million at September 30, 2004.

On November 7, 2005, Inergy amended the Credit Agreement with existing lenders to, among other changes, have the following impact to the credit provisions of the agreement:

• Lowered the applicable margin in the leverage-based pricing grid;

• Extended the maturity from December 17, 2009 to November 10, 2010;

• Increased to $75.0 million the effective amount of working capital borrowings available through the utilization of the Acquisition Facility; and

• Other terms, conditions, and covenants remained materially unchanged.

In December 2004, Inergy entered into a 364-day credit facility and borrowed $375.0 million under this facility. The borrowings under this facility were used to finance part of the Star Gas acquisition and related expenses. The 364-day credit facility was guaranteed by all of Inergy’s domestic subsidiaries and was secured on an equal basis with its revolving credit facilities. The borrowings under this facility were permanently repaid with the net proceeds from the offering of senior unsecured notes and the 364-day facility was terminated. This resulted in the write-off of deferred financing costs associated with the 364-day facility of $5.5 million.

Senior Unsecured Notes

On December 22, 2004, the Company and its wholly-owned subsidiary, Inergy Finance Corp., completed a private placement of $425 million in aggregate principal amount of 6.875% senior unsecured notes due 2014 (the “Senior Notes”). The Senior Notes contain covenants similar to the Credit Agreement. The net proceeds from the Senior Notes were used to repay all amounts drawn under the 364-day credit facility, with the $39.9 million balance of the net proceeds being applied to the Acquisition Facility.

The Senior Notes represent senior unsecured obligations and rank pari passu in right of payment with all of the Company’s other present and future senior indebtedness. The Senior Notes are jointly and severally guaranteed by all current domestic subsidiaries and have certain call features, which allow the Company to redeem the Senior Notes at specified prices based on date redeemed.

Subsequently, on October 26, 2005, Inergy completed an offer to exchange its existing Senior Notes for $425 million of 6.875% senior notes due 2014 (the “Exchange Notes”) that are registered and do not carry transfer restrictions, registration rights and provisions for additional interest. The Exchange Notes did not provide us with any additional proceeds and satisfied our obligations under the registration rights agreement.

Inergy is party to four interest rate swap agreements scheduled to mature in December 2014, each designed to hedge $25 million in underlying fixed rate senior unsecured notes, in order to manage interest rate risk exposure. These swap agreements, which expire on the same date as the maturity date of the related Senior Notes and contain call provisions consistent with the underlying Senior Notes, require the counterparty to pay the Company an amount based on the stated fixed interest rate due every six months. In exchange, Inergy is required to make semi-annual floating interest rate payments on the same dates to the counterparty based on an annual interest rate equal to the 6-month LIBOR interest rate plus spreads between 1.95% and 2.20% applied to the same notional amount of $100 million. The swap agreements have been recognized as fair value hedges. Amounts to be received or paid under the agreements are accrued and recognized over the life of the agreements as an adjustment to interest expense. Inergy recognized an approximate $1.6 million decrease in the fair market

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value of the related Senior Notes at September 30, 2005 with a corresponding change in the fair value of its interest rate swaps, which are recorded in other long term liabilities.

Notes Payable and Other Obligations

Noninterest-bearing obligations due under noncompetition agreements and other note payable agreements consist of agreements between Inergy and the sellers of retail propane companies acquired from fiscal years 1999 through 2005 with payments due through 2014 and imputed interest ranging from 6.0% to 10.0%. Noninterest-bearing obligations consist of $11.5 million and $6.9 million in total payments due under agreements, less unamortized discount based on imputed interest of $1.9 million and $1.4 million at September 30, 2005 and 2004, respectively.

The aggregate amounts of principal to be paid on the outstanding long-term debt during the next five years ending September 30 and thereafter are as follows, in thousands of dollars:

2006	$	17,931
2007		2,175
2008		2,026
2009		923
2010		112,346
Thereafter		424,330
	$	559,731

On June 7, 2002, Inergy entered into a note purchase agreement with a group of institutional lenders pursuant to which it issued $85.0 million aggregate principal amount of senior secured notes with a weighted average interest rate of 9.07% and a weighted average maturity of 5.9 years. The funds from a public unit offering, together with net new borrowings under a then-existing revolving credit facility were used to repay in full $85.0 million aggregate principal amount of senior secured notes, plus interest expense related to a make whole premium charge of approximately $17.9 million in January 2004. All interest rate swap agreements were cancelled in conjunction with the repayment of $85 million of senior secured notes. The interest expense related to the make whole premium charge of $17.9 million was recorded as a charge to earnings in the quarter ended March 31, 2004 together with the write-off of the $1.2 million deferred financing costs associated with the senior secured notes, partially offset by a $0.9 million gain from the cancellation of the interest rate swaps.

In August 2002, the Operating Company entered into two interest rate swap agreements, each designed to hedge $10 million in underlying fixed rate senior secured notes, in order to manage interest rate risk exposure and reduce overall interest expense. In October 2002, the Operating Company entered into three additional interest rate swap agreements each designed to hedge $5 million in underlying fixed rate senior secured notes. In January 2004, all interest rate swap agreements were cancelled in conjunction with the repayment of the related $85 million of senior secured notes.

5. Leases

Inergy has certain noncancelable operating leases, mainly for office space and vehicles, which expire at various times over the next ten years.

Future minimum lease payments under noncancelable operating leases for the next five years ending September 30 and thereafter consist of the following, in thousands of dollars:

	Year Ending September 30
2006	$	5,751
2007		4,657
2008		3,590
2009		1,947
2010		802
Thereafter		1,829
Total minimum lease payments	$	18,576

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Rent expense for operating leases during 2005, 2004, and 2003 totaled $7.9 million, $4.5 million, and $2.8 million, respectively.

Inergy has certain related party leases, discussed in Note 9, of real property payable to Pascal Enterprises and Robert A. Pascal. Robert A. Pascal is the sole shareholder of United Propane (now known as Bonavita, Inc.), Pascal Enterprises and United Leasing and is on Inergy’s managing general partner’s board of directors.

6. Partners’ Capital

On December 10, 2003, the Board of Directors of the Managing General Partner declared a two-for-one split of the outstanding Limited Partnership units. The split entitled unitholders of record at the close of business on January 2, 2004 to receive one additional unit for each unit held as of such date. The distribution was made on January 12, 2004. The effect of the split was to double the number of all outstanding units and to reduce by half the minimum quarterly per unit distribution and the targeted distribution levels. All common and subordinated unit amounts and per unit amounts were restated to reflect the two-for-one split.

In December 2004, the Company issued 3,568,139 common units to unrelated third parties resulting in proceeds of $91.0 million. These proceeds were obtained to partially fund the acquisition of Star Gas.

Also in December 2004, the Company issued 4,400,000 common units in a public offering, resulting in proceeds of $121.3 million, net of underwriter’s discount, commission, and offering expenses. These funds were used to repay borrowings under the Credit Agreement.

In January 2005, the underwriters of the December 2004 4,400,000 Common Unit offering exercised their over-allotment provision and the Company issued 660,000 common units in a follow-on offering, resulting in proceeds of approximately $17.9 million, net of underwriters’ discounts, commissions, and offering expenses. These funds were used to repay borrowings under the Credit Agreement.

On August 9, 2005, Inergy issued for aggregate gross proceeds of $25 million, 769,941 special units (the “Special Units”), representing a new class of equity securities in Inergy that are not entitled to a current cash distribution and will convert into common units representing limited partnership interests in Inergy at a specified conversion rate upon the commercial operation of the Stagecoach expansion project as described below. The Special Units were issued to fund the announced $25 million acquisition of the rights to the Phase II expansion project of the Stagecoach natural gas storage facility in connection with the Stagecoach Acquisition and were issued to Inergy Holdings, L.P. (“Holdings”), a Delaware limited partnership, and an affiliate of Inergy.

Upon the commercial operation of the Stagecoach expansion project the Special Units will convert into common units at a specified conversion ratio. The initial conversion ratio is 1.0 Special Unit for 1.0 Common Unit with the conversion rate increasing 3% per three month period thereafter on a compounded basis with a maximum conversion ratio of 1.0 Special Unit for 1.43 common units.

In addition on August 9, 2005, Inergy entered into a separate Registration Rights Agreement with Holdings relating to the Special Units that allows for the registered resale of the units. Pursuant to the Registration Rights Agreement, Inergy has agreed to file a shelf registration statement for the resale of the common units issuable upon conversion of the Special Units within 180 days after the issue date of the Special Units and to use commercially reasonable efforts to cause the shelf registration statement to be declared effective by the SEC within 240 days after the issue date.

In September 2005, Inergy issued 6,500,000 common units in a public offering resulting in net proceeds after underwriters’ discounts, commissions, and offering expenses of $180.4 million. These proceeds were obtained to repay borrowings under our Credit Agreement which were incurred to make certain acquisitions, including the acquisition of the Stagecoach natural gas storage facility.

In October 2005, the underwriters of the September 2005 6,500,000 Common Unit offering exercised a portion of their over-allotment provision and Inergy issued an additional 900,000 common units in a follow-on offering, resulting in proceeds of approximately $25.0 million, net of underwriters’ discounts, commissions, and offering expenses. These funds were used to repay borrowings under our Credit Agreement.

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The amended and restated Agreement of Limited Partnership of Inergy, L.P. (Partnership Agreement) contains specific provisions for the allocation of net earnings and losses to each of the partners for purposes of maintaining the partner capital accounts.

The Partnership Agreement provides that during the Subordination Period (as defined below), the Partnership may issue up to 1,600,000 additional common units (excluding common units issued in connection with conversion of Subordinated Units into common units) or an equivalent number of securities ranking on a parity with the common units. During 2003, the Partnership issued 246,372 of such common units, thus the Partnership currently retains the ability to issue 1,353,628 additional common units under this provision. The Partnership Agreement also provides that an unlimited number of partnership interests junior to the common units may be issued without a Unitholder vote. The Partnership may also issue additional common units during the Subordination Period in connection with certain acquisitions or the repayment of certain indebtedness. After the Subordination Period, the Partnership Agreement authorizes the General Partner to cause the Partnership to issue an unlimited number of limited partner interests of any type without the approval of any Unitholders.

Quarterly Distributions of Available Cash

The Partnership is expected to make quarterly cash distributions of all of its Available Cash, generally defined as income (loss) before income taxes plus depreciation and amortization, less maintenance capital expenditures and net changes in reserves established by the General Partner for future requirements. These reserves are retained to provide for the proper conduct of the Partnership business, or to provide funds for distributions with respect to any one or more of the next four fiscal quarters.

Distributions by the Partnership in an amount equal to 100% of its Available Cash will generally be made 98.8% to the Common and Subordinated Unitholders and approximately 1.2% to the General Partner, subject to the payment of incentive distributions to the holders of Incentive Distribution Rights to the extent that certain target levels of cash distributions are achieved. To the extent there is sufficient Available Cash, the holders of common units have the right to receive the Minimum Quarterly Distribution ($0.30 per Unit), plus any arrearages, prior to any distribution of Available Cash to the holders of Subordinated Units. common units will not accrue arrearages for any quarter after the Subordination Period (as defined below) and Subordinated Units will not accrue any arrearages with respect to distributions for any quarter.

In general, the Subordination Period will continue indefinitely until the first day of any quarter beginning after June 30, 2006 for the Senior Subordinated Units and June 30, 2008 for the Junior Subordinated Units in which distributions of Available Cash equal or exceed the Minimum Quarterly Distribution on the common units and the Subordinated Units for each of the three consecutive four-quarter periods immediately preceding such date. On August 13, 2004, 1,656,684 Senior Subordinated Units were converted to common units and on August 12, 2005, an additional 1,656,684 Senior Subordinated Units were converted. Prior to the end of the Subordination Period, 286,272 Junior Subordinated Units will convert to common units after June 30, 2006 and 286,272 Junior Subordinated Units will convert to common units after June 30, 2007, if distributions of Available Cash on the common units and Subordinated Units equal or exceed the Minimum Quarterly Distribution for each of the three consecutive four-quarter periods preceding such date. Upon expiration of the Subordination Period, all remaining Subordinated Units will convert to common units.

The Partnership is expected to make distributions of its Available Cash within 45 days after the end of each fiscal quarter ending December, March, June, and September to holders of record on the applicable record date. The Partnership made distributions to unitholders, including the non-managing general partner, amounting to $67.8 million, $37.4 million, and $25.2 million during the years ended September 30, 2005, 2004, and 2003, respectively, or $1.91, $1.60, and $1.45 per unit, respectively, for the periods to which these distributions relate.

Unit Purchase Plan

Inergy’s managing general partner sponsors a unit purchase plan for its employees and the employees of its affiliates. The unit purchase plan permits participants to purchase common units in market transactions from Inergy, the general partners or any other person. All purchases made have been in market transactions, although the plan allows Inergy to issue additional units. Inergy has reserved 100,000 units for purchase under the unit purchase plan. As determined by the compensation committee, the managing general partner may match each participant’s cash base pay or salary deferrals by an amount up to 10% of such deferrals and have such amount applied toward the purchase of additional units. The managing general partner has also agreed to pay the brokerage commissions, transfer taxes and other transaction fees associated with a participant’s purchase of common units. The maximum amount that a participant may elect to have withheld from his or her salary or cash base pay with respect to unit purchases in any calendar year may not exceed 10% of his or her base salary or

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wages for the year. Units purchased on behalf of a participant under the unit purchase plan generally are to be held by the participant for at least one year. To the extent a participant desires to sell or dispose of such units prior to the end of this one year holding period, the participant will be ineligible to participate in the unit purchase plan again until the one year anniversary of the date of such sale. The unit purchase plan is intended to serve as a means for encouraging participants to invest in common units. Units purchased through the unit purchase plan by Inergy and its employees for the fiscal years ended September 30, 2005, 2004, and 2003 were 10,496 units, 9,518 units, and 10,277 units, respectively.

Long-Term Incentive Plan

Inergy’s managing general partner sponsors the Inergy Long-Term Incentive Plan for its employees, consultants, and directors and the employees of its affiliates that perform services for Inergy. The long-term incentive plan currently permits the grant of awards covering an aggregate of 1,735,100 common units, which can be granted in the form of unit options and/or restricted units; however, not more than 565,600 restricted units may be granted under the plan. With the exception of 56,000 unit options (exercise prices from $1.92 to $5.34) granted to non-executive employees in exchange for option grants made by the predecessor in fiscal 1999, all of which have been grandfathered into the long-term incentive plan and are presented as grants in the table below, all unit options and restricted units granted under the plan will vest no sooner than, and in the same proportion as, Senior Subordinated Units convert into common units as described above. The compensation committee of the managing general partner’s board of directors administers the plan.

Restricted Units

A restricted unit is a “phantom” unit that entitles the grantee to receive a common unit upon the vesting of the phantom unit, or at the discretion of the compensation committee, cash equivalent to the value of a common unit. In general, restricted units granted to employees will vest three years from the date of grant and are subject to the vesting provisions described above in connection with the Subordination Period. In addition, the restricted units will become exercisable upon a change of control of the managing general partner or Inergy.

The restricted units are intended to serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation of the common units. Therefore, plan participants will not pay any consideration for the common units they receive, and Inergy will receive no remuneration for the units.

As of September 30, 2005, there were no restricted units issued under the long-term incentive plan.

Unit Options

Unit options issued under the long-term incentive plan will generally have an exercise price equal to the fair market value of the units on the date of grant. In general, unit options will expire after 10 years and are subject to the vesting provisions described above in connection with the Subordination Period. In addition, most unit option grants made under the plan provide that the unit options will become exercisable upon a change of control of the managing general partner or Inergy. None of the outstanding unit options were exercisable at September 30, 2005. A summary of Inergy’s unit option activity for the years ended September 30, 2005, 2004, and 2003, is as follows:

	Range of Exercise Prices		Weighted- Average Exercise Price		Number of Units
Outstanding at September 30, 2002	$	1.92-$15.35	$	11.60	996,464
Granted	$	13.75-$20.13	$	16.53	308,000
Exercised		—		—	—
Canceled	$	10.00-$15.35	$	10.54	227,400
Outstanding at September 30, 2003	$	1.92-$20.13	$	13.10	1,077,064
Granted	$	20.96-$24.71	$	23.11	84,000
Exercised		—		—	—
Canceled	$	13.83-$15.35	$	14.51	46,000
Outstanding at September 30, 2004	$	1.92-$24.71	$	13.79	1,115,064
Granted	$	27.14-$31.32	$	28.81	100,500
Exercised		—		—	—
Canceled	$	10.00-$27.14	$	16.81	103,000
Outstanding at September 30, 2005	$	1.92-$31.32	$	14.87	1,112,564

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Information regarding options outstanding as of September 30, 2005 is as follows:

Range of Exercise Prices	Options Outstanding	Weighted Average Remaining Contracted Life (years)	Weighted Average Exercise Price
$  1.92 - $8.19	25,564	5.8	$	2.37
$10.00 - $11.00	475,500	5.7		10.81
$13.75 - $16.90	391,000	7.1		15.20
$19.43 - $24.14	125,000	8.1		21.09
$27.14 - $31.32	95,500	9.5		28.90
	1,112,564	6.8	$	14.87

The weighted-average remaining contract life for options outstanding at September 30, 2005 is approximately seven years. Pro forma information regarding net income and earnings per share, as required by SFAS No. 123, is included in Note 1. SFAS No. 123 requires the pro forma information be determined as if Inergy has accounted for its employee unit options under the fair value method of that statement. As described below, the fair value accounting provided under SFAS No. 123 requires the use of option valuation models that were not developed for use in valuing employee unit options. The fair value of each option grant was estimated as of the grant date using the Black-Scholes option pricing model with the following assumptions:

	2005			2004			2003
Weighted average fair value of options granted	$	1.36		$	1.41		$	1.97
Expected volatility		0.158			0.159			0.230
Distribution yield		7.0	%		6.9	%		7.5	%
Expected life of option in years		5			5			5
Risk-free interest rate		3.5	%		3.2	%		3.0	%

The Black-Scholes option valuation model was developed for use in estimating the fair value of traded options, which have no vesting restrictions and are fully transferable. In addition, option valuation models require the input of highly subjective assumptions, including the expected unit price volatility. Because Inergy’s employee unit options have characteristics significantly different from those of traded options, and because changes in the subjective input assumptions can materially affect the fair value estimate, in management’s opinion, the existing models do not necessarily provide a reliable single measure of the fair value of its employee unit options.

7. Employee Benefit Plans

A 401(k) profit-sharing plan is available to all of Inergy’s employees who have completed 30 days of service. The plan permits employees to make contributions up to 75% of their salary, up to statutory limits, which was $14,000 in 2005. The plan provides for matching contributions by Inergy for employees completing one year of service of at least 1,000 hours. Aggregate matching contributions made by Inergy were $1.2 million, $0.4 million, and $0.3 million in 2005, 2004, and 2003, respectively. For the fiscal year 2005, Inergy made contributions on behalf of its union employees to union sponsored defined benefit plans of $1.5 million. Contributions in 2004 and 2003 were not significant.

8. Commitments and Contingencies

Inergy periodically enters into agreements to purchase fixed quantities of liquid propane and distillates at fixed prices with suppliers. At September 30, 2005, the total of these firm purchase commitments was approximately $169.8 million. The company also enters into agreements to purchase quantities of liquid propane and distillates at variable prices with suppliers at future dates at the then prevailing market prices. At September 30, 2005, the quantity of these variable purchase commitments was approximately 70 million gallons.

At September 30, 2005, Inergy was contingently liable for letters of credit outstanding totaling $22 million, which guarantees various transactions.

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Inergy is periodically involved in litigation proceedings. The results of litigation proceedings cannot be predicted with certainty; however, management believes that Inergy does not have material potential liability in connection with these proceedings that would have a significant financial impact on its consolidated financial condition or results of operations.

Inergy utilizes third-party insurance subject to varying retention levels of self-insurance, which management considers prudent. Such self-insurance relates to losses and liabilities primarily associated with 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.

To the extent they have not already been paid, certain employees are entitled to receive up to $1.7 million in aggregate of bonus payments at the end of the subordination periods of the Junior and Senior Subordinated Units. As these amounts will only become due if the employees remain employed by Inergy, no amount has been accrued at September 30, 2005.

9. Related Party Transactions

In connection with our acquisition of assets from United Propane, Inc. on July 31, 2003, we entered into ten leases of real property formerly used by United Propane (now known as Bonavita, Inc.) in its business. We entered into five of these leases with United Propane, three of these leases with Pascal Enterprises, Inc. and two of these leases with Robert A. Pascal. Each of these leases provides for an initial five-year term, and is renewable by us for up to two additional terms of five years each. During the initial term of these leases we are required to make monthly rental payments totaling $59,167, of which $17,167 is payable to United Propane, $16,800 is payable to Pascal Enterprises, and $25,200 is payable to Mr. Pascal.

On May 1, 2004, Inergy Propane, LLC entered into a lease agreement with United Leasing, Inc. to lease a propane rail terminal known as the Curtis Bay Terminal for the base monthly rent of $15,000.

Robert A. Pascal is the sole shareholder of Bonavita, Inc., Pascal Enterprises and United Leasing and is on our managing general partner’s board of directors.

In connection with the financing of our Phase II expansion rights on the Stagecoach natural gas storage facility, on August 9, 2005 we entered into the Special Unit Purchase Agreement with Inergy Holdings L.P. Inergy Holdings purchased 769,741 special units (the “Special Units” for $25,000,000 in cash from us. These units are not entitled to current cash distributions, but are convertible to our common units at a special conversion ratio upon the Phase II expansion becoming commercially operational. The purchase price was based on the ten-day average closing price for the common units ending August 8, 2005.

On August 9, 2005, we also entered into a separate Registration Rights Agreement with Inergy Holdings relating to the Special Units that allows for the registered resale of the units. Pursuant to the Registration Rights Agreement, we have agreed to file a shelf registration statement for the resale of the common units issuable upon conversion of the Special Units within 180 days after the issue date of the Special Units and to use commercially reasonable efforts to cause the shelf registration statement to be declared effective by the SEC within 240 days after the issue date.

On occasion, Inergy Holdings reimburses us for expenses paid on behalf of Inergy Holdings. At September 30, 2005, we had a receivable from Inergy Holdings of $280,368 which is included in prepaid expenses and other current assets on our consolidated balance sheet.

Our managing general partner and its affiliates will not receive any management fee or other compensation for the management of us. Our managing general partner and its affiliates will be reimbursed, however, for direct and indirect expenses incurred on our behalf. For the fiscal years ended September 30, 2005, 2004 and 2003 the expense reimbursement to our managing general partner and its affiliates was approximately $3.0, $2.9, and $2.1 million, respectively, with the reimbursement related primarily to personnel costs.

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10. Segments

Inergy’s financial statements reflect two operating and reportable segments: propane operations and midstream operations, which represents a change from the retail and wholesale segments previously reported. The change was related to further diversification of the company’s business profile and growth of the company. Inergy’s propane operations include propane sales to end users, the sale of propane-related appliances and service work for propane-related equipment, the sale of distillate products and wholesale distribution of propane and provide marketing and price risk management services to other users, retailers and resellers of propane. Inergy’s midstream operations include storage of natural gas liquids for third parties, fractionation of natural gas liquids, processing of natural gas liquids, distribution of natural gas liquids, primarily from Inergy’s Stagecoach business and NGL business. Inergy’s President and Chief Executive Officer has been identified as the Chief Operating Decision Maker (CODM). The CODM evaluates performance and allocates resources based on revenues and gross profit of each segment. The accounting policies of the segments are the same as those described in the summary of significant accounting policies. All intersegment revenues and profits associated with propane sales and other services between the propane and midstream segments have been eliminated.

The identifiable assets associated with each reportable segment reviewed by the CODM include accounts receivable and inventories. Goodwill is also presented for each segment. The net asset/liability from price risk management, as reported in the accompanying consolidated balance sheets, is related to the propane segment and is specifically reviewed by the CODM. Inergy does not report property, plant and equipment, purchases of property, plant, and equipment, intangible assets, and depreciation and amortization by segment to the CODM.

Revenues, gross profit, identifiable assets and goodwill for each of Inergy’s reportable segments are presented below, in thousands of dollars. Certain reclassifications have been made to the 2004 and 2003 segment reporting to conform to the 2005 presentation.

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	Year Ended September 30, 2005
	Propane Sales Operations		Midstream Sales Operations		Total
Retail propane revenues	$	526,531	$	—	$	526,531
Wholesale propane revenues		305,457		19,625		325,082
Storage, fractionation and other midstream revenues		—		77,007		77,007
Transportation revenues		11,145		—		11,145
Propane-related appliance sales revenues		11,260		—		11,260
Retail service revenues		14,770		—		14,770
Rental service and other revenues		12,360		—		12,360
Distillate revenues		71,981		—		71,981
Gross profit		307,077		18,836		325,913
Identifiable assets		196,295		20,968		217,263
Goodwill		226,579		22,594		249,173
	Year Ended September 30, 2004
	Propane Sales Operations		Midstream Sales Operations		Total
Retail propane revenues	$	196,312	$	—	$	196,312
Wholesale propane revenues		226,183		8,707		234,890
Storage, fractionation and other midstream revenues		—		29,486		29,486
Transportation revenues		7,649		—		7,649
Propane-related appliance sales revenues		4,803		—		4,803
Retail service revenues		3,428		—		3,428
Rental service and other revenues		3,716		—		3,716
Distillate revenues		2,212		—		2,212
Gross profit		111,056		12,387		123,443
Identifiable assets		97,196		8,649		105,845
Goodwill		75,628		—		75,628
	Year Ended September 30, 2003
	Propane Sales Operations		Midstream Sales Operations		Total
Retail propane revenues	$	153,348	$	—	$	153,348
Wholesale propane revenues		190,230		—		190,230
Storage, fractionation and other midstream revenues		—		—		—
Transportation revenues		9,087		—		9,087
Propane-related appliance sales revenues		3,495		—		3,495
Retail service revenues		1,902		—		1,902
Rental service and other revenues		2,793		—		2,793
Distillate revenues		2,510		—		2,510
Gross profit		96,355		—		96,355
Identifiable Assets		58,320		—		58,320
Goodwill		62,046		—		62,046

11. Quarterly Financial Data (Unaudited)

Summarized unaudited quarterly financial data is presented below. Inergy’s business is seasonal due to weather conditions in its service areas. Propane sales to residential and commercial customers are affected by winter heating season requirements, which generally results in higher operating revenues and net income during the period from October through March of each year and lower operating revenues and either net losses or lower net income during the period from April through September of each year. Sales to industrial and agricultural customers are much less weather sensitive.

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Inergy, L.P. and Subsidiaries

Notes to Consolidated Financial Statements – (Continued)

	(In Thousands of Dollars, except per unit information)
	Quarter Ended
	December 31		March 31 (a)		June 30			September 30 (b)
Fiscal 2005
Revenues	$	257,465	$	414,428	$	173,602		$	204,641
Gross profit		64,688		136,513		50,604			74,108
Operating income (loss)		21,052		64,943		(15,339	)		7,811
Net income (loss)		11,001		54,959		(24,119	)		(3,204	)
Net income (loss) per limited partner unit:
Basic	$	0.41	$	1.52	$	(0.72	)	$	(0.18	)
Diluted	$	0.40	$	1.49	$	(0.72	)	$	(0.18	)
Fiscal 2004
Revenues	$	132,581	$	178,068	$	69,715		$	102,132
Gross profit		37,117		50,320		16,987			19,019
Operating income (loss)		12,101		25,174		(8,631	)		(7,586	)
Net income (loss)		9,370		5,422		(9,800	)		(9,588	)
Net income (loss) per limited partner unit: (c)
Basic	$	0.48	$	0.24	$	(0.42	)	$	(0.42	)
Diluted	$	0.46	$	0.23	$	(0.42	)	$	(0.42	)

^(a) For the quarter ended March 31, 2004 operating income reflects a make whole premium charge of $17.9 million, the write-off of deferred financing cost of $1.2 million, and a benefit of $0.9 million relating to swap value received upon the cancellation of outstanding interest rate swap agreements.

^(b) For the quarter ended September 30, 2005 gross profit reflects a non-cash gain associated with derivative contracts of $19.4 million which will reverse over the subsequent two quarters as the physical gallons are delivered to retail customers.

^(c) The accumulation of 2005 and 2004 Basic and Diluted net income (loss) per limited partner unit does not total the respective amounts for the fiscal years ended 2005 and 2004 due to changes in ownership percentages throughout the respective years.

12. Subsequent Events

On October 3, 2005, we acquired the assets of Atlas Gas Products, Inc., (“Atlas”), headquartered in Costonia, OH. Atlas delivers propane to approximately 7,000 customers from three retail locations.

On October 4, 2005, we acquired the assets of Dowdle Gas, Inc. (“Dowdle”), headquartered in Columbus, MS, effective as of October 1, 2005. Dowdle delivers in excess of 50 million gallons of retail propane to approximately 120,000 customers in Alabama, Florida, Georgia, Mississippi, and Tennessee from sixty-nine retail locations.

On October 14, 2005 we acquired the assets of Graeber Brothers, Inc. (“Graeber”), located in northern Mississippi, effective as of October 4, 2005. Graeber delivers retail propane to approximately 14,000 customers from six retail locations which are contiguous with the acquisition of Dowdle.

The total consideration paid for these acquisitions was approximately $165 million, including working capital, assumed liabilities and acquisition costs, and were funded through our Acquisition Facility.

On October 25, 2005, a quarterly distribution of $0.52 per limited partner unit was paid to unitholders of record on November 7, 2005 with respect to the fourth fiscal quarter of 2005, which totaled $25.1 million.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	INERGY, L.P.
	By	Inergy GP, LLC (its managing general partner)
Dated: December 12, 2005	By	/S/    JOHN J. SHERMAN
		John J. Sherman, President

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following officers and directors of Inergy GP, LLC, as managing general partner of Inergy, L.P., the registrant, in the capacities and on the dates indicated.

Date	Signature and Title
December 12, 2005	/S/    JOHN J. SHERMAN
	John J. Sherman, President, Chief Executive Officer and Director (Principal Executive Officer)
December 12, 2005	/S/    R. BROOKS SHERMAN, JR.
	R. Brooks Sherman, Jr., Senior Vice President and Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)
December 12, 2005	/S/    PHILLIP L. ELBERT
	Phillip L. Elbert, Director
December 12, 2005	/S/    WARREN H. GFELLER
	Warren H. Gfeller, Director
December 12, 2005	/S/    ARTHUR B. KRAUSE
	Arthur B. Krause, Director
December 12, 2005	/S/    ROBERT A. PASCAL
	Robert A. Pascal, Director
December 12, 2005	/S/    ROBERT D. TAYLOR
	Robert D. Taylor, Director

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Schedule II

Inergy, L.P. and Subsidiaries

Valuation and Qualifying Accounts

(in thousands)

Year ended September 30,	Balance at beginning of period		Charged to costs and expenses		Other Additions (recoveries)		Deductions (write-offs)			Balance at end of period
Allowance for doubtful accounts
2005	$	1,078	$	1,966	$	87	$	(775	)	$	2,356
2004		997		214		1,125		(1,258	)		1,078
2003		927		719		96		(745	)		997

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