Edgar Filing: INERGY L P

Form 10-K

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, 2007

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

For the transition period from to .

Commission file number: 000-32453

INERGY, L.P.

(Exact name of registrant as specified in its charter)


Delaware		43-1918951
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

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

(Address of principal executive offices) (Zip Code)

(816) 842-8181

(Registrant’s telephone number including area code)

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


Title of Each Class		Name of Each Exchange on Which Registered
Common Units representing limited partnership interests		The NASDAQ Global Select National Market

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

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

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

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

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

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

Large accelerated filer x Accelerated filer ¨ Non-accelerated filer ¨

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 42,852,434 common units of the registrant held by non-affiliates computed by reference to the $34.54 closing price of such common units on November 1, 2007, was approximately $1.5 billion. The aggregate market value of the 42,394,117 common units of the registrant held by non-affiliates computed by reference to the $32.68 closing price of such common units on March 31, 2007, the last business day of the registrant’s most recently completed second fiscal quarter, was approximately $1.4 billion. As of November 19, 2007, the registrant had 49,789,486 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 0.9% 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 1A.	Risk Factors	16

Item 1B.	Unresolved Staff Comments	30

Item 2.	Properties	30

Item 3.	Legal Proceedings	30

Item 4.	Submission of Matters to a Vote of Security Holders	31

PART II

Item 5.	Market for the Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities	32

Item 6.	Selected Financial Data	33

Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	36

Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	56

Item 8.	Financial Statements and Supplementary Data	58

Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	58

Item 9A.	Controls and Procedures	58

Item 9B.	Other Information	59

PART III

Item 10.	Directors, Executive Officers and Corporate Governance	60

Item 11.	Executive Compensation	63

Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters	75

Item 13.	Certain Relationships, Related Transactions and Director Independence	77

Item 14.	Principal Accountant Fees and Services	79

PART IV

Item 15.	Exhibits and Financial Statement Schedules	80

PART I

Item 1. Business.

Recent Developments

On October 4, 2007, we acquired the assets of Riverside Oil and Gas Company headquartered in Chestertown, New York. At the time of the acquisition, Riverside Oil and Gas delivered retail propane to approximately 3,800 customers.

On October 5, 2007, we acquired the membership interests of Arlington Storage Company, LLC (“ASC”). ASC is the majority owner and operator of the Steuben Gas Storage Company (“Steuben”), which owns a natural gas storage facility located in Steuben County, New York, with approximately 6.2 bcf of working gas capacity, maximum withdrawal capacity of 60 MMcf/day and maximum injection capability of 30 MMcf/day. In addition to Steuben, ASC owns the development rights to the Thomas Corners storage project (“Thomas Corners”). Thomas Corners is also located in Steuben County, and, upon completion, will have a working gas capacity of approximately 5.7 bcf and maximum withdrawal and injection capabilities of 100 MMcf/day and 50 MMcf/day, respectively. We expect the Thomas Corners project to be developed and commercially operational by fall of 2009.

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 growing midstream business that includes a natural gas storage facility (“Stagecoach”), a liquefied petroleum gas (“LPG”) storage facility and a natural gas liquids (“NGL”) business. For the fiscal year ended September 30, 2007, we sold and physically delivered approximately 362.2 million gallons of propane to retail customers and approximately 383.9 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 Global Select National Market under the symbol “NRGY”. We electronically file certain documents with the Securities and Exchange Commission (“SEC”). We file annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K (as appropriate), along with any related amendments and supplements. From time-to-time, we also may file registration and related statements pertaining to equity or debt offerings. You may read and download our SEC filings over the internet from several commercial document retrieval services as well as at the SEC’s website at www.sec.gov. You may also read and copy our SEC filings at the SEC’s public reference room located at 100 F. Street, N.E., Washington, D.C. 20549. Please call the SEC 1-800-SEC-0330 for further information concerning the public reference room and any applicable copy charges. In addition, our SEC filings are available at no cost after the filing thereof on our website at www.inergypropane.com. Please note that any internet addresses provided in this Form 10-K are for information purposes only and are not intended to be hyperlinks. Accordingly, no information found and/or provided at such internet addresses is intended or deemed to be incorporated by reference herein.

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 various regional brand names. As of November 1, 2007, we serve approximately 700,000 retail customers in 28 states from 321 customer service centers, which have an aggregate of approximately 32.2 million gallons of above-ground propane storage. In addition to our retail propane business, we operate a wholesale supply, marketing and distribution business, providing propane

procurement, transportation and supply and price risk management services to our customer service centers, as well as to independent dealers, multistate marketers, petrochemical companies, refinery and gas processors and a number of other NGL marketing and distribution companies in 40 states, primarily in the Midwest, Northeast and South.

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

•

the Stagecoach natural gas storage facility, a high performance, multi-cycle natural gas storage facility with approximately 26.25 bcf of working gas capacity, a maximum withdrawal capability of 500 MMcf/day and a maximum injection capability of 250 MMcf/day. Located 150 miles northwest of New York City, the Stagecoach facility is among the closest natural gas storage facilities to the northeastern United States market. Stagecoach is connected to Tennessee Gas Pipeline Company’s 300-Line. 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 August 2014.

•

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

•

the Bath Storage Facility, an LPG storage facility with a 1.4 million barrel salt cavern storage facility located near Bath, New York, approximately 210 miles northwest of New York City and 60 miles from our Stagecoach facility. The facility is supported by both rail and truck terminals capable of loading/unloading 15 – 17 rail cars per day and 15 truck transports per day.

We have grown primarily through acquisitions. Since our predecessor’s inception in November 1996 through September 30, 2007, we have acquired the assets and liabilities of 72 companies for an aggregate purchase price of approximately $1.5 billion, including working capital, assumed liabilities and acquisition costs. The acquisitions include the assets and liabilities of 11 propane companies and 2 midstream companies acquired during fiscal 2007 for an aggregate purchase price, net of cash acquired, of approximately $98.9 million.

The following chart sets forth information about each business we acquired during the fiscal year ended September 30, 2007 and through the date of this filing:


Acquisition Date	Company	Location
October 2006	Bath Storage Facility	Bath, NY
October 2006	Columbus Butane Company, Inc.	Columbus, MS
October 2006	Hometown Propane, Inc.	Campbell, NY
November 2006	Mideastern Oil Company, Inc.	Salisbury, MD
December 2006	Sunbelt Energy of Florida, LLC	Jacksonville, FL
December 2006	Stevens Gas Service, Inc.	Essex Junction, VT
February 2007	South Lateral Pipeline	Tioga County, NY
May 2007	F&S Oil Company	Waterbury, CT
July 2007	Brent & Selma retail propane locations	Selma, AL
August 2007	Quality Propane, Inc.	Tallahassee, FL
August 2007	Bay Cities Gas Corporation	Tampa, FL
September 2007	Prince Oil Company, Inc. (d/b/a Valley Propane)	Christiansburg, VA
September 2007	DeCock Bottled Gas & Oil Company	Escanaba, MI

Acquisitions after September 30, 2007
October 2007	Riverside Gas & Oil Company	Chestertown, NY
October 2007	Arlington Storage Company, LLC	Steuben County, NY

Industry Background and Competition

Propane

Propane, a by-product of natural gas processing and petroleum refining, is a clean-burning energy source recognized for its transportability and ease of use relative to alternative stand-alone energy sources. Our retail

propane business consists principally of transporting propane to our customer service centers and other distribution areas and then to tanks located on our customers’ premises. Retail propane falls into four broad categories: residential, industrial, commercial and agricultural. Residential customers use propane primarily for space and water heating. Industrial customers use propane primarily as fuel for forklifts and stationary engines, to fire furnaces, as a cutting gas, in mining operations and in other process applications. Commercial customers, such as restaurants, motels, laundries and commercial buildings, use propane in a variety of applications, including cooking, heating and drying. In the agricultural market, propane is primarily used for tobacco curing, crop drying, poultry brooding and weed control.

Propane is extracted from natural gas or oil wellhead gas at processing plants or separated from crude oil during the refining process. Propane is normally transported and stored in a liquid state under moderate pressure or refrigeration for ease of handling in shipping and distribution. When the pressure is released or the temperature is increased, it is usable as a flammable gas. Propane is colorless and odorless; an odorant is added to allow its detection. Propane is clean-burning, producing negligible amounts of pollutants when consumed.

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

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

In addition to competing with alternative energy sources, we compete with other companies engaged in the retail propane distribution business. Competition in the propane industry is highly fragmented and generally occurs on a local basis with other large full-service, multi-state propane marketers, smaller local independent marketers and farm cooperatives. Based on industry publications, we believe that the 10 largest retailers account for approximately 40% of the total retail sales of propane in the United States, and that no single marketer has a greater than 10% share of the total retail market in the United States. Most of our customer service centers compete with several marketers or distributors. Each customer service center operates in its own competitive environment because retail marketers tend to locate in close proximity to customers. Our typical customer service center generally has an effective marketing radius of approximately 25 miles, although in certain rural areas the marketing radius may be extended by a satellite location.

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

Retail propane distributors typically price retail usage based on a per gallon margin over wholesale costs. As a result, distributors generally seek to maintain their operating margins by passing costs through to customers, thus insulating themselves from volatility in wholesale propane prices.

The propane distribution industry is characterized by a large number of relatively small, independently owned and locally operated distributors. Each year, a 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.

Midstream

We own, as part of our midstream operations, a high-performance, multi-cycle natural gas storage facility (Stagecoach) in New York that we acquired in August 2005. We also own 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, and a 1.4 million barrel salt cavern liquefied petroleum gas storage facility near Bath, New York. We believe these businesses complement our existing propane operations and provide us with added long-term strategic benefits.

Natural Gas Storage Business

According to the Energy Information Administration’s 2007 report Natural Gas Consumption Overview, natural gas supplies approximately 23% of U.S. energy, generating about 26.4% of electric power, supplying heat to over half of all U.S. homes and providing over 35% of all primary energy for U.S. industries. In recent years, the market for natural gas has experienced increasingly volatile prices, due in part to the following factors:

•

weather-related demand shifts;

•

infrastructure constraints;

•

trading impacts on short-term energy markets; and

•

supply, demand and other factors affecting alternative fuels.

Underground natural gas storage facilities are a critical component of the North American natural gas transmission and distribution system. They provide an essential reliability cushion against unexpected disruptions in supply, transportation or markets, and allow for the warehousing of gas to meet expected seasonal and daily variability in demand. According to the Energy Information Administration, U.S. natural gas consumption is expected to grow at a compound annual growth rate of approximately 1.0% through 2020.

Most forecasts of North American natural gas supply and demand suggest a continuation of trends that will result in increased demand for natural gas storage capacity. Seasonal and weather sensitive demand sectors (residential and commercial heating demand and gas-fired power generation demand) have been growing and are expected to continue to do so, while the less seasonal industrial demand has been declining. Natural gas supply, meanwhile, has become almost entirely non-seasonal, requiring greater reliance on natural gas storage to respond to demand variability. On average, total North American natural gas consumption levels are approximately 40% higher in

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

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

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

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

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

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

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

Storage capacity is held by a wide variety of market participants for a variety of purposes such as:

Reliability: local distribution companies (“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 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 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. Our natural gas processing operation, located in Bakersfield, CA, separates, for the most part, the NGLs from the methane, and delivers the methane to the local natural gas pipelines. The NGLs are retained for further processing within our fractionation facility.

NGL fractionation facilities separate mixed NGL streams into discrete NGL products: 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 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 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.

Business Strategy

Our primary objective is to increase distributable cash flow for our unitholders, while maintaining the highest level of commitment and service to our customers. We have engaged and will continue to engage in objectives of further growth through acquisitions both in our propane and midstream operations, internally generated expansion, and measures aimed at increasing the profitability of existing operations.

Competitive Strengths

We intend to pursue this objective by capitalizing on what we believe are our competitive strengths as follows:

Proven Acquisition Expertise

Since our predecessor’s inception and through September 30, 2007, we have acquired and successfully integrated 72 companies—68 propane companies and 4 midstream businesses. Our executive officers and key employees,

who together average more than 15 years experience in the propane and midstream energy-related industries, have developed business relationships with retail propane owners and businesses as well as other midstream industry participants throughout the United States. These significant industry contacts have enabled us to negotiate most of our acquisitions on an exclusive basis. We believe that this acquisition expertise should allow us to continue to grow through strategic and accretive acquisitions. Our acquisition program will continue to seek:

•

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

•

propane and midstream businesses in attractive market areas;

•

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

•

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

•

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

•

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

•

retention of key employees in acquired businesses.

Management Experience

Our senior management team has extensive experience in the propane and midstream energy industry. Our management team has a proven track record of enhancing the value of our partnership, through the acquisition, integration and optimization of the businesses we own and operate.

Flexible Financial Structure

We have a $350 million revolving credit facility for acquisitions and a $75 million revolving working capital facility. These facilities include a provision which allows us to utilize up to $200 million of combined borrowing capacity for working capital as needed during the winter heating season. We believe our available capacity under these facilities combined with our ability to fund acquisitions through the issuance of additional partnership interests will provide us with a flexible financial structure that will facilitate our acquisition strategy.

Propane Business Strengths

Focus on High Percentage of Retail Sales to Residential Customers

Our retail propane operations concentrate on sales to residential customers. Residential customers tend to generate higher margins and are generally more stable purchasers than other customers. For the fiscal year ended September 30, 2007, sales to residential customers represented approximately 69% of our retail propane gallons sold. Although overall demand for propane is affected by weather and other factors, we believe that residential propane consumption is not materially affected by general economic conditions because most residential customers consider home space heating to be an essential purchase. In addition, we own nearly 90% of the propane tanks located at our customers’ homes. In many states, fire safety regulations restrict the refilling of a leased tank solely to the propane supplier that owns the tank. These regulations, which require customers to switch propane tanks when they switch suppliers, help enhance the stability of our customer base because of the inconvenience and costs involved with switching tanks and suppliers.

Regionally Branded Operating Structure

We believe that our success in maintaining customer stability and our low cost operating structure at our customer service centers results from our decentralized operation under established, locally recognized trade names. We attempt to capitalize on the reputation of the companies we acquire by retaining their local brand

names and employees, thereby preserving the goodwill of the acquired business and fostering employee loyalty and customer retention. We expect our local branch management to continue to manage the marketing programs, new business development, customer service and customer billing and collections. We believe that our employee incentive programs encourage efficiency and allow us to control costs at the corporate and field levels.

Operations in Attractive Propane Markets

A majority of our propane operations are concentrated in attractive propane market areas, where natural gas distribution is not cost-effective, margins are relatively stable, and tank control is relatively high. We intend to pursue acquisitions in similar attractive markets.

Comprehensive Propane Logistics and Distribution Business

One of our distinguishing strengths is our propane procurement and distribution expertise and capabilities. For the fiscal year ended September 30, 2007, we delivered approximately 383.9 million gallons of propane on a wholesale basis to our various customers. These operations are significantly larger on a relative basis than the wholesale operations of most publicly-traded propane businesses. We also provide transportation services to these distributors through our fleet of transport vehicles, and price risk management services to our customers through a variety of financial and other instruments. The presence of our trucks serving our wholesale customers allows us to take advantage of various pricing and distribution inefficiencies that exist in the market from time to time. We believe our wholesale business enables us to obtain valuable market intelligence and awareness of potential acquisition opportunities. Because we sell on a wholesale basis to many residential and commercial retailers, we have an ongoing relationship with a large number of businesses that may be attractive acquisition opportunities for us. We believe that we will have an adequate supply of propane to support our growing retail operations at prices that are generally available only to large wholesale purchasers. This purchasing scale and resulting expertise also helps us avoid shortages during periods of tight supply to an extent not generally available to other retail propane distributors.

Midstream Business Strengths

Strategically Located Assets

Our assets are situated close to or within demand based market areas, which positions us well to leverage the services we offer to our customers relative to our competitors. We own and operate natural gas storage operations approximately 200 miles northwest of New York City. These assets are among the closest natural gas storage facilities to the New York City market and have the capability of delivering gas to this market as well as other Northeast and Mid-Atlantic market centers. We also own and operate an NGL operation in Bakersfield, California, strategically situated between the major refining centers of Los Angeles and San Francisco. We believe there are opportunities to further leverage our geographic location, expand our current asset base and to enhance the platform of services we offer to our customers that will further enhance the value and profitability of these assets.

Ability to Leverage Industry Relationships

Our management team has extensive industry relationships and they have been successful in leveraging these relationships with both new and existing customers of our midstream operations into profitable opportunities to further grow our operations.

Stable Cash Flows

Our midstream operations consist predominantly of fee-based services that generate stable cash flows. Our Stagecoach operations are 100% fee-based with a weighted average contract maturity which extends to August

2014. These contracts are with investment-grade rated customers such as large east coast utilities and major gas marketing firms. In addition, our West Coast NGL operations are also primarily fee-based and have little exposure to fluctuations in commodity prices. We believe that this further adds to our stable cash flow and enhances our access to the capital markets.

Operations

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

Propane Operations

Retail Propane

Customer Service Centers

At November 1, 2007, we distribute propane to approximately 700,000 retail customers from 321 customer service centers in 28 states. We market propane primarily in rural areas, but also have a significant number of customers in suburban areas where energy alternatives to propane such as natural gas are generally not available. We market our propane primarily in the eastern half of the United States through our customer service centers using multiple regional brand names. The following table shows our customer service centers by state:


State		Number of Customer Service Centers
Alabama		46
Arkansas		2
Connecticut		4
Florida		23
Georgia		5
Illinois		4
Indiana		22
Kentucky		1
Maine		5
Maryland		8
Massachusetts		4
Michigan		34
Mississippi		35
New Hampshire		3
New Jersey		4
New York		11
North Carolina		9
Ohio		26
Oklahoma		3
Pennsylvania		9
Rhode Island		1
South Carolina		2
Tennessee		10
Texas		26
Vermont		8
Virginia		4
West Virginia		3
Wisconsin		9

Total		321

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

Customer Deliveries

Retail deliveries of propane are usually made to customers by means of our fleet of bobtail and rack trucks. Propane is pumped from the bobtail truck, which generally holds 2,500 to 3,000 gallons, into a stationary storage tank at the customer’s premises. The capacity of these tanks range from 100 gallons to 1,200 gallons, with a typical tank having a capacity of 100 to 300 gallons in milder climates and 500 to 1,000 gallons in colder climates. We also deliver propane to retail customers in portable cylinders, which typically have a capacity of five to thirty-five gallons. These cylinders typically are picked up by us and replenished at our distribution locations, then returned to the retail customer. To a limited extent, we also deliver propane to certain customers in larger trucks known as transports, which have an average capacity of approximately 10,000 gallons. These customers include industrial customers, large-scale heating accounts and large agricultural accounts.

During the fiscal year ended September 30, 2007, we delivered approximately half of our propane volume to retail customers and half to wholesale customers. Our retail volume sold to residential, industrial and commercial, and agricultural customers were as follows:

•

approximately 69% to residential customers;

•

approximately 22% to industrial and commercial customers; and

•

approximately 9% to agricultural customers.

No single retail customer accounted for more than 1% of our revenue during the fiscal year ended September 30, 2007.

Approximately half of our residential customers receive their propane supply under an automatic delivery program. Under the automatic delivery program, we deliver propane to our heating customers approximately six times during the year. We determine the amount of propane delivered based on weather conditions and historical consumption patterns. Our automatic delivery program eliminates the customer’s need to make an affirmative purchase decision, promotes customer retention by ensuring an uninterrupted supply and enables us to efficiently route deliveries on a regular basis. We promote this program by offering level payment billing, discounts, fixed price options and price caps. In addition, we generally provide emergency service 24 hours a day, seven days a week, 52 weeks a year.

Seasonality

The retail propane business is seasonal with weather conditions significantly affecting demand for propane. We believe that the geographic diversity of our areas of operations helps to minimize our exposure to regional weather. Although overall demand for propane is affected by climate, changes in price and other factors, we believe our residential and commercial business to be relatively stable due to the following characteristics:

•

residential and commercial demand for propane has been relatively unaffected by general economic conditions due to the largely non-discretionary nature of most propane purchases by our customers;

•

loss of customers to competing energy sources has been low;

•

the tendency of our customers to remain with us due to the product being delivered pursuant to a regular delivery schedule and to our ownership of approximately 90% of the storage tanks utilized by our customers; and

•

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

Since home heating usage is the most sensitive to temperature, residential customers account for the greatest usage variation due to weather. Variations in the weather in one or more regions in which we operate can significantly affect the total volumes of propane we sell and the margins we realize and, consequently, our results of operations. We believe that sales to the commercial and industrial markets, while affected by economic patterns, are not as sensitive to variations in weather conditions as sales to residential and agricultural markets.

Transportation Assets and Truck Maintenance

Our transportation assets are operated by L&L Transportation, LLC, a wholly-owned subsidiary of Inergy Propane. The transportation of propane requires specialized equipment. Propane trucks carry specialized steel tanks that maintain the propane in a liquefied state. As of September 30, 2007, we owned a fleet of approximately 143 tractors, 625 transports, 1,192 bobtail and rack trucks and 714 other service vehicles. In addition to supporting our retail and wholesale propane operations, our fleet is also used to deliver butane and ammonia for third parties and to distribute natural gas for various processors and refiners.

We own truck maintenance facilities located in Indiana and Ohio. We also have a trucking operation located in California as part of our NGL business. We believe that our ability to maintain the trucks we use in our propane operations significantly reduces the costs we would otherwise incur in maintaining our fleet of trucks.

Pricing Policy

Our pricing policy is an essential element in our successful marketing of propane. We base our pricing decisions on, among other things, prevailing supply costs, local market conditions and local management input. We rely on our regional management to set prices based on these factors. Our local managers are advised regularly of any changes in the posted prices of our propane suppliers. We believe our propane pricing methods allow us to respond to changes in supply costs in a manner that protects our customer base and gross margins. In some cases, however, our ability to respond quickly to cost increases could cause our retail prices to rise more rapidly than those of our competitors, possibly resulting in a loss of customers.

Billing and Collection Procedures

We retain our customer billing and account collection responsibilities at the local level. We believe that this decentralized approach is beneficial for a number of reasons:

•

customers are billed on a timely basis;

•

customers are more likely to pay a local business;

•

cash payments are received faster; and

•

local personnel have current account information available to them at all times in order to answer customer inquiries.

Trademarks and Trade Names

We use a variety of trademarks and trade names which we own, including “Inergy” and “Inergy Services.” We believe that our strategy of retaining the names of the companies we acquire has maintained the local identification of such companies and has been important to the continued success of the acquired businesses. 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 28% of total revenue, this business represented approximately 4% of our gross profit during the fiscal year ended September 30, 2007.

Marketing and Distribution

Because of the size of our wholesale operations one of our distinguishing strengths is our procurement and distribution expertise and capabilities. This is partly the result of the unique background of our management team, which has significant experience in the procurement aspects of the propane business. We also offer transportation services to these distributors through our fleet of transport trucks and price risk management services to our customers through a variety of financial and other instruments. Our wholesale supply, marketing and distribution business provides us with an additional income stream as well as extensive market intelligence and acquisition opportunities. In addition, these operations provide us with more secure supplies and better pricing for our customer service centers. Moreover, the presence of our trucks across the Midwest and Southeast allows us to take advantage of various pricing and distribution inefficiencies that exist in the market from time to time.

Supply

We obtain a substantial majority of our propane from domestic suppliers, with our remaining propane requirements provided by Canadian suppliers. During the fiscal year ended September 30, 2007, 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, ExxonMobil Oil Corp. (13%), BP Amoco Corp. (12%) and Sunoco, Inc. (12%), accounted for approximately 37% of propane purchases during the past fiscal year. We believe that contracts with these suppliers will enable us to purchase most of our supply needs at market prices and ensure adequate supply. No other single supplier accounted for more than 10% of propane purchases in the current year.

Propane generally is transported from refineries, pipeline terminals, storage facilities and marine terminals to our approximate 650 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 ensure the availability of propane during periods of short supply. We are currently a party to propane forward and option contracts with various third parties to purchase and sell propane at fixed prices in the future. We monitor these activities through enforcement of our risk management policy.

Midstream Operations

Natural Gas Storage Operations

Stagecoach was acquired on August 9, 2005 and is a high performance, multi-cycle natural gas storage facility with approximately 26.25 bcf of working storage capacity of natural gas, maximum withdrawal capability of 500 MMcf/day, and maximum injection capability of 250 MMcf/day. Located approximately 150 miles northwest of New York City, the Stagecoach facility is currently connected to Tennessee Gas Pipeline Company’s 300 Line and is a significant participant in the northeast United States natural gas distribution system. On September 1, 2007, we placed into full commercial service an expansion of our Stagecoach facility, which increased our working storage capacity of natural gas to approximately 26.25 bcf through the addition of approximately 13.0 bcf of storage to our existing 13.25 bcf working storage capacity. The Stagecoach facility, including the expansion storage capacity is 100% contracted with predominantly investment-grade rated customers such as large east coast utility companies and major gas marketing firms. As of September 30, 2007, the total capital invested in the Stagecoach facility including the initial acquisition and associated expansion capital was approximately $335.6 million. Stagecoach is also expected to construct a pipeline interconnect with the proposed Millennium Pipeline which will enhance and further diversify our supply sources and provide interruptible wheeling opportunities to its shipper community.

West Coast NGL Operations

Our NGL business, located near Bakersfield, CA, currently provides natural gas gathering/processing, liquids processing and fractionation, rail and truck terminal throughput, propane storage, natural gas liquids transportation, and purchase and sale of LPG purity products. The facility includes a 10,000 barrel per day NGL fractionation plant, a 25 million cubic feet per day natural gas processing plant, approximately 6 million gallons of NGL storage and state of the art rail and trucking terminals. This facility is supported by predominantly fee based contracts. We have announced a significant capital expansion of this facility, including the construction of additional refrigerated NGL storage capacity and the installation of a butane isomerization unit to convert normal butane into isobutane for use by west coast refiners in gasoline blending. We expect this expansion to be in commercial service by the fall of 2008.

Bath LPG Storage Facility

Our Bath LPG storage facility is a 1.4 million barrel salt cavern storage facility located near Bath, New York, approximately 210 miles northwest of New York City and approximately 60 miles from our Stagecoach facility. The facility is supported by both rail and truck terminals capable of loading and unloading 15-17 rail cars per day and 15 truck transports per day. The facility is currently fully contracted in butane and propane storage.

For more information on our reportable business segments, see Note 12 to our Consolidated Financial Statements

Employees

As of November 1, 2007, we had 2,880 full-time employees and 91 part-time employees. Of the 2,971 employees, 113 were general and administrative and 2,858 were operational. Of the operational employees, 153 were members of labor unions. We believe that our relationship with our employees is satisfactory.

Government Regulation

National Fire Protection Association Pamphlets No. 54 and No. 58, which establish rules and procedures governing the safe handling of propane, or comparable regulations, have been adopted as the law in substantially all of the states in which we operate. In some states these laws are administered by state agencies, and in others they are administered on a county or municipal level. Regarding the transportation of propane, ammonia and butane by truck, we are subject to regulations promulgated under the Federal Motor Carrier Safety Act. These

regulations cover the transportation of hazardous materials and are administered by the United States Department of Transportation. We conduct ongoing training programs to help ensure that our operations are in compliance with applicable regulations. We maintain various permits that are necessary to operate some of our facilities, some of which may be material to our operations. We believe that the procedures currently in effect at all of our facilities for the handling, storage and distribution of propane and the transportation of ammonia and butane are consistent with industry standards and are in compliance in all material respects with applicable laws and regulations.

Our midstream operations are subject to federal, state and local regulatory authorities. Specifically, our Stagecoach natural gas storage facility and related assets are subject to the regulation of the Federal Energy Regulatory Commission, or FERC.

Under the Natural Gas Act of 1938 (“NGA”), FERC has authority to regulate gas transportation services in interstate commerce, including storage services. FERC’s authority to regulate those services includes the rates charged for the services, terms and conditions of service, certification and construction of new facilities, the extension or abandonment of services and facilities, the maintenance of accounts and records, the acquisition and disposition of facilities, the initiation and discontinuation of services, relationships with affiliated entities, and various other matters. Natural gas companies may not charge rates that, upon review by the FERC, are found to be unjust, unreasonable, or unduly discriminatory. In addition, the FERC prohibits natural gas companies from unduly preferring or unreasonably discriminating against any person with respect to pipeline transportation rates or terms and conditions of service. The rates and terms and conditions for such services are found in the FERC-approved tariff of Central New York Oil and Gas Company, LLC (“CNYOG”), our regulated subsidiary and owner of the Stagecoach facility. Pursuant to the NGA, existing interstate transportation and storage rates may be challenged by complaint and are subject to prospective change by FERC. Additionally, rate increases proposed by the regulated pipeline or storage provider may be challenged by protest and such proposed increases may ultimately be rejected by FERC. CNYOG currently holds authority from FERC to charge and collect market-based rates for services it provides at the Stagecoach facility. There can be no guarantee that CNYOG will be allowed to continue to operate under such a rate structure for the remainder of the Stagecoach facility’s operating life. Any successful complaint or protest against rates charged for Stagecoach storage and related services, or CNYOG’s loss of market-based rate authority, could have an adverse impact on our revenues.

In addition, the Stagecoach facility’s market-based rate authority would be subject to further review if we acquire transportation facilities or additional storage capacity, if we or one of our affiliates provides storage or transportation services in the same market area or acquires an interest in another storage field that can link our facilities to the market area or if we or one of our affiliates acquire an interest in or is acquired by an interstate pipeline.

In August, 2005, Congress enacted legislation that, among other matters, amends the NGA to make it unlawful for “any entity” to use any deceptive or manipulative device or contrivance in connection with the purchase or sale of natural gas or the purchase or sale of transportation services, including storage services such as those provided by the Stagecoach facility, subject to FERC regulation, in contravention of rules prescribed by the FERC. On January 20, 2006, the FERC issued rules implementing this provision. The rules make it unlawful for any entity, in connection with the purchase or sale of natural gas subject to the jurisdiction of the FERC, or the purchase or sale of FERC-regulated transportation services, directly or indirectly, to use or employ any device, scheme or artifice to defraud; to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or to engage in any act or practice that operates as a fraud

or deceit upon any entity. The new legislation also amends the NGA to give the FERC authority to impose civil penalties for violations of the NGA up to $1,000,000 per day per violation. The new anti-manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales, gas processing, or gathering, but does apply to activities of interstate gas pipelines and storage providers, as well as otherwise non-jurisdictional entities, such as gas processors, to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction. It therefore reflects an expansion of the FERC’s NGA enforcement authority.

Certain aspects of our midstream operations are also subject to the Pipeline Safety Act of 2002, as amended by the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006, which provides guidelines in the area of testing, education, training and communication. In addition to pipeline integrity tests, pipeline and storage companies are required to implement a qualification program to make certain that employees are properly trained. The United States Department of Transportation has approved our qualification program. We believe that we are in substantial compliance with these requirements and have integrated appropriate aspects of the law into our Operator Qualification Program, which is in place and functioning.

Additionally, we are subject to stringent federal, state and local environmental, health and safety laws and environmental regulations governing our operations. These laws and regulations impose limitations on the discharge and emission of pollutants and establish standards for the handling of solid and hazardous wastes. Applicable laws include the Resource Conservation and Recovery Act, the Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), the Clean Air Act, the Occupational Safety and Health Act, the Emergency Planning and Community Right to Know Act, the Clean Water Act and comparable state or local statutes. CERCLA, also known as the “Superfund” law, imposes joint and several liability without regard to fault or the legality of the original conduct on certain classes of persons that are considered to have contributed to the release or threatened release of a hazardous substance into the environment. While propane is not a hazardous substance within the meaning of CERCLA, other chemicals used in our operations may be classified as hazardous substances. Failure to comply with these laws and regulations may result in the assessment of administrative, civil or criminal penalties, the imposition of remedial liabilities and the issuance of injunctions restricting or prohibiting our activities. We have not received any notices that we have violated these environmental laws and regulations in any material respect and we have not otherwise incurred any material liability or capital expenditure thereunder.

For acquisitions that involve the purchase of real estate, we conduct due diligence investigations to assess whether any material or waste has been sold from, or stored on, or released or spilled from any of that real estate prior to its purchase. This due diligence includes questioning the seller, obtaining representations and warranties concerning the seller’s compliance with environmental laws and performing site assessments. During these due diligence investigations, our employees, and, in certain cases, independent environmental consulting firms, review historical records and databases and conduct physical investigations of the property to look for evidence of contamination, compliance violations and the existence of underground storage tanks.

Recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gas” and including methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of fuels such as propane and natural gas, may be contributing to warming of the Earth’s atmosphere. In response to such studies, the U.S. Congress is actively considering legislation to reduce emissions of greenhouse gases. In addition, at least 17 states have already taken legal measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Also, as a result of the U.S. Supreme Court’s decision on April 2, 2007 in Massachusetts, et al. v. EPA, the U.S. Environmental Protection Agency or “EPA” may be required to regulate greenhouse gas emissions from mobile sources (e.g., cars and trucks) even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. The Court’s holding in Massachusetts that greenhouse gases fall under the federal Clean Air Act’s definition of “air pollutant” may also result in future regulation of greenhouse gas emissions from stationary sources under certain Clean Air Act programs. Passage of climate

control legislation or other regulatory initiatives by Congress or various states of the U.S. or the adoption of regulations by the EPA or analogous state agencies that restrict emissions of greenhouse gases in areas in which we conduct business could have an adverse affect on our operations and demand for our services.

In addition, the Department of Homeland Security Appropriations Act of 2007 requires the Department of Homeland Security or “DHS” to issue regulations establishing risk-based performance standards for the security of chemical and industrial facilities, including oil and gas facilities that are deemed to present “high levels of security risk.” The DHS issued an interim final rule in April 2007 regarding risk-based performance standards to be attained pursuant to the act and the DHS is currently adopting an Appendix A to the interim rules that establish the chemicals of concern and their respective threshold quantities that will trigger compliance with the interim rules.

Future developments, such as stricter environmental, health or safety laws and regulations, or more stringent enforcement of existing requirements could affect our operations. We do not anticipate that our compliance with or liabilities under environmental, health and safety laws and regulations, including CERCLA, will require any material increase in our capital expenditures or otherwise have a material adverse effect on us. To the extent that any environmental liabilities, or environmental, health or safety laws, or regulations are made more stringent, there can be no assurance that our results of operations will not be materially and adversely affected.

Item 1A. Risk Factors

Risks Inherent in Our Business

If we do not continue to make acquisitions on economically acceptable terms, our future financial performance will be limited.

Due to increased competition from alternative energy sources the propane industry is not a growth industry. In addition, as a result of long-standing customer relationships that are typical in the retail home propane industry, the inconvenience of switching tanks and suppliers and propane’s higher cost as compared to other energy sources, we may have difficulty in increasing our retail customer base other than through acquisitions. Therefore, while our operating objectives include promoting internal growth, our ability to grow depends principally on acquisitions. Our future financial performance depends on our ability to continue to make acquisitions at attractive prices. There is no assurance that we will be able to continue to identify attractive acquisition candidates in the future or that we will be able to acquire businesses on economically acceptable terms. In particular, competition for acquisitions in the propane business has intensified and become more costly. We may not be able to grow as rapidly as we expect through our acquisition of additional businesses for various reasons, including the following:

•

We will use our cash from operations primarily to service our debt and for distributions to unitholders and reinvestment in our business. Consequently, the extent to which we are unable to use cash or access capital to pay for additional acquisitions may limit our growth and impair our operating results. Further, we are subject to certain debt incurrence covenants under our bank credit agreement and the indentures that govern our 6.875% senior notes due 2014 and 8.25% senior notes due 2016 that may restrict our ability to incur additional debt to finance acquisitions.

•

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

•

We will use cash for capital expenditures related to infrastructure expansions such as the Stagecoach expansion project, which will reduce our cash available to pay for additional acquisitions.

Moreover, acquisitions involve potential risks, including:

•

our inability to integrate the operations of recently acquired businesses,

•

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

•

customer or key employee loss from the acquired businesses, and

•

a significant increase in our indebtedness.

Our growth strategy includes acquiring entities with lines of business that are distinct and separate from our existing operations which could subject us to additional business and operating risks.

Consistent with our announced growth strategy and our acquisition of the Stagecoach facility and related assets, we may acquire assets that have operations in new and distinct lines of business from our existing operations, including midstream assets. Integration of new business segments is a complex, costly and time-consuming process and may involve assets in which we have limited operating experience. Failure to timely and successfully integrate acquired entities’ new lines of business with our existing operations may have a material adverse effect on our business, financial condition or results of operations. The difficulties of integrating new business segments with existing operations include, among other things:

•

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

•

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

•

integrating personnel with diverse business backgrounds and organizational cultures; and

•

consolidating corporate and administrative functions.

In addition, the diversion of our attention and any delays or difficulties encountered in connection with the integration of the new business segments, such as unanticipated liabilities or costs, could harm our existing business, results of operations, financial condition or prospects. Furthermore, new lines of business will subject us to additional business and operating risks which could have a material adverse effect on our financial condition or results of operations.

We may be unable to successfully integrate our recent acquisitions.

One of our primary business strategies is to grow through acquisitions. There is no assurance that we will successfully integrate acquisitions into our operations, or that we will achieve the desired profitability from our acquisitions. Failure to successfully integrate these substantial acquisitions could adversely affect our operations. The difficulties of combining the acquired operations include, among other things:

•

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

•

coordinating geographically disparate organizations, systems and facilities;

•

integrating personnel from diverse business backgrounds and organizational cultures;

•

consolidating corporate, technological and administrative functions;

•

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

•

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

•

customer or key employee loss from the acquired businesses;

•

a significant increase in our indebtedness; and

•

potential environmental or regulatory liabilities and title problems.

In addition, we may not realize all of the anticipated benefits from our acquisitions, such as cost-savings and revenue enhancements, for various reasons, including difficulties integrating operations and personnel, higher costs, unknown liabilities and fluctuations in markets.

Our indebtedness may limit our ability to borrow additional funds, make distributions to our unitholders, or capitalize on acquisition or other business opportunities, in addition to impairing our ability to fulfill our debt obligation under our senior notes.

As of September 30, 2007, we had approximately $710 million of total outstanding indebtedness. Our leverage, various limitations in our credit facility, other restrictions governing our indebtedness and the indentures governing the notes may reduce our ability to incur additional indebtedness, to engage in some transactions and to capitalize on acquisition or other business opportunities.

Our indebtedness and other financial obligations could have important consequences. For example, they could:

•

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

•

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

•

result in higher interest expense in the event of increases in interest rates since some of our debt is, and will continue to be, at variable rates of interest;

•

have a material adverse effect on us if we fail to comply with financial and restrictive covenants in our debt agreements and an event of default occurs as a result of that failure that is not cured or waived;

•

require us to dedicate a substantial portion of our cash flow to payments of our indebtedness and other financial obligations, thereby reducing the availability of our cash flow to fund working capital, capital expenditures and other general partnership requirements;

•

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

•

place us at a competitive disadvantage compared to our competitors that have proportionately less debt.

If we are unable to meet our debt service obligations and other financial obligations, we could be forced to restructure or refinance our indebtedness and other financial transactions, seek additional equity capital or sell our assets. We may then be unable to obtain such financing or capital or sell our assets on satisfactory terms, if at all.

A change of control of our managing general partner could result in us facing substantial repayment obligations under our credit facility.

In addition, our bank credit agreement and the indentures governing our senior notes contain provisions relating to change of control of our managing general partner, our partnership and our operating company. If these provisions are triggered, our outstanding bank indebtedness may become due. In such an event, there is no assurance that we would be able to pay the indebtedness, in which case the lenders would have the right to foreclose on our assets, which would have a material adverse effect on us. There is no restriction on the ability of our general partners to enter into a transaction which would trigger the change of control provisions.

Restrictive covenants in the agreements governing our indebtedness may reduce our operating flexibility.

The indentures governing our outstanding senior notes and agreements governing our revolving credit facilities and other future indebtedness contain or may contain various covenants limiting our ability and the ability of our specified subsidiaries to, among other things:

•

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

•

make investments;

•

incur or guarantee additional indebtedness or issue preferred securities;

•

create or incur certain liens;

•

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

•

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

•

engage in transactions with affiliates;

•

create unrestricted subsidiaries;

•

create non-guarantor subsidiaries.

These restrictions could limit our ability and the ability of our subsidiaries to obtain future financings, make needed capital expenditures, withstand a future downturn in our business or the economy in general, conduct operations or otherwise take advantage of business opportunities that may arise. Our bank credit agreement contains covenants requiring us to maintain specified financial ratios and satisfy other financial conditions. We may be unable to meet those ratios and conditions. Any future breach of these covenants and our failure to meet any of those ratios and conditions could result in a default under the terms of our bank credit agreement, which could result in the acceleration of our debt and other financial obligations. If we were unable to repay these amounts, the lenders could initiate a bankruptcy proceeding or liquidation proceeding or proceed against the collateral.

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

Our operations are subject to all operating hazards and risks incident to handling, storing, transporting and providing customers with combustible products such as propane and natural gas. As a result, we have been, and likely will be, a defendant in legal proceedings and litigation arising in the ordinary course of business. We

maintain insurance policies with insurers in such amounts and with such coverages and deductibles as we believe are reasonable and prudent. However, our insurance may not be adequate to protect us from all material expenses related to potential future claims for personal injury and property damage. In addition, the occurrence of a serious accident, whether or not we are involved, may have an adverse effect on the public’s desire to use our products.

Our operations are subject to compliance with environmental laws and regulations that can adversely affect our results of operations and financial condition.

Our operations are subject to stringent environmental laws and regulations of federal, state and local authorities. Such environmental laws and regulations impose numerous obligations, including the acquisition of permits to conduct regulated activities, the incurrence of capital expenditures to comply with applicable laws, and restrictions on the generation, handling, treatment, storage, disposal, and transportation of certain materials and wastes. Failure to comply with such environmental laws and regulations can result in the assessment of substantial administrative, civil, and criminal penalties, the imposition of remedial liabilities and even the issuance of injunctions restricting or prohibiting our activities. Certain environmental laws impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances have been disposed or otherwise released. In the course of our operations, materials or wastes may have been spilled or released from properties owned or leased by us or on or under other locations where these materials or wastes have been taken for disposal. In addition, many of the properties owned or leased by us were previously operated by third parties whose management, disposal, or release of materials and wastes was not under our control. Accordingly, we may be liable for the costs of cleaning up or remediating contamination arising out of our operations or as a result of activities by others who previously occupied or operated on properties now owned or leased by us. It is also possible that adoption of stricter environmental laws and regulations or more stringent interpretation of existing environmental laws and regulations in the future could result in additional costs or liabilities to us as well as the industry in general.

Cost reimbursements due our managing general partner may be substantial and will reduce the cash available for principal and interest on our outstanding indebtedness.

We reimburse our managing general partner and its affiliates, including officers and directors of our managing general partner, for all expenses they incur on our behalf. The reimbursement of expenses could adversely affect our ability to make payments of principal and interest on our outstanding indebtedness. Our managing general partner has sole discretion to determine the amount of these expenses. In addition, our managing general partner and its affiliates provide us with services for which we are charged reasonable fees as determined by our managing general partner in its sole discretion.

Failure to maintain effective internal controls in accordance with Section 404 of the Sarbanes-Oxley Act could cause us to incur additional expenditures of time and financial resources.

We have completed the process of documenting and testing our internal control procedures in order to satisfy the requirements of Section 404 of the Sarbanes-Oxley Act, which requires annual management assessments of the effectiveness of our internal controls over financial reporting and a report by our independent registered public accounting firm on our controls over financial reporting. If, in the future, we fail to maintain the adequacy of our internal controls, as such standards are modified, supplemented or amended from time to time, we may not be able to ensure that we can conclude on an ongoing basis that we have effective internal controls over financial reporting in accordance with Section 404 of the Sarbanes-Oxley Act. Failure to achieve and maintain an effective internal control environment could cause us to incur substantial expenditures of management time and financial resources to identify and correct any such failure.

Risks Related to Our Propane Operations

Since weather conditions may adversely affect the demand for propane, our financial condition and results of operations are vulnerable to, and will be adversely affected by, warm winters.

Weather conditions have a significant impact on the demand for propane because many of our customers depend on propane principally for heating purposes. As a result, warm weather conditions will adversely impact our operating results and financial condition. Actual weather conditions can substantially change from one year to the next. Furthermore, warmer than normal temperatures in one or more regions in which we operate can significantly decrease the total volume of propane we sell. Consequently, our operating results may vary significantly due to actual changes in temperature. During seven of the last ten fiscal years temperatures were significantly warmer than normal in our areas of operation (based on the 30-year average consisting of years 1976 through 2005 published by the National Oceanic and Atmospheric Administration). We believe that our results of operations during these periods were adversely affected as a result of this warm weather.

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

The propane industry is a “margin-based” business in which gross profits depend on the excess of sales prices over supply costs. As a result, our profitability is sensitive to changes in wholesale prices of propane caused by changes in supply or other market conditions. When there are sudden and sharp increases in the wholesale cost of propane, we may not be able to pass on these increases to our customers through retail or wholesale prices. Propane is a commodity and the price we pay for it can fluctuate significantly in response to changes in supply or other market conditions. We have no control over supply or market conditions. In addition, the timing of cost pass-throughs can significantly affect margins. Sudden and extended wholesale price increases could reduce our gross profits and could, if continued over an extended period of time, reduce demand by encouraging our retail customers to conserve or convert to alternative energy sources.

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

We have competitors and potential competitors who are larger and have substantially greater financial resources than we do. Also, because of relatively low barriers to entry into the retail propane business, numerous small retail propane distributors, as well as companies not engaged in retail propane distribution, may enter our markets and compete with us. Most of our propane retail branch locations compete with several marketers or distributors. The principal factors influencing competition with other retail marketers are:

•

price;

•

reliability and quality of service;

•

responsiveness to customer needs;

•

safety concerns;

•

long-standing customer relationships;

•

the inconvenience of switching tanks and suppliers; and

•

the lack of growth in the industry.

We can make no assurances that we will be able to compete successfully on the basis of these factors. If a competitor attempts to increase market share by reducing prices, we may lose customers, which would reduce our revenues.

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

Most of our total volume purchases are made under supply contracts that have a term of one year, are subject to annual renewal, and provide various pricing formulas. Three of our suppliers, ExxonMobil Oil Corp. (13%), BP Amoco Corp. (12%) and Sunoco, Inc. (12%), accounted for approximately 37% of propane purchases during the fiscal year ended September 30, 2007. In the event that we are unable to purchase propane from our significant suppliers, our failure to obtain alternate sources of supply at competitive prices and on a timely basis may hurt our ability to satisfy customer demand, reduce our revenues and adversely affect our results of operations.

Competition from other energy sources may cause us to lose customers, thereby reducing our revenues.

Competition from other energy sources, including natural gas and electricity, has been increasing as a result of reduced regulation of many utilities, including natural gas and electricity. Propane is generally not competitive with natural gas in areas where natural gas pipelines already exist because natural gas is a less expensive source of energy than propane. The gradual expansion of natural gas distribution systems and availability of natural gas in many areas that previously depended upon propane could cause us to lose customers, thereby reducing our revenues.

Our business would be adversely affected if service at our principal storage facilities or on the common carrier pipelines we use is interrupted.

Historically, a substantial portion of the propane purchased to support our operations has originated at Conway, Kansas, Hattiesburg, Mississippi and Mont Belvieu, Texas and has been shipped to us through major common carrier pipelines. Any significant interruption in the service at these storage facilities or on the common carrier pipelines we use would adversely affect our ability to obtain propane.

If we are not able to sell propane that we have purchased through wholesale supply agreements to either our own retail propane customers or to other retailers and wholesalers, the results of our operations would be adversely affected.

We currently are party to propane supply contracts and expect to enter into additional propane supply contracts which require us to purchase substantially all the propane production from certain refineries. Our inability to sell the propane supply in our own propane distribution business, to other retail propane distributors, or to other propane wholesalers would have a substantial adverse impact on our operating results and could adversely impact our capital liquidity.

Energy efficiency and new technology may reduce the demand for propane and adversely affect our operating results.

Increased conservation and technological advances, including installation of improved insulation and the development of more efficient furnaces and other heating devices, have adversely affected the demand for propane by retail customers. Future conservation measures or technological advances in heating, conservation, energy generation or other devices might reduce demand for propane and adversely affect our operating results.

Due to our limited asset diversification, adverse developments in our propane business could adversely affect our operating results and reduce our ability to make distributions to our unitholders.

We rely substantially on the revenues generated from our propane business. Due to our limited asset diversification, an adverse development in this business would have a significantly greater impact on our financial condition and results of operations than if we maintained more diverse assets.

Risk Related to Our Midstream Operations

Federal, state or local regulatory measures could adversely affect our business.

Our operations are subject to federal, state and local regulatory authorities. Specifically, our Stagecoach facility and related assets are subject to the regulation of the Federal Energy Regulatory Commission, or FERC.

Under the Natural Gas Act of 1938 (“NGA”), FERC has authority to regulate our natural gas facilities that provide natural gas transportation services in interstate commerce, including storage services. FERC’s authority to regulate those services includes the rates charged for the services, terms and conditions of service, certification and construction of new facilities, the extension or abandonment of services and facilities, the maintenance of accounts and records, the acquisition and disposition of facilities, the initiation and discontinuation of services, relationships with affiliated entities, and various other matters. Natural gas companies may not charge rates that, upon review by FERC, are found to be unjust and unreasonable or unduly discriminatory. In addition, the FERC prohibits natural gas companies from unduly preferring or unreasonably discriminating against any person with respect to pipeline transportation rates or terms and conditions of service. The rates and terms and conditions for interstate services provided by Steuben are found in Steuben’s FERC-approved tariff. The rates and terms and conditions for interstate services provided by Stagecoach are found in the FERC-approved tariff of Central New York Oil and Gas Company, LLC (“CNYOG”), our regulated subsidiary and owner of the Stagecoach facility.

Pursuant to the NGA, existing interstate transportation and storage rates may be challenged by complaint and are subject to prospective change by FERC. Additionally, rate increases proposed by the regulated pipeline or storage provider may be challenged by protest and such increases may ultimately be rejected by FERC. CNYOG currently holds authority from FERC to charge and collect market-based rates for services it provides at the Stagecoach facility. There can be no guarantee that CNYOG will be allowed to continue to operate under such a rate structure for the remainder of the Stagecoach facility’s operating life. Any successful complaint or protest against rates charged for Stagecoach storage and related services, or CNYOG’s loss of market-based rate authority, could have an adverse impact on our revenues.

There can be no assurance that FERC will continue to pursue its approach of pro-competitive policies as it considers matters such as pipeline rates and rules and policies that may affect rights of access to natural gas transportation capacity, transportation and storage facilities. Any successful complaint or protest against our rates or loss of our market-based rate authority could have an adverse impact on our revenues associated with providing storage services. Failure to comply with applicable regulations under the NGA, Natural Gas Policy Act of 1978, Pipeline Safety Act of 1968 and certain other laws, and with implementing regulations associated with these laws could result in the imposition of administrative and criminal remedies and civil penalties of up to $1,000,000 per day, per violation.

Our storage business depends on neighboring pipelines to transport natural gas.

Our Stagecoach natural gas storage business depends on the Tennessee Gas Pipeline Company’s 300-Line, currently the only pipeline to which it is interconnected. This pipeline is owned by parties not affiliated with us. Any interruption of service on the pipeline or lateral connections or adverse change in the terms and conditions of service could have a material adverse effect on our ability, and the ability of our customers, to transport natural gas to and from our facilities and have a corresponding material adverse effect on our storage revenues. In addition, the rates charged by the interconnected pipelines for transportation to and from our facilities affect the utilization and value of our storage services. Significant changes in the rates charged by these pipelines or the rates charged by other pipelines with which the interconnected pipelines compete could also have a material adverse effect on our storage revenues.

We expect to derive a significant portion of our revenues from the Stagecoach facility from three customers, and the loss of one or more of these customers could result in a significant loss of revenues and cash flow.

We expect to derive a significant portion of our revenues and cash flow in connection with the Stagecoach facility from our largest three customers comprised of Consolidated Edison Company, New Jersey Resources and New Jersey Natural Gas. The loss, nonpayment, nonperformance, or impaired creditworthiness of one or more of these customers could have a material adverse effect on our business, results of operations and financial condition.

We compete with other natural gas storage companies and services that can substitute for storage services.

Our principal competitors in our natural gas storage market include other storage providers including among others Dominion Resources, Inc., NiSource Inc. and El Paso Corporation. These major pipeline natural gas transmission companies have existing storage facilities connected to their systems that compete with certain of our facilities. FERC has adopted policy that favors authorization of new storage projects, and there are numerous natural gas storage options in the New York/Pennsylvania geographic market. Pending and future construction projects, if and when brought on line, may also compete with the Stagecoach facility. Such projects may include FERC-certificated storage expansions and greenfield construction projects. We also compete with the numerous alternatives to storage available to customers, including pipeline balancing/no-notice services, seasonal/swing services provided by pipelines and marketers, and on-system LNG facilities.

Expanding our business by constructing new midstream assets subjects us to risks.

One of the ways we may grow our business is through the expansion of our existing storage facilities, such as the Stagecoach expansion project. The construction of additional storage facilities or new pipeline interconnects involves numerous regulatory, environmental, political and legal uncertainties beyond our control and may require the expenditure of significant amounts of capital. If we undertake these projects, they may not be completed on schedule or at all or at the budgeted cost. Moreover, our revenues may not increase immediately upon the expenditure of funds on a particular project. For instance, if we build a new midstream asset, the construction will occur over an extended period of time, and we will not receive material increases in revenues until the project is placed in service. Moreover, we may construct facilities to capture anticipated future growth in production and/or demand in a region in which such growth does not materialize. As a result, new facilities may not be able to attract enough throughput to achieve our expected investment return, which could adversely affect our results of operations and financial condition.

We may not be able to retain existing customers or acquire new customers, which would reduce our revenues and limit our future profitability.

The renewal or replacement of existing contracts with our customers at rates sufficient to maintain current revenues and cash flows depends on a number of factors beyond our control, including competition from other pipelines and storage providers, and the price of, and demand for, natural gas in the markets we serve. The inability of our management to renew or replace our current contracts as they expire and to respond appropriately to changing market conditions could have a negative effect on our profitability.

The fees charged by us to third parties under transmission, transportation and storage agreements may not escalate sufficiently to cover increases in costs and the agreements may not be renewed or may be suspended in some circumstances.

Our costs may increase at a rate greater than the rate that the fees we charge to third parties increase pursuant to our contracts with them. Furthermore, third parties may not renew their contracts with us. Additionally, some third parties’ obligations under their agreements with us may be permanently or temporarily reduced upon the occurrence of certain events, some of which are beyond our control, including force majeure events wherein the

supply of either natural gas, are curtailed or cut off. Force majeure events include (but are not limited to) revolutions, wars, acts of enemies, embargoes, import or export restrictions, strikes, lockouts, fires, storms, floods, acts of God, explosions, mechanical or physical failures of our equipment or facilities or those of third parties. If the escalation of fees is insufficient to cover increased costs, if third parties do not renew or extend their contracts with us or if any third party suspends or terminates its contracts with us, our financial results would be negatively impacted.

Our business would be adversely affected if operations at any of our facilities were interrupted.

Our operations are dependent upon the infrastructure that we have developed, including, storage facilities and various means of transportation. Any significant interruption at these facilities or pipelines or our customers’ inability to transmit natural gas to or from these facilities or pipelines for any reason would adversely affect our results of operations.

Risks Inherent in an Investment in Us

Unitholders have less ability to elect or remove management than holders of common stock in a corporation.

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business, and therefore limited ability to influence management’s decisions regarding our business. Unitholders did not elect our managing general partner or its board of directors and will have no right to elect our managing general partner or its board of directors on an annual or other continuing basis. The board of directors of our managing general partner is chosen by the sole member of our managing general partner, Inergy Holdings, L.P. Although our managing general partner has a fiduciary duty to manage our partnership in a manner beneficial to Inergy, L.P. and our unitholders, the directors of our managing general partner also have a fiduciary duty to manage our managing general partner in a manner beneficial to its member, Inergy Holdings, L.P.

If unitholders are dissatisfied with the performance of our managing general partner, they will have little ability to remove our managing general partner. Our managing general partner generally may not be removed except upon the vote of the holders of 66²/3% of the outstanding units voting together as a single class.

Our unitholders’ voting rights are further restricted by a provision in our partnership agreement providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partners and their affiliates, cannot be voted on any matter.

The control of our managing general partner may be transferred to a third party without unitholder consent.

Our managing general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of our unitholders. Furthermore, there is no restriction in our partnership agreement on the ability of the owner of our managing general partner, Inergy Holdings, L.P., from transferring its ownership interest in our managing general partner to a third party. The new owner of our managing general partner would then be in a position to replace the board of directors and officers of our managing general partner with its own choices and to control the decisions taken by our board of directors and officers.

Cost reimbursements due our managing general partner may be substantial and reduce our ability to pay the minimum quarterly distribution.

Before making any distributions on our units, we will reimburse our managing general partner for all expenses it has incurred on our behalf. In addition, our general partners and their affiliates may provide us with services for which we will be charged reasonable fees as determined by our managing general partner. The reimbursement of these expenses and the payment of these fees could adversely affect our ability to make distributions to you. Our managing general partner has sole discretion to determine the amount of these expenses and fees.

We may issue additional common units without unitholder approval, which would dilute our unitholders’ existing ownership interests.

We may issue an unlimited number of limited partner interests of any type without the approval of unitholders. The issuance of additional common units or other equity securities of equal rank will have the following effects:

•

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

•

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

•

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

•

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

Our general partners have conflicts of interest and limited fiduciary responsibilities, which may permit our general partners to favor their own interests to the detriment of unitholders.

Inergy Holdings, L.P. and its affiliates directly and indirectly own an aggregate limited partner interest of approximately 10.3% in us, own and control our managing general partner and own and control our non-managing general partner, which owns an approximate 0.9% general partner interest. Inergy Holdings, L.P. also owns the incentive distribution rights under our partnership agreement. Conflicts of interest could arise in the future as a result of relationships between Inergy Holdings, L.P., our general partners and their affiliates, on the one hand, and the partnership or any of the limited partners, on the other hand. As a result of these conflicts our general partners may favor their own interests and those of their affiliates over the interests of our unitholders. The nature of these conflicts includes the following considerations:

•

Our general partners may limit their liability and reduce their fiduciary duties, while also restricting the remedies available to unitholders for actions that might, without the limitations, constitute breaches of fiduciary duty. Unitholders are deemed to have consented to some actions and conflicts of interest that might otherwise be deemed a breach of fiduciary or other duties under applicable state law.

•

Our general partners are allowed to take into account the interests of parties in addition to the partnership in resolving conflicts of interest, thereby limiting their fiduciary duties to our unitholders.

•

Our managing general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings and reserves, each of which can affect the amount of cash that is distributed to unitholders.

•

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

•

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

•

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

•

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

•

Our managing general partner is not restricted from causing us to pay it or its affiliates for any services rendered on terms that are fair and reasonable to us or entering into additional contractual arrangements with any of these entities on our behalf.

•

In some instances our managing general partner may borrow funds in order to permit the payment of distributions, even if the purpose or effect of the borrowing is to make incentive distributions.

The president and chief executive officer of our managing general partner effectively controls us through his control of the general partner of Inergy Holdings and our managing general partner.

The president and chief executive officer of both the general partner of Inergy Holdings and our managing general partner owns an economic interest of 56.4% in the general partner of Inergy Holdings and has voting

control of the general partner of Inergy Holdings. He therefore controls the general partner of Inergy Holdings and through it, our managing general partner and may be able to influence unitholder votes. Control over these entities gives our president and chief executive officer substantial control over our and Inergy Holdings’ business and operations.

Our cash distribution policy limits our ability to grow.

Because we distribute all of our available cash, our growth may not be as rapid as businesses that reinvest their available cash to expand ongoing operations. If we issue additional units or incur debt to fund acquisitions and growth capital expenditures, the payment of distributions on those additional units or interest on that debt could increase the risk that we will be unable to maintain or increase our per unit distribution level.

Tax Risks to Common Unitholders

The tax treatment of publicly traded partnerships is subject to potential legislative, judicial or administrative changes. If we were treated as a corporation for federal income tax purposes, or if legislation is passed that may preclude us from qualifying for tax treatment as a partnership, or if we were to become subject to a material amount of entity level taxation for state tax purposes, then our cash available for distribution to our unitholders would be substantially reduced.

The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes. The present federal income tax treatment of publicly traded partnerships may be modified by administrative, legislative or judicial interpretation at any time. For example, Congress is considering changes to the existing federal income tax laws that may affect certain publicly traded partnerships.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum rate of 35%, and would likely pay state income tax at varying rates. Distributions would generally be taxed again as corporate distributions, and no income, gain, loss, deduction or credit would flow through to our unitholders. Because a tax would be imposed upon us as a corporation, our cash available for distribution would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our common units.

Current law or our business may change so as to cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity level taxation. In addition, because of widespread state budget deficits, several states are evaluating ways to subject partnerships to entity level taxation through the imposition of state income, franchise or other forms of taxation. If any state were to impose a tax upon us as an entity, the cash available to pay distributions would be reduced. Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity level taxation for federal, state or local income tax purposes, then the minimum quarterly distribution amount and the target distribution amount will be adjusted to reflect the impact of that law on us.

Our unitholders may be required to pay taxes even if they do not receive cash distributions from us.

Because our unitholders will be treated as partners to whom we will allocate taxable income which could be different in amount than the cash we distribute, they will be required to pay any federal income taxes and, in some cases, state and local income taxes on their share of our taxable income even if they do not receive any cash distributions from us. Unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from their share of our taxable income.

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

A unitholder who sells common units will recognize a gain or loss equal to the difference between the amount realized and his adjusted tax basis in those common units. Prior distributions to a unitholder in excess of the total

net taxable income allocated to that unitholder, which decreased the tax basis in that unitholder’s common unit, will, in effect, become taxable income to that unitholder if the common unit is sold at a price greater than that unitholder’s tax basis in that common unit, even if the price is less than the original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income to that unitholder. In addition, if a unitholder sells units, the unitholder may incur a tax liability in excess of the amount of cash received from the sale.

Tax-exempt entities, regulated investment companies and foreign persons face unique tax issues from owning common units that may result in adverse tax consequences to them.

Investment in common units by tax-exempt entities, including employee benefit plans and individual retirement accounts (known as IRAs), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes imposed at the highest effective applicable tax rate, and non-U.S. persons will be required to file United States federal income tax returns and pay tax on their share of our taxable income.

The sale or exchange of 50% or more of our capital and profits interests within a twelve-month period will result in the termination of our partnership for federal income tax purposes.

We will be considered to have terminated our partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. Our termination would, among other things result in the closing of our taxable year for all unitholders and could result in a deferral of depreciation deductions allowable in computing our taxable income for the year in which the termination occurs. Thus, if this occurs our unitholders will be allocated an increased amount of federal taxable income for the year in which we are considered to be terminated as a percentage of the cash distributed to unitholders with respect to that period. Although the amount of increase cannot be estimated because it depends upon numerous factors including the timing of the termination, the amount could be material. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead, we would be treated as a new partnership for tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred.

Our unitholders will likely be subject to state and local taxes and return filing requirements in states where they do not live as a result of investing in our common units.

In addition to federal income taxes, our unitholders will likely be subject to other taxes, including foreign taxes, state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property and in which they do not reside. We own property and conduct business in numerous states in the United States. Unitholders may be required to file state and local income tax returns and pay state and local income taxes in many or all of the jurisdictions in which we do business or own property. Further, unitholders may be subject to penalties for failure to comply with those requirements. It is our unitholders’ responsibility to file all United States federal, state, local and foreign tax returns.

If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contest will reduce our cash available for distribution to you.

The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly

by our unitholders and our managing general partner because the costs will reduce our cash available for distribution.

We have adopted certain valuation methodologies and monthly conventions that may result in a shift of income, gain, loss and deduction between the general partner and the unitholders. The IRS may challenge this treatment, which could adversely affect the value of the common units.

When we issue additional units or engage in certain other transactions, we determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. The adopted methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and the general partner, which may be unfavorable to such unitholders. Moreover, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge the adopted valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain, loss and deduction between the general partner and certain of our unitholders.

A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.

We treat each purchaser of common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could result in a unitholder owing more tax and may adversely affect the value of the common units.

To maintain the uniformity of the economic and tax characteristics of our common units, we have adopted certain depreciation and amortization positions that may not conform with all aspects of existing Treasury Regulations. These positions may result in an understatement of deductions and an overstatement of income to our unitholders. For example, we do not amortize certain goodwill assets, the value of which has been attributed to certain of our outstanding units. A subsequent holder of those units may be entitled to an amortization deduction attributable to that goodwill under Internal Revenue Code Section 743(b). But, because we cannot identify these units once they are traded by the initial holder, we do not allocate any subsequent holder of a unit any such amortization deduction. This approach may understate deductions available to those unitholders who own those units and may result in those unitholders believing that they have a higher tax basis in their units than would be the case if the IRS strictly applied certain Treasury Regulations. This, in turn, may result in those unitholders reporting less gain or more loss on a sale of their units than would be the case if the IRS strictly applied certain Treasury Regulations.

The IRS may challenge the manner in which we calculate our unitholder’s basis adjustment under Section 743(b). If so, because neither we nor a unitholder can identify the units to which this issue relates once the initial holder has traded them, the IRS may assert adjustments to all unitholders selling units within the period under audit as if all unitholders owned such units.

A successful IRS challenge to this position or other positions we may take could adversely affect the amount of taxable income or loss allocated to our unitholders. It also could affect the gain from a unitholder’s sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

Under the terms of our Partnership Agreement, we prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under Treasury Regulations. If the IRS were to challenge this method or new Treasury regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

Item 1B. Unresolved Staff Comments.

None.

Item 2. Properties.

As of November 1, 2007, we owned 219 of our 321 retail propane customer service centers and leased the remaining centers. For more information concerning the location of our customer service centers see “Retail Propane” under Item 1. We lease our Kansas City, Missouri headquarters. We lease underground storage facilities with an aggregate capacity of approximately 52.2 million gallons of propane at nine 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, 2007, we owned the following:

•

approximately 1,300 bulk storage tanks at approximately 650 locations with typical capacities of 12,000 to 30,000 gallons,

•

approximately 630,000 stationary customer storage tanks with typical capacities of 100 to 1,200 gallons, and

•

approximately 155,000 portable propane cylinders with typical capacities of up to 35 gallons.

We believe that we have satisfactory title or valid rights to use all of our material properties. Although some of these properties are subject to liabilities and leases, liens for taxes not yet due and payable, encumbrances securing payment obligations under non-competition agreements entered in connection with acquisitions and immaterial encumbrances, easements and restrictions, we do not believe that any of these burdens will materially interfere with our continued use of these properties in our business, taken as a whole. Our obligations under our credit facility are secured by liens and mortgages on our real and personal property.

In addition, we believe that we have, or are in the process of obtaining, all required material approvals, authorizations, orders, licenses, permits, franchises and consents of, and have obtained or made all required material registrations, qualifications and filings with, the various state and local governmental and regulatory authorities that relate to ownership of our properties or the operation of our business.

Item 3. 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.

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, 2007.

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 Global Select National Market under the symbol “NRGY.” The following table sets forth the range of high and low bid prices of the common units, as reported by NASDAQ, as well as the amount of cash distributions declared per common unit for the periods indicated.


Quarters Ended:	Low		High		Cash Distribution Per Unit
Fiscal 2007:
September 30, 2007	$	28.53	$	38.17	$	0.595
June 30, 2007		32.44		38.09		0.585
March 31, 2007		28.01		32.99		0.575
December 31, 2006		26.63		30.49		0.565

Fiscal 2006:
September 30, 2006	$	25.60	$	28.00	$	0.555
June 30, 2006		24.84		27.55		0.545
March 31, 2006		25.49		27.80		0.540
December 31, 2005		25.00		29.20		0.530

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

As of November 19, 2007, our company had issued and outstanding 49,789,486 common units, which were held by approximately 32,711 unitholders of record.

Our company makes quarterly distributions to the partners within approximately 45 days after the end of each fiscal quarter in an aggregate amount equal to our available cash (as defined) for such quarter. Available cash generally means, with respect to each fiscal quarter, all cash on hand at the end of the quarter less the amount of cash that the managing general partner determines in its reasonable discretion is necessary or appropriate to:

•

provide for the proper conduct of our business,

•

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

•

provide funds for distributions to unitholders and to our non-managing general partner for any one or more of the next four quarters,

plus all cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter. Working capital borrowings are generally borrowings that are made under our working capital facility and in all cases are used solely for working capital purposes or to pay distributions to partners. The full definition of available cash is set forth in our partnership agreement (as amended), which is incorporated by reference herein as an exhibit to this report. For a discussion of restrictions on our ability to distribute cash, please see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

With the payment of the distribution on August 14, 2006 with respect to the quarter ended June 30, 2006, we met the necessary financial tests for the senior subordinated units and the junior subordinated units to convert to common units. Therefore, the remaining 3,821,884 senior subordinated units and 1,145,084 junior subordinated units were converted to common units on a one-for-one basis on August 14, 2006.

On March 23, 2006, our shelf registration statement (File No. 333-132287) was declared effective by the Securities and Exchange Commission for the periodic sale of up to $1.0 billion of common units, partnership securities and debt securities, or any combination thereof. Pursuant to the shelf registration statement, we are permitted to issue these securities from time to time for general business purposes, including debt repayment, future acquisitions, capital expenditures and working capital, or for other potential uses identified in a prospectus supplement. In June 2006 and February 2007, we issued 4,312,500 common units (which included 562,500 common units issued as result of the underwriters exercising their over-allotment provision) and 3,450,000 common units (which included 450,000 common units issued as result of the underwriters exercising their over-allotment provision), respectively. There is approximately $792.1 million remaining available under this shelf registration statement. No further partnership securities or debt securities have been offered under the shelf registration except as described above. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Sources of Capital” under Item 7.

The following table sets forth in tabular format, a summary of our company’s equity compensation plan information as of September 30, 2007:

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	330,500	$	20.25	3,865,160

Total	330,500	$	20.25	3,865,160

Item 6. Selected Financial Data.

The following table sets forth selected consolidated financial data and other operating data of Inergy, L.P. The selected historical consolidated financial data of Inergy, L.P. as of and for the years ended September 30, 2007, 2006, 2005, 2004 and 2003 are derived from the audited consolidated financial statements of Inergy, L.P and Inergy Partners, LLC. The historical consolidated financial data of Inergy, L.P. and Inergy Partners, LLC include the results of operations of its acquisitions from the effective date of the respective acquisitions.

“EBITDA” shown in the table below is defined as income before income taxes, plus net interest expense (inclusive of write-off of deferred financing costs) and depreciation and amortization expense. Adjusted EBITDA represents EBITDA excluding the non-cash gain or loss on certain derivative contracts, the gain or loss on sale of fixed assets and long-term incentive and equity compensation expenses. EBITDA and Adjusted EBITDA should not be considered an alternative to net income, income before income taxes, cash flows from operating activities, or any other measure of financial performance calculated in accordance with generally accepted accounting principles as those items are used to measure operating performance, liquidity or ability to service debt

obligations. We believe that EBITDA and Adjusted EBITDA provide additional information for evaluating our ability to make the minimum quarterly distribution and are presented solely as a supplemental measure. EBITDA and Adjusted EBITDA, as we define it, may not be comparable to EBITDA and Adjusted EBITDA or similarly titled measures used by other corporations or partnerships.

The data in the following 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. Years Ended September 30,
	2007			2006			2005			2004			2003
	(in millions, except per unit data)
Statement of Operations Data:
Revenues	$	1,483.1		$	1,390.2		$	1,051.9		$	483.2		$	363.7
Cost of product sold (excluding depreciation and amortization as shown below):		1,021.7			990.4			724.2			359.1			267.0

Gross profit		461.4			399.8			327.7			124.1			96.7
Expenses:
Operating and administrative		252.2			248.1			197.1			81.3			59.3
Depreciation and amortization		83.4			76.7			50.3			21.0			13.8
Loss on disposal of assets		8.0			11.5			0.7			0.2			0.1

Operating income		117.8			63.5			79.6			21.6			23.5
Other income (expense):
Interest expense, net		(52.0	)		(53.8	)		(34.2	)		(7.9	)		(10.0	)
Write-off of deferred financing costs		—			—			(7.0	)		(1.2	)		—
Make whole premium charge^(b)		—			—			—			(17.9	)		—
Swap value received		—			—			—			0.9			—
Other income		1.9			0.8			0.3			0.1			0.1

Income (loss) before income taxes		67.7			10.5			38.7			(4.4	)		13.6
Provision for income taxes		(0.7	)		(0.7	)		(0.1	)		(0.2	)		(0.1	)

Net income (loss)	$	67.0		$	9.8		$	38.6		$	(4.6	)	$	13.5

Net income (loss) per limited partner unit:
Basic	$	0.61		$	(0.20	)	$	0.98		$	(0.26	)	$	0.77

Diluted	$	0.61		$	(0.20	)	$	0.96		$	(0.26	)	$	0.76

Weighted average limited partners’ units outstanding:
Basic		47,693			41,407			31,143			22,027			16,676

Diluted		47,875			41,407			31,853			22,027			16,942

Cash distributions paid per unit	$	2.28		$	2.14		$	1.91		$	1.60		$	1.45


	2007			2006			2005			2004			2003
Balance Sheet Data (end of period):
Current assets	$	298.6		$	295.6		$	303.2		$	136.6		$	74.0
Total assets		1,744.4			1,639.0			1,502.2			503.8			362.4
Long-term debt, including current portion		710.2			659.7			559.7			137.6			131.1
Partners’ capital		741.2			676.1			663.9			252.0			179.0

Other Financial Data:
EBITDA (unaudited)	$	203.1		$	141.0		$	130.2		$	42.7		$	37.4
Net cash provided by operating activities		167.9			104.4			87.6			31.9			34.4
Net cash used in investing activities		(187.8	)		(210.9	)		(840.6	)		(98.1	)		(33.7	)
Net cash provided by financing activities		15.6			109.0			760.1			64.9			0.7
Maintenance capital expenditures^(a) (unaudited)		5.1			3.7			3.6			1.4			1.0

Other Operating Data (unaudited):
Retail propane gallons sold		362.2			360.3			318.4			140.7			119.7
Wholesale propane gallons delivered		383.9			365.3			391.3			368.3			284.7

Reconciliation of Net Income (Loss) to EBITDA and Adjusted EBITDA:
Net income (loss)	$	67.0		$	9.8		$	38.6		$	(4.6	)	$	13.5
Provision for income taxes		0.7			0.7			0.1			0.2			0.1
Interest expense, net		52.0			53.8			34.2			7.9			10.0
Write-off of deferred financing costs		—			—			7.0			1.2			—
Make whole premium charge^(b)		—			—			—			17.9			—
Swap value received		—			—			—			(0.9	)		—
Depreciation and amortization		83.4			76.7			50.3			21.0			13.8

EBITDA	$	203.1		$	141.0		$	130.2		$	42.7		$	37.4
Non-cash (gain) loss on derivative contracts		(0.6	)		20.0			(19.4	)		—			—
Loss on disposal of assets		8.0			11.5			0.7			0.2			0.1
Long-term incentive and equity compensation expense		0.7			2.9			—			—			—

Adjusted EBITDA	$	211.2		$	175.4		$	111.5		$	42.9		$	37.5

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

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

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. We also own and operate a growing midstream operation, including a high performance, multicycle natural gas storage facility (“Stagecoach”), an LPG storage facility and an NGL business in California, which includes natural gas processing, NGL fractionation, NGL rail and truck terminals, bulk storage, trucking and marketing operations. We further intend to pursue our growth objectives through, among other things, future acquisitions, maintaining a high percentage of retail sales to residential customers, operating in attractive markets and focusing our operations under established, and locally recognized trade names.

We have grown primarily through acquisitions. Since the inception of our predecessor in November 1996 through September 30, 2007, we have acquired 72 companies, 68 propane companies and 4 midstream businesses, for an aggregate purchase price of approximately $1.5 billion, including working capital, assumed liabilities and acquisition costs. During the fiscal year ended September 30, 2007, we made 11 retail acquisitions, including Columbus Butane Company, Inc., Hometown Propane, Inc., Quality Propane, Inc., Bay Cities Gas Corporation, Prince Oil Company, Inc., DeCock Bottled Gas & Appliance, Inc. and the propane assets of five other retail locations. We also acquired two midstream businesses: a natural gas liquids storage facility located near Bath, New York (the “Bath Storage Facility”), and the 24-mile lateral pipeline (“South Lateral Pipeline”) connecting our Stagecoach natural gas storage facility to Tennessee Gas Pipeline Company’s Line 300. The aggregate purchase price of these 13 acquisitions, net of cash acquired, was approximately $98.9 million. The purchase price allocation for these acquisitions has been prepared on a preliminary basis pending final asset valuation and asset rationalization, and changes are expected when additional information becomes available. Changes to final asset valuation of prior fiscal year acquisitions have been included in our consolidated financial statements but are not material.

For the fiscal year ended September 30, 2007, we sold approximately 362.2 million gallons of propane to retail customers and sold approximately 383.9 million gallons of propane to wholesale customers.

The results of operations discussed below are those of Inergy, L.P. Audited financial statements for Inergy, L.P. are included elsewhere in this Form 10-K.

The retail propane distribution business is largely seasonal due to propane’s primary use as a heating source in residential and commercial buildings. As a result, cash flows from operations are generally highest from November through April when customers pay for propane purchased during the six-month peak heating season of October through March. Our propane operations generally experience net losses in the six-month, off season of April through September.

Because a substantial portion of our propane is used in the weather-sensitive residential markets, the temperatures realized in our areas of operations, particularly during the six-month peak heating season, have a significant effect on our financial performance. In any given area, warmer-than-normal temperatures will tend to result in reduced propane use, while sustained colder-than-normal temperatures will tend to result in greater propane use. Therefore, we use information on normal temperatures in understanding how historical results of operations are affected by temperatures that are colder or warmer than normal and in preparing forecasts of future operations, which are based on the assumption that normal weather will prevail in each of our operating regions. “Heating degree days” are a general indicator of how weather impacts propane usage and are calculated for any given period by adding the difference between 65 degrees and the average temperature of each day in the period (if less than 65 degrees).

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 1977 through 2007. We then calculate weighted averages, based on retail volumes attributable to each measuring point, of actual and normal heating degree days within each region. Based on this information, we calculate a ratio of actual heating degree days to normal heating degree days, first on a regional basis consistent with our operational structure and then on a partnership-wide basis.

The retail propane business is a “margin-based” business where the level of profitability is largely dependent on the difference between sales prices and product 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 2006 and 2007, 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;

•

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, 2007 Compared to Fiscal Year Ended September 30, 2006

The following table summarizes the consolidated income statement components for the fiscal years ended September 30, 2007 and 2006, respectively (in millions):


	Year Ended September 30,						Change
	2007			2006			In Dollars			Percentage
Revenue	$	1,483.1		$	1,390.2		$	92.9		6.7	%
Cost of product sold		1,021.7			990.4			31.3		3.2

Gross profit		461.4			399.8			61.6		15.4
Operating and administrative expenses		252.2			248.1			4.1		1.7
Depreciation and amortization		83.4			76.7			6.7		8.7
Loss on disposal of assets		8.0			11.5			(3.5	)	(30.4	)

Operating income		117.8			63.5			54.3		85.5
Interest expense, net		(52.0	)		(53.8	)		1.8		3.3
Other income		1.9			0.8			1.1		137.5

Income before income taxes		67.7			10.5			57.2		544.8
Provision for income taxes		(0.7	)		(0.7	)		—		—

Net income	$	67.0		$	9.8		$	57.2		583.7	%

The following table summarizes revenues, including associated volume of gallons sold, for the years ended September 30, 2007 and 2006, respectively (in millions):


	Revenues								Gallons
	Year Ended September 30,				Change				Year Ended September 30,		Change
	2007		2006		In Dollars		Percent		2007	2006	In Units	Percent
Retail propane	$	733.2	$	701.1	$	32.1	4.6	%	362.2	360.3	1.9	0.5	%
Wholesale propane		417.2		371.2		46.0	12.4		383.9	365.3	18.6	5.1
Other retail		168.8		164.8		4.0	2.4		—	—	—	—
Storage, fractionation and midstream		163.9		153.1		10.8	7.1		—	—	—	—

Total	$	1,483.1	$	1,390.2	$	92.9	6.7	%	746.1	725.6	20.5	2.8	%

Volume. During fiscal 2007, we sold 362.2 million retail gallons of propane compared to 360.3 million retail gallons of propane during fiscal 2006. This 1.9 million gallon net increase was driven by retail propane acquisitions, which contributed an increase of approximately 19.7 million retail gallons during fiscal 2007, partially offset by a 17.8 million gallon decline in comparable sales volumes. The 17.8 million decrease in comparable retail gallons sold was due to several factors, including lower volumes resulting from the sale of certain branches during the fourth quarter of fiscal year 2006, expected volume losses from recent acquisitions and customer conservation arising from the increasing cost of propane. These factors that resulted in a decrease in comparable sales were partially offset by higher volumes related to the colder weather experienced during fiscal 2007. Although it was 7% warmer than normal during fiscal 2007, it was approximately 3% colder than fiscal 2006.

Wholesale gallons delivered increased 18.6 million gallons, or 5.1%, to 383.9 million gallons in fiscal 2007 from 365.3 million gallons in fiscal 2006. The increase was primarily attributable to increased sales volumes to new customers and increased sales volumes to existing customers.

The total natural gas liquid gallons sold or processed by our West Coast NGL operations increased 30.2 million gallons, or 18.9%, to 190.3 million gallons in fiscal 2007 from 160.1 million gallons in fiscal 2006. This increase was attributable to the addition of natural gas liquid marketing and processing contracts in fiscal 2007. Stagecoach had 13.25 bcf of working gas storage capacity for the first six months in fiscal 2007, 17.45 bcf of working gas storage capacity for the following five months and 26.25 bcf of working gas storage capacity during September 2007. Stagecoach had 13.25 bcf of working gas storage capacity throughout fiscal 2006. Stagecoach’s storage services were 100% contracted during each of the periods noted above.

Revenues. Revenues in fiscal 2007 were $1,483.1 million, an increase of approximately $92.9 million, or 6.7% from $1,390.2 million in fiscal 2006.

Revenues from retail propane sales were $733.2 million for the year ended September 30, 2007, an increase of $32.1 million, or 4.6%, compared to $701.1 million for the year ended September 30, 2006. These higher retail propane revenues were primarily the result of $39.0 million of acquisition-related sales and an increase of $27.7 million related to the higher average selling price of propane. Partially offsetting these increases in retail propane revenue was a $34.6 million decline resulting from lower volume sales at our existing locations as discussed above.

Revenues from wholesale propane sales were $417.2 million in fiscal 2007, an increase of $46.0 million or 12.4%, from $371.2 million in fiscal 2006. Approximately $27.1 million of this increase was attributable to the higher sales price of propane and the remaining $18.9 million attributable to higher sales volumes to new and existing customers. The higher selling price in our wholesale division in 2007 compared to 2006 is the result of the higher cost of propane.

Revenues from other retail sales, primarily distillates, service, rental, appliance sales and transportation services, were $168.8 million in fiscal 2007, an increase of $4.0 million, or 2.4% from $164.8 million in fiscal 2006. This increase was primarily related to $4.2 million of acquisition-related sales and a $2.1 million increase in transportation sales. These increases were partially offset by a $2.3 million decline related to other products and services, primarily appliances and rental sales.

Revenues from storage, fractionation and other midstream activities were $163.9 million in fiscal 2007, an increase of $10.8 million or 7.1% from $153.1 million in fiscal 2006. Approximately $13.9 million of this increase was due to the acquisition of the Bath LPG Storage Facility, the Stagecoach Phase II expansion placed into partial service in April 2007 and full service in September 2007, and increased contractual rates on the Stagecoach Storage Facility. In addition, revenues from our West Coast NGL operations were $4.4 million higher as a result of increased transportation and processing activities. Partially offsetting the above increases was a net $7.5 million decline in revenues due to expected changes in the variety of natural gas liquid products sold.

Cost of Product Sold. Retail propane cost of product sold was $419.3 million for the year ended September 30, 2007, a $1.1 million decrease as compared to $420.4 million for the year ended September 30, 2006. Retail propane cost of goods sold includes a $0.6 million non-cash gain and a $20.0 million non-cash charge for fiscal 2007 and 2006, respectively, arising from derivative contracts associated with retail propane fixed price contracts. Excluding the impact of these non-cash items, retail propane cost of goods sold increased approximately $19.5 million during fiscal 2007 as compared to fiscal 2006. This $19.5 million increase was driven by higher costs of $23.2 million associated with acquisitions and an increase of $16.0 million resulting from an approximate 4% higher average per gallon cost of propane. These factors, which increased retail propane cost of product sold, were partially offset by lower volume sales at our existing locations as discussed above, which reduced costs by $19.7 million.

Wholesale propane cost of product sold in fiscal 2007 was $400.7 million, an increase of $41.4 million or 11.5%, from wholesale cost of product sold of $359.3 million in 2006. Contributing to these higher costs was an approximate $23.1 million increase due to the higher average cost of propane and the remaining $18.3 million due to higher volumes sold to new and existing customers.

Other retail cost of product sold was $100.0 million for the year ended September 30, 2007, an increase of $0.4 million from $99.6 million for the year ended September 30, 2006. This increase was primarily due to cost of goods sold related to acquisitions of $0.9 million and a $1.5 million increase in transportation costs, partially offset by a $2.0 million decline in costs for other products and services, primarily appliances sales.

Storage, fractionation and other midstream cost of product sold was $101.7 million, a decrease of $9.4 million, or 8.5%, from $111.1 million in fiscal 2006. Of this $9.4 million decrease, $9.1 million was related to the lower cost of product sold associated with the expected changes in variety of natural gas liquid product sold. Additionally, a $1.9 million decrease was primarily attributable to lower transportation expense associated with the acquisition of the Stagecoach South Lateral. These decreases were partially offset by a $1.6 million increase from increased transportation and processing activities from our West Coast NGL operations.

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, delivery vehicle costs consisting of fuel costs, repair and maintenance and lease expense, and depreciation on tanks being rented to customers. Costs associated with delivery vehicles approximated $66.0 million and $62.4 million in 2007 and 2006, respectively. In addition, the depreciation expense associated with the delivery vehicles and customer tanks is reported within depreciation and amortization expense and amounted to $30.8 million and $30.7 million in 2007 and 2006, 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 $313.9 million in fiscal 2007 compared to $280.7 million in fiscal 2006. This $33.2 million, or 11.8%, increase was attributable to several factors, including a $15.8 million increase due to acquisitions and an $11.7 million increase related to a higher cash margin per gallon. The increase in cash margin per gallon was primarily the result of our ability to raise selling prices in certain markets in excess of the increased cost of propane. Also contributing to higher gross profit was the $20.6 million decrease in cost of product sold relating to the change in non-cash charges from derivative contracts associated with retail fixed price sales contracts. These factors that contributed to a higher gross profit were partially offset by a decline in retail gallon sales at existing locations as discussed above, resulting in a decrease in gross profit of $14.9 million.

Wholesale propane gross profit was $16.5 million in fiscal 2007 compared to $11.9 million in fiscal 2006, an increase of $4.6 million or 38.7%. Approximately $4.0 million of this increase was the result of a higher margin per gallon from our existing business and the remaining $0.6 million due to increased wholesale volumes from our new and existing business. The improved margin per gallon is primarily the result of a higher average selling price in excess of our increased cost of propane.

Other retail gross profit was $68.8 million for the year ended September 30, 2007 compared to $65.2 million for the year ended September 30, 2006. This $3.6 million, or 5.5%, increase was due primarily to acquisitions and higher transportation, distillate and rental sales, which together resulted in an increase to other retail gross profit of approximately $6.2 million. These increases were partially offset by a combined decrease in gross profit for appliance sales and other retail services of approximately $2.6 million.

Storage, fractionation and other midstream gross profit was $62.2 million in fiscal 2007 compared to $42.0 million in fiscal 2006, an increase of $20.2 million, or 48.1%. Approximately $15.8 million of this increase was due to the acquisition of the Bath LPG Storage Facility, the Stagecoach Phase II expansion placed into partial service in April 2007 and full service in September 2007, and increased contractual rates on the Stagecoach Storage Facility. Additionally, $4.4 million relates to increases in transportation, processing activities and natural gas liquids gross profit at our West Coast NGL operations.

Operating and Administrative Expenses. Operating and administrative expenses were $252.2 million in fiscal 2007 compared to $248.1 million in fiscal 2006. This $4.1 million increase in operating expenses was primarily the result of higher expenses of approximately $11.5 million arising from acquisitions, partially offset by lower expenses of approximately $5.1 million due to integration efficiencies and lower variable expenses as a result of lesser volumes sold at existing locations. Also partially offsetting the increase was a one-time charge in 2006 of $2.3 million for long-term incentive compensation related to the conversion of subordinated units to common units.

Depreciation and Amortization. Depreciation and amortization increased to $83.4 million in fiscal 2007 from $76.7 million in fiscal 2006, with the change primarily a result of acquisitions and the expansion of our midstream segment.

Loss on Disposal of Assets. Loss on sale of assets decreased to $8.0 million in fiscal 2007 compared to $11.5 million in fiscal 2006. The losses recognized in fiscal 2007 and 2006 include unrealized losses of approximately $6.2 million and $6.6 million, respectively, related to assets held for sale, which have been written down to their estimated selling price. In addition, we had realized losses in fiscal 2007 and 2006 of approximately $1.8 million and $4.9 million, respectively. These assets, both those sold and those held for sale, consist primarily of vehicles, tanks and real estate deemed to be excess, redundant or underperforming assets. These assets were identified primarily as a result of the integration of the larger retail propane acquisitions closed since November 2004 as we focused on eliminating duplicity in vehicles, operations, tanks and real estate.

Interest Expense. Interest expense decreased to $52.0 million in fiscal 2007 compared to $53.8 million in fiscal 2006. This $1.8 million decline resulted from $17.3 million in lower average debt outstanding and more capitalized interest during fiscal 2007 partially offset by a higher overall average interest rate in 2007 (7.73%) compared to 2006 (7.39%). During fiscal 2007 and 2006, we capitalized $3.1 million and $0.4 million, respectively, of interest related to certain capital improvement projects at our West Coast NGL and Stagecoach facilities as further described below in “Liquidity and Sources of Capital—Capital Resource Activities.”

Net Income. Net income for fiscal 2007 was $67.0 million, including a non-cash gain on derivative contracts of $0.6 million, compared to net income for fiscal 2006 of $9.8 million, including a non-cash loss on derivative contracts of $20.0 million. Excluding these non-cash items, net income for fiscal 2007 was $66.4 million compared to net income for fiscal 2006 of $29.8 million. The $36.6 million increase in net income is primarily attributable to higher gross profit, partially offset by increased operating and administrative expenses and non-cash expenses.

EBITDA and Adjusted EBITDA. The following table summarizes EBITDA and Adjusted EBITDA for the fiscal years ended September 30, 2007 and 2006, respectively (in millions):


	Year Ended September 30,
	2007			2006
EBITDA:
Net income	$	67.0		$	9.8
Interest expense, net		52.0			53.8
Provision for income taxes		0.7			0.7
Depreciation and amortization		83.4			76.7

EBITDA	$	203.1		$	141.0

Non-cash (gain) loss on derivative contracts		(0.6	)		20.0
Long-term incentive and equity compensation expense		0.7			2.9
Loss on disposal of assets		8.0			11.5

Adjusted EBITDA	$	211.2		$	175.4

EBITDA is defined as income before taxes, plus net interest expense (inclusive of write-off of deferred financing costs) and depreciation and amortization expense. For the years ended September 30, 2007 and 2006, EBITDA was $203.1 million and $141.0 million, respectively. This $62.1 million improvement in EBITDA was primarily attributable to net higher gross profit, which more than offset the increase in cash operating expenses in 2007. As indicated in the table, Adjusted EBITDA represents EBITDA excluding the gain or loss on derivative contracts associated with retail fixed price propane sales, the gain or loss on the disposal of assets and long-term incentive and equity compensation expenses (including conversion bonuses). Adjusted EBITDA was $211.2 million for fiscal 2007 compared to $175.4 million in fiscal 2006. EBITDA and Adjusted EBITDA should not be considered an alternative to net income, income before income taxes, cash flows from operating activities, or any other measure of financial performance calculated in accordance with generally accepted accounting principles as those items are used to measure operating performance, liquidity or the ability to service debt obligations. We believe that EBITDA and Adjusted EBITDA provide additional information for evaluating our ability to make the minimum quarterly distribution and are presented solely as supplemental measures. EBITDA and Adjusted EBITDA, as we define them, may not be comparable to EBITDA and Adjusted EBITDA or similarly titled measures used by other corporations or partnerships.

Fiscal Year Ended September 30, 2006 Compared to Fiscal Year Ended September 30, 2005

The following table summarizes the consolidated income statement components for the fiscal years ended September 30, 2006 and 2005, respectively (in millions):


	Year Ended September 30,						Change
	2006			2005			In Dollars			Percentage
Revenue	$	1,390.2		$	1,051.9		$	338.3		32.2	%
Cost of product sold		990.4			724.2			266.2		36.8

Gross profit		399.8			327.7			72.1		22.0
Operating and administrative expenses		248.1			197.1			51.0		25.9
Depreciation and amortization		76.7			50.3			26.4		52.5
Loss on disposal of assets		11.5			0.7			10.8		*

Operating income		63.5			79.6			(16.1	)	(20.2	)
Interest expense, net		(53.8	)		(34.2	)		(19.6	)	(57.3	)
Write-off of deferred financing costs		—			(7.0	)		7.0		100.0
Other income		0.8			0.3			0.5		166.7

Income before income taxes		10.5			38.7			(28.2	)	(72.9	)
Provision for income taxes		(0.7	)		(0.1	)		(0.6	)	*

Net income	$	9.8		$	38.6		$	(28.8	)	(74.6	)%

*	not meaningful

The following table summarizes revenues, including associated volume of gallons sold, for the years ended September 30, 2006 and 2005, respectively (in millions):


	Revenues								Gallons
	Year Ended September 30,				Change				Year Ended September 30,		Change
	2006		2005		In Dollars		Percent		2006	2005	In Units		Percent
Retail propane	$	701.1	$	526.5	$	174.6	33.2	%	360.3	318.4	41.9		13.2	%
Wholesale propane		371.2		325.1		46.1	14.2		365.3	391.3	(26.0	)	(6.6	)
Other retail		164.8		123.3		41.5	33.7		—	—	—		—
Storage, fractionation and midstream		153.1		77.0		76.1	98.8		—	—	—		—

Total	$	1,390.2	$	1,051.9	$	338.3	32.2	%	725.6	709.7	15.9		2.2	%

Volume. During fiscal 2006, we sold 360.3 million retail gallons of propane, an increase of 41.9 million gallons, or 13.2%, from the 318.4 million retail gallons sold in fiscal 2005. The increase in retail sales volume was principally due to the retail propane acquisitions, which combined resulted in a 99.9 million gallon increase. This increase was partially offset by an approximate 58.0 million gallon decline in comparable sales. We believe this is due primarily to a combination of warmer weather and conservation by our customers due to an approximate 19.4% higher propane cost per gallon in our retail operations in 2006 (excluding the $20.0 million non-cash loss on derivative contracts discussed below) to $1.11 per gallon compared with $0.93 per gallon in 2005 (excluding the $19.4 million non-cash gain on derivative contracts). 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 approximately 6% warmer in fiscal 2006 as compared to fiscal 2005 (and approximately 10% warmer than normal) in our retail areas of operations, we experienced erratic weather during the winter months of fiscal 2006 including the months of December 2005 and January 2006, which were approximately 9% colder and 26% warmer, respectively, than the previous year’s winter, while the month of March 2006 was 16% warmer than the month of March 2005.

Wholesale gallons delivered decreased 26.0 million gallons, or 6.6%, to 365.3 million gallons in fiscal 2006 from 391.3 million gallons in fiscal 2005. The decrease was primarily attributable to decreased sales volumes of approximately 32.5 million gallons to new and existing customers due to the warmer weather in 2006 in our wholesale areas of operations. This decrease was partially offset by an increase from acquisition-related volume, which accounted for 6.5 million gallons.

The total natural gas liquid gallons sold or processed by our West Coast NGL operations increased 10.2 million gallons, or 6.8%, to 160.1 million gallons in fiscal 2006 from 149.9 million gallons in fiscal 2005. This increase was attributable to the addition of natural gas liquid marketing and processing contracts in fiscal 2006. Stagecoach had 13.25 bcf of working gas storage capacity in fiscal 2006 and 2005 which was 100% contracted on average in fiscal 2006 and 85% contracted on average from the date of acquisition (August 9, 2005) to September 30, 2005.

Revenues. Revenues in fiscal 2006 were $1,390.2 million, an increase of approximately $338.3 million, or 32.2% from $1,051.9 million in fiscal 2005.

Revenues from retail propane sales were $701.1 million in fiscal 2006, an increase of $174.6 million, or 33.2%, from $526.5 million in fiscal 2005. This increase was primarily the result of $189.2 million of sales related to acquisitions together with an increase of approximately $92.9 million due to higher selling prices of propane due to the higher cost of propane in 2006. These increases were partially offset by a $107.5 million decline in revenues as a result of lower retail volume sales at our existing locations.

Revenues from wholesale propane sales were $371.2 million in fiscal 2006, an increase of $46.1 million or 14.2%, from $325.1 million in fiscal 2005. Approximately $72.6 million of this increase was attributable to the higher sales price of propane and approximately $6.9 million was attributable to acquisition-related volume. These increases were offset by a decrease of $33.4 million attributable to lower sales volumes to new and existing customers due primarily to warmer weather in the wholesale areas of operations. The higher selling price in our wholesale division in 2006 compared to 2005 is the result of the higher cost of propane.

Revenues from other retail sales, primarily service, appliance, transportation and distillates, were $164.8 million in fiscal 2006, an increase of $41.5 million or 33.7% from $123.3 million in fiscal 2005. This increase was primarily due to acquisitions, which contributed approximately $38.5 million of this increase.

Revenues from storage, fractionation and other midstream activities were $153.1 million in fiscal 2006, an increase of $76.1 million or 98.8% from $77.0 million in fiscal 2005. Approximately $37.8 million of this increase was due to increased volumes and sales price of natural gas liquids at our West Coast NGL operations,

approximately $36.0 million of this increase was due to the August 2005 acquisition of the Stagecoach natural gas storage facility and approximately $2.3 million of the increase was due to other changes in Stagecoach revenues and other changes at our West Coast NGL operations related to fractionation, transportation and terminaling revenues.

Cost of Product Sold. Retail propane cost of product sold in fiscal 2006 was $420.4 million, an increase of $145.8 million or 53.1%, from $274.6 million in fiscal 2005. Approximately $79.2 million of this increase was attributable to the approximate 19.4% per gallon higher average cost of propane in our retail division. Retail propane product costs included a non-cash derivative charge of $20.0 million in 2006 related to fixed price retail propane contracts whereas 2005 retail propane product cost was net of a $19.4 million non-cash derivative gain on those contracts. A net additional increase of approximately $111.3 million of retail propane product cost is a result of retail propane acquisition-related volume offset by a $64.7 million decrease due to lower volumes from existing locations.

Wholesale propane cost of product sold in fiscal 2006 was $359.3 million, an increase of $40.5 million or 12.7%, from wholesale cost of product sold of $318.8 million in 2005. Contributing to these higher costs was an approximate $66.1 million increase due to the higher average cost of propane and an approximate $7.1 million increase was a result of acquisition-related volume. These increases were partially offset by a $32.7 million decline due to lower volumes sold in our wholesale propane areas of operations.

Other cost of product was $99.6 million, an increase of $27.8 million, from other retail cost of product of $71.8 in fiscal 2005. Approximately $20.8 million of the increase was attributable to acquisitions and $7.0 million was attributable to other volume variances, primarily increased distillate costs.

Storage, fractionation and other midstream cost of product sold was $111.1 million, an increase of $52.1 million, or 88.3%, from $59.0 million in fiscal 2005. Approximately $36.6 million of this increase was due to higher volumes and cost of natural gas liquids at the West Coast NGL operations, approximately $13.9 million was due to the acquisition of the Stagecoach natural gas storage facility and approximately $1.6 million of the increase was due to other changes in Stagecoach cost of sales and other changes at our West Coast NGL operations cost of sales related to fractionation, transportation and terminaling revenues.

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, delivery vehicle costs consisting of fuel costs, repair and maintenance and lease expense, and depreciation on tanks being rented to customers. Costs associated with delivery vehicles approximated $62.4 million and $45.6 million in 2006 and 2005, respectively. In addition, the depreciation expense associated with the delivery vehicles is reported within depreciation and amortization expense and amounted to $15.3 million and $10.8 million in 2006 and 2005, respectively. Depreciation expense associated with tanks being rented to customers amounted to $15.4 million and $10.7 million in 2006 and 2005, 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 $280.7 million in fiscal 2006 compared to $251.9 million in fiscal 2005, an increase of $28.8 million, or 11.4%. Fiscal 2006 gross profit was negatively impacted by a $20.0 million non-cash derivatives charge while fiscal 2005 retail propane gross profit included a $19.4 million non-cash derivatives gain. Excluding these non-cash items, retail propane gross profit increased $68.2 million to $300.7 million in fiscal 2006 from $232.5 million in fiscal 2005. This $68.2 million increase was attributable to higher retail gallons sold as a result of acquisitions, which accounted for an increase of approximately $77.9 million, and improved gross profit per gallon which contributed approximately $32.6 million toward the increase. Both of these increases were partially offset by lesser retail gallon sales at existing locations resulting in a

decrease in gross profit of approximately $42.3 million. The decreased gallon sales are discussed above while 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 $11.9 million in fiscal 2006 compared to $6.3 million in fiscal 2005, an increase of $5.6 million or 88.9%. Approximately $6.4 million of this increase was the result of a higher margin per gallon from our existing business, partially offset by a $0.8 million decrease in wholesale volumes from our existing business. The improved 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.

Other retail gross profit was $65.2 million in fiscal 2006 compared to $51.5 million in fiscal 2005, an increase of $13.7 million, or 26.6%, due primarily to acquisition-related increases partially offset by lesser distillate volume sales and higher distillate costs, described above. In addition, decreases in service revenues and transportation revenues consistent with decreased retail propane volume sales contributed to this decrease in other retail gross profit.

Storage, fractionation and other midstream gross profit was $42.0 million in fiscal 2006 compared to $18.0 million in fiscal 2005, an increase of $24.0 million, or 133.3%. This increase was due primarily to the Stagecoach acquisition which accounted for $22.1 million of the increase. In addition, approximately $1.3 million of the increase was due to the increased volume and margin of natural gas liquids and an additional $0.6 million was due to other Stagecoach margins and other changes at our West Coast NGL operations margins related to fractionation, transportation and terminaling revenues.

Operating and Administrative Expenses. Operating and administrative expenses increased $51.0 million, or 25.9%, to $248.1 million in fiscal 2006 as compared to $197.1 million in fiscal 2005. Higher costs related to acquisitions, which accounted for approximately $59.5 million of this increase, were partially offset by an $8.5 million decline in operating expenses from our existing operations. The resulting net increases in our operating and administrative expenses related primarily to increases in personnel expenses of $28.0 million, general operating expenses of $14.5 million including insurance, professional services and facility costs, and increased vehicle costs of $8.5 million.

Depreciation and Amortization. Depreciation and amortization increased $26.4 million, or 52.5%, to $76.7 million in fiscal 2006 from $50.3 million in fiscal 2005 as a result of a higher asset base primarily due to our retail propane acquisitions.

Loss on Disposal of Assets. Loss on sale of assets increased to $11.5 million in fiscal 2006 compared to $0.7 million in fiscal 2005. The loss recognized in fiscal 2006 includes an unrealized loss of approximately $6.6 million related to assets held for sale at September 30, 2006, which have been written down to their estimated selling price, in addition to realized losses of approximately $4.9 million. These assets, both those sold and those held for sale, consist primarily of vehicles, tanks and real estate deemed to be excess, redundant or underperforming assets. These assets were identified as a result of the integration of the larger retail propane acquisitions closed since November 2004 as we focused on eliminating duplicity in vehicles, operations, tanks and real estate.

Interest Expense and Write-off of Deferred Financing Costs. Interest expense increased $19.6 million, or 57.3%, to $53.8 million in fiscal 2006 as compared to $34.2 million in fiscal 2005. Interest expense increased primarily due to an increase of $208.2 million in average debt outstanding in 2006 compared to 2005 primarily as a result of net borrowings for acquisitions, and an approximate 100 basis points higher average interest rate in 2006 (7.39%) compared to 2005 (6.39%). 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 a previously existing credit agreement and a 364-day facility.

Net Income (Loss). Net income for fiscal 2006 was $9.8 million, including a non-cash loss on derivative contracts of $20.0 million, compared to net income for fiscal 2005 of $38.6 million, including a non-cash gain on derivative contracts of $19.4 million. Excluding these non-cash items, net income for fiscal 2006 was $29.8 million compared to net income for fiscal 2005 of $19.2 million. The $10.6 million increase in net income is primarily attributable to higher gross profit, offset by increased operating and administrative expenses, non-cash expenses, interest expense and loss on disposal of assets, all discussed above.

EBITDA and Adjusted EBITDA. The following table summarizes EBITDA and Adjusted EBITDA for the fiscal years ended September 30, 2006 and 2005, respectively (in millions):


	Year Ended September 30,
	2006		2005
EBITDA:
Net income	$	9.8	$	38.6
Interest expense, net		53.8		34.2
Write-off of deferred financing costs		—		7.0
Provision for income taxes		0.7		0.1
Depreciation and amortization		76.7		50.3

EBITDA	$	141.0	$	130.2

Non-cash (gain) loss on derivative contracts		20.0		(19.4	)
Long-term incentive and equity compensation expense		2.9		—
Loss on disposal of assets		11.5		0.7

Adjusted EBITDA	$	175.4	$	111.5

EBITDA is defined as income before taxes, plus net interest expense (inclusive of write-off of deferred financing costs) and depreciation and amortization expense. For the years ended September 30, 2006 and 2005, EBITDA was $141.0 million and $130.2 million, respectively. This $10.8 million improvement in EBITDA was primarily attributable to net higher gross profit, which more than offset the increase in cash operating expenses in 2006. As indicated in the table, Adjusted EBITDA represents EBITDA excluding the gain or loss on derivative contracts associated with retail fixed price propane sales, the gain or loss on the disposal of assets and long-term incentive and equity compensation expenses (including conversion bonuses). Adjusted EBITDA was $175.4 million for fiscal 2006 compared to $111.5 million in fiscal 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 operating performance, liquidity or the 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 are presented solely as supplemental measures. EBITDA and Adjusted EBITDA, as we define them, may not be comparable to EBITDA and Adjusted EBITDA or similarly titled measures used by other corporations or partnerships.

Liquidity and Sources of Capital

Capital Resource Activities

common units issued as result of the underwriters exercising their over-allotment provision) and 3,450,000 common units (which included 450,000 common units issued as result of the underwriters exercising their over-allotment provision), respectively. There is approximately $792.1 million remaining available under this shelf registration statement. No further partnership securities or debt securities have been offered under the shelf registration except as described above.

We have identified growth projects related to our Stagecoach and West Coast NGL midstream businesses that are expected to require a total capital investment of approximately $268 million. Of the $268 million, we have invested approximately $90.7 million toward completion of these projects through September 30, 2007, primarily on the Stagecoach expansion. On September 1, 2007, the Phase II expansion project was placed into full commercial operation, which increased our total working gas capacity to 26.25 bcf from 13.25 bcf. The expanded facility is 100% contracted with long term firm storage contracts that commenced upon full commercial operation. Stagecoach is also expected to construct a pipeline to interconnect with the proposed Millennium Pipeline, which will enhance and further diversify our supply sources and provide interruptible wheeling services to the shipper community. The West Coast project consists of the construction of a butane isomerization unit and related ancillary facilities, as well as the expansion of butane storage capacity. The isomerization unit is projected to have a capacity of 10,000 barrels per day and provide isobutane supplies to refiners or wholesale distributors for gasoline blending. This project is subject to regulatory approval by state and county agencies and is expected to be in service by the fall of 2008.

Cash Flows and Contractual Obligations

Net operating cash inflows were $167.9 million and $104.4 million for fiscal years ending September 30, 2007 and 2006, respectively. The $63.5 million increase in operating cash flows was primarily attributable to increases in net income and net assets from price risk management activities, partially offset by a decrease in working capital balances.

Net investing cash outflows were $187.8 million and $210.9 million for the fiscal years ending September 30, 2007 and 2006, respectively. We funded acquisitions of $99.6 million in 2007 compared to $187.2 million in 2006, a decrease of $87.6 million. Additionally, deferred acquisition costs decreased $0.3 million in fiscal year 2007 compared to fiscal year 2006 and proceeds from sale of assets increased $1.6 million. These reductions in net investing cash outflows were partially offset by an increase of $66.4 million in capital expenditures.

Net financing cash inflows were $15.6 million and $109.0 million for the fiscal years ending September 30, 2007 and 2006, respectively. Net financing cash inflows were primarily impacted by $99.6 million and $187.2 million of acquisitions financed in 2007 and 2006, respectively. The lesser acquisitions financed in 2007 versus 2006 were the primary reason for a $46.2 million period to period decrease in proceeds from the issuance of long-term debt, net of payments on long-term debt, and a $22.9 million decrease in proceeds from the issuance of common units. Net financing cash outflows were also impacted by a $29.2 million period to period increase in distributions and a $5.0 million decrease in the payments for deferred financing costs.

At September 30, 2007 and 2006, we had goodwill of $347.2 million and $332.4 million, respectively, representing approximately 20% of total assets in each year. This goodwill is attributable to our acquisitions.

At September 30, 2007, we were in compliance with all debt covenants to our credit facilities.

The following table summarizes our contractual obligations as of September 30, 2007 (in millions):


	Total		Less than 1 year		1-3 years		4-5 years		After 5 years
Aggregate amount of principal and interest to be paid on the outstanding long-term debt ^(a)	$	1,089.9	$	78.1	$	109.9	$	151.4	$	750.5
Amount of principal and interest to be paid on other long-term obligations		8.8		3.5		5.3		—		—
Future minimum lease payments under noncancelable operating leases		23.1		6.7		9.0		4.4		3.0
Fixed price purchase commitments		292.4		291.8		0.6		—		—
Standby letters of credit		26.6		26.1		0.1		0.4		—
Purchase commitments of identified growth projects ^(b)		37.9		37.9		—		—		—

Total contractual obligations	$	1,478.7	$	444.1	$	124.9	$	156.2	$	753.5

^(a)

$196.0 million of our long-term debt, including interest rate swaps, is variable interest rate debt at prime rate or LIBOR plus an applicable spread. These rates plus their applicable spreads were between 7.0% and 7.2% at September 30, 2007. These rates have been applied for each period presented in the table.

^(b)	Identified growth projects related to the Stagecoach and West Coast NGL midstream assets.

We believe that anticipated cash from operations and borrowing capacity under our Credit Agreement described below will be sufficient to meet our liquidity needs for the foreseeable future. If our plans or assumptions change or are inaccurate, or we make acquisitions, we may need to raise additional capital.

Description of Credit Facility

On December 17, 2004, we 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 accrues interest at either prime rate or LIBOR plus applicable spreads, resulting in interest rates between 7.0% and 7.2% at September 30, 2007. At September 30, 2007, borrowings outstanding under the Credit Agreement were $71.0 million, including $40.0 million under the Acquisition Facility and $31.0 million under the Working Capital Facility. In October 2006, we amended the Credit Agreement with existing lenders primarily to increase the effective amount of working capital borrowing capacity available to us under the two facilities from $150 million to $200 million utilizing capacity under the acquisition credit facility for working capital needed during the winter heating season. Other terms, conditions, and covenants remained materially unchanged. The Credit Agreement is guaranteed by each of our domestic subsidiaries.

During each fiscal year beginning October 1, the outstanding balance of the Working Capital Facility must be reduced to $10.0 million or less for a minimum of 30 consecutive days during the period commencing March 1 and ending September 30 of each calendar year. We met this provision of our Credit Agreement on March 30, 2007.

At our option, loans under the Credit Agreement bear interest at either the prime rate or LIBOR (preadjusted for reserves), plus, in each case, an applicable margin. The applicable margin varies quarterly based on its leverage ratio. We also pay a fee based on the average daily unused commitments under the Credit Agreement.

We are required to use 50% of the net cash proceeds (that are not applied to purchase replacement assets) from asset dispositions (other than the sale of inventory and motor vehicles in the ordinary course of business, sales of assets among us and our domestic subsidiaries, and the sale or disposition of obsolete or worn-out equipment) to reduce borrowings under the Credit Agreement during any fiscal year in which unapplied net cash proceeds are in excess of $50 million. Any such mandatory prepayments are first applied to reduce borrowings under the Acquisition Facility and then under the Working Capital Facility.

In addition, the Credit Agreement contains various covenants limiting our ability to (subject to various exceptions), among other things:

•

grant or incur liens;

•

incur other indebtedness (other than permitted debt as defined in the Credit Agreement);

•

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;

•

enter into any debt (other than permitted junior debt) that contains covenants more restrictive than those of the Credit Agreement or enter into any permitted junior debt that contains negative covenants more restrictive than those of the Credit Agreement;

•

enter into hedge agreements that do not hedge or mitigate risks to which we have actual exposure;

•

enter into put agreements granting put rights with respect to equity interests of us or our subsidiaries;

•

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

•

modify organizational documents.

“Permitted junior debt” consists of:

•

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

•

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

•

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

•

other debt of ours and our subsidiaries that is either unsecured debt, or second lien debt that is subordinated to the obligations under the Credit Agreement.

Permitted junior debt may be incurred under the Credit Agreement so long as:

•

there is no default under the Credit Agreement;

•

the ratio of our total funded debt to consolidated EBITDA 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% and 8.25% senior notes and other substantially similar debt, the debt does not contain covenants more restrictive than those in the Credit Agreement.

The Credit Agreement contains the following financial covenants:

•

the ratio of our total funded debt (as defined in the Credit Agreement) to consolidated EBITDA (as defined in the Credit Agreement) for the four fiscal quarters most recently ended must be no greater than 5.25 to 1.0 for any period of two consecutive fiscal quarters immediately following an acquisition with a purchase price in excess of $100 million and 4.75 to 1.0 at all other times.

•

the ratio of our consolidated EBITDA to consolidated interest expense (as defined in the Credit Agreement), for the four fiscal quarters then most recently ended, must not be less than 2.5 to 1.0.

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

•

default in payment of principal when due;

•

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

•

violation of specified affirmative and negative covenants;

•

default in performance or observance of any term, covenant, condition or agreement contained in the Credit Agreement or any ancillary document related to the credit facility for 30 days;

•

specified cross-defaults;

•

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

•

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

•

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

•

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

•

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

Senior Unsecured Notes

2016 Senior Notes

On January 11, 2006, we and our wholly owned subsidiary, Inergy Finance Corp (“Finance Corp.” and together with us, the “Issuers”), issued $200 million aggregate principal amount of 8.25% senior unsecured notes due 2016 (the “2016 Senior Notes”) in a private placement to eligible purchasers.

The 2016 Senior Notes contain covenants similar to our existing senior unsecured notes due 2014. We used the net proceeds of the offering to repay outstanding indebtedness under our revolving acquisition credit facility. The 2016 Senior Notes represent senior unsecured obligations of ours and rank pari passu in right of payment with all other present and future senior indebtedness of ours. The 2016 Senior Notes are jointly and severally guaranteed by all of our current domestic subsidiaries and have certain call features which allow us to redeem the notes at specified prices based on date redeemed.

On May 18, 2006, we completed an offer to exchange our existing 8.25% 2016 Senior Notes for $200 million of 8.25% senior notes due 2016 (the “2016 Exchange Notes”) that are registered and do not carry transfer restrictions, registration rights and provisions for additional interest. The 2016 Exchange Notes did not provide us with any additional proceeds and satisfied our obligations under the registration rights agreement.

Before March 1, 2009, we may, at any time or from time to time, redeem up to 35% of the aggregate principal amount of the 2016 Senior Notes with the net proceeds of a public or private equity offering at 108.25% 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 150 days of the date of the closing of such equity offering.

The 2016 Senior Notes are redeemable, at our option, in whole or in part, at any time on or after March 1, 2011, in each case at the redemption prices described in the table below, together with any accrued and unpaid interest to the date of the redemption.


Year	Percentage
2011	104.125	%
2012	102.750	%
2013	101.375	%
2014 and thereafter	100.000	%

2014 Senior Notes

On December 22, 2004, we completed a private placement of $425 million in aggregate principal amount of our 6.875% senior unsecured notes due 2014 (the “2014 Senior Notes”). We used the net proceeds from the 2014 Senior Notes to repay all amounts drawn under a 364-day credit facility which was entered into in order to fund the acquisition of Star Gas and is no longer available to us, with the $39.9 million remaining balance of the net proceeds applied to the Acquisition Facility.

The 2014 Senior Notes represent senior unsecured obligations of ours and rank pari passu in right of payment with all other present and future senior indebtedness of ours. The 2014 Senior Notes are effectively subordinated to all of our secured indebtedness to the extent of the value of the assets securing the indebtedness and to all existing and future indebtedness and liabilities, including trade payables, of our non-guarantor subsidiaries. The 2014 Senior Notes rank senior in right of payment to all of our future subordinated indebtedness.

The 2014 Senior Notes are jointly and severally guaranteed by all of our 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 us). The subsidiaries guarantees rank senior in right of payment to all of our future subordinated indebtedness.

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

Before December 15, 2007, we may, at any time or from time to time, redeem up to 35% of the aggregate principal amount of the 2014 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 2014 Senior Notes are redeemable, at our option, in whole or in part, at any time on or after December 15, 2009, in each case at the redemption prices described in the table below, together with any accrued and unpaid interest to the date of the redemption.


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

Recent Accounting Pronouncements

SFAS No. 155, “Accounting for Certain Hybrid Financial Instruments” (“SFAS 155”) amends SFAS 133, and SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishment of Liabilities.” SFAS 155 permits fair value remeasurement for any hybrid financial instrument that contains an embedded derivative that otherwise would require bifurcation. It also establishes a requirement to evaluate securitized financial assets to identify interests that are freestanding derivatives or that are hybrid financial instruments that contain an embedded derivative requiring bifurcation. We adopted SFAS 155 for all financial instruments acquired or issued on or after October 1, 2006. We have evaluated the impact of SFAS 155 and determined that it does not have a material effect on our consolidated financial statements in the current year as well as all prior years considered.

Staff Accounting Bulletin No. 108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements” (“SAB 108”), provides guidance on the quantification of prior year misstatements. SAB 108 requires that registrants use both the income statement (roll-over) approach and the balance sheet (iron curtain) approach when evaluating the materiality of a misstatement and contains guidance for correcting the errors under this dual approach. SAB 108 was required to be adopted by us for the fiscal year ended September 30, 2007. We have evaluated the impact of this bulletin and determined that it does not have a material effect on our consolidated financial statements in the current year as well as all prior years considered.

SFAS No. 154, “Accounting Changes and Error Corrections” (“SFAS 154”) is a replacement of APB Opinion No. 20, “Accounting Changes,” and SFAS No. 3, “Reporting Accounting Changes in Interim Financial Statements.” SFAS 154 applies to all voluntary changes in accounting principle and changes the accounting for and a reporting of a change in accounting principle. SFAS 154 requires retrospective application to the prior periods’ financial statements of a voluntary change in accounting principle unless it is impracticable. SFAS 154 was required to be adopted by us for the fiscal year ended September 30, 2007. We have evaluated the impact of SFAS 154 and determined that it does not have a material effect on our consolidated financial statements in the current year as well as all prior years considered.

EITF Issue No. 06-3, “How Taxes Collected from Customers and Remitted to Governmental Authorities Should be Presented in the Income Statement (That Is, Gross Versus Net Presentation)” requires companies to disclose their policy regarding the presentation of tax receipts. The scope of this guidance includes any tax assessed by a governmental authority that is directly imposed on a revenue-producing transaction between a seller and a customer and may include, but is not limited to, sales, use, value added, and some excise taxes (gross receipts taxes are excluded). An entity is not required to reevaluate its existing policies related to taxes assessed by a governmental authority as a result of this consensus. In addition, for any such taxes that are reported on a gross basis, an entity should disclose the amounts of those taxes in interim and annual financial statements for each period for which an income statement is presented if those amounts are significant. We have adopted the consensus reached in this EITF for the fiscal year ended September 30, 2007. We have evaluated the impact of EITF 06-3 and determined that its impact is not material to our consolidated financial statements. Our accounting policy is to record taxes assessed by governmental authorities on a net basis.

SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS 159”) was issued in February 2007 to permit entities to choose to measure many financial instruments and certain other items at fair value at specified election dates. A business entity is required to report unrealized gains and losses on items for which the fair value option has been elected in earnings at each subsequent reporting date. SFAS 159 is required to be adopted by us for the fiscal year ended September 30, 2009. We are evaluating the potential financial statement impact of SFAS 159 to our consolidated financial statements.

expand disclosures about fair value measurements. SFAS 157 is required to be adopted by us for the fiscal year ended September 30, 2009. We are evaluating the potential financial statement impact of SFAS 157 to our consolidated financial statements.

FASB Interpretation No. 48 (“FIN 48”), “Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109” provides a recognition threshold and measurement attribute for the recognition and measurement of a tax position taken or expected to be taken in a tax return and also provides guidance on derecognition, classification, treatment of interest and penalties, and disclosure. FIN 48 is required to be adopted by us for the fiscal year ended September 30, 2008. We are evaluating the potential financial statement impact of FIN 48 to our consolidated financials statements.

Critical Accounting Policies

Accounting for Price Risk Management. We use certain derivative financial instruments to (i) manage our exposure to commodity price risk, specifically, the related change in the fair value of inventories, as well as the variability of cash flows related to forecasted transactions; (ii) to ensure adequate physical supply of propane and heating oil will be available; and (iii) manage our exposure to interest rate risk. We record all derivative instruments on the balance sheet as either assets or liabilities measured at estimated fair value 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, primarily resulting from variability in supply and demand, are recorded either through current earnings or as other comprehensive income, depending on the type of transaction.

On the date the derivative contract is entered into, we generally designate specific derivatives as either a hedge of the fair value of a recognized asset or liability (fair value hedge), or a hedge of a forecasted transaction (cash flow hedge). We document all relationships between hedging instruments and hedged items, as well as our risk-management objective and strategy for undertaking various hedge transactions. We use regression analysis or the dollar offset method to assess, both at the hedge’s inception and on an ongoing basis, whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in fair value or cash flows of hedged items. When it is determined that a derivative is not highly effective as a hedge or that is has ceased to be a highly effective hedge, we discontinue hedge accounting prospectively. When hedge accounting is discontinued because it is determined that the derivative no longer qualifies as an effective hedge, we continue to carry the derivative on the balance sheet at fair value, and recognize changes in the fair value of the derivative through current-period earnings.

We are party to certain commodity derivative financial instruments that are designated as hedges of selected inventory positions, and qualify as fair value hedges, as defined in SFAS 133. Our overall objective for entering into fair value hedges is to manage our exposure to fluctuations in commodity prices and changes in the fair market value of our inventories. These derivatives are recorded at fair value on the balance 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. Any ineffective portion of the fair value hedges is recognized as cost of product sold in the current period. We recognized a net gain of $0.1 million in the year ended September 30, 2007, related to the ineffective portion of our fair value hedging instruments. In addition, for the year ended September 30, 2007, we recognized a net gain of $1.0 million related to the portion of fair value hedging instruments that we excluded from our assessment of hedge effectiveness.

We also enter into derivative financial instruments that qualify as cash flow hedges, which hedge the exposure of variability in expected future cash flows predominantly attributable to forecasted purchases to supply fixed price sale contracts. These derivatives are recorded on the balance sheet at fair value as price risk management assets or liabilities. The effective portion of the gain or loss on these cash flow hedges is recorded in other comprehensive income in partner’s capital and reclassified into earnings in the same period in which the hedge

transaction affects earnings. Any ineffective portion of the gain or loss is recognized as cost of product sold in the current period. Accumulated other comprehensive income (loss) was $9.2 million and $(16.6) million at September 30, 2007 and 2006, respectively.

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 later of the time product is shipped or delivered to the customer. Gas processing and fractionation fees are recognized upon delivery of the product. Revenue from the sale of propane appliances and equipment is recognized at the later of the time of sale or installation. Revenue from repairs and maintenance is recognized upon completion of the service. Revenue from storage contracts is recognized during the period in which storage services are provided.

Impairment of Long-Lived Assets. 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, 2007.

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. The value of the assets to be disposed of is estimated at the date a commitment to dispose the asset is made.

Self-Insurance. We are insured by third parties, subject to varying retention levels of self-insurance, which management considers prudent. Such self-insurance relates to losses and liabilities primarily associated with medical claims, workers’ compensation claims, general, product and vehicle liability, and environmental exposures. Losses are accrued based upon management’s estimates of the aggregate liability for claims incurred using certain assumptions followed in the insurance industry and based on past experience. At September 30, 2007 and 2006, our self-insurance reserves were $13.2 million and $11.2 million, respectively.

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.

•

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

•

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

•

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

•

Due to our lack of asset diversification, adverse developments in our propane business would reduce our ability to make distributions to our unitholders.

See “Item 1A – “Risk Factors” for further discussion of factors that could impact our business.

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, 2007, we had floating rate obligations totaling approximately $196.0 million including amounts borrowed under our Credit Agreement and interest rate swaps, which convert fixed rate debt associated with the same amount of principal of our 2014 Senior Notes to floating, with aggregate notional amounts of $125 million. The floating rate obligations expose us to the risk of increased interest expense in the event of increases in short-term interest rates.

If the floating rate were to fluctuate by 100 basis points from September 2007 levels, our combined interest expense would change by a total of approximately $2.0 million per year.

Commodity Price, Market and Credit Risk

Inherent in our contractual portfolio are certain business risks, including market risk and credit risk. Market risk is the risk that the value of the portfolio will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by suppliers, customers or financial counterparties to a contract. We take an active role in managing and controlling market and credit risk and have established control procedures, which are reviewed on an ongoing basis. We monitor market risk through a variety of techniques, including daily reporting of the portfolio’s position to senior management. We attempt to minimize credit risk exposure through credit policies and periodic monitoring procedures as well as through customer deposits, letters of credit and entering into netting agreements that allow for offsetting counterparty receivable and payable balances for certain financial transactions, as deemed appropriate. The counterparties associated with assets from price risk management activities as of September 30, 2007 and 2006 were propane retailers, resellers, energy marketers and dealers.

The propane industry is a “margin-based” business in which gross profits depend on the excess of sales prices over supply costs. As a result, our profitability will be sensitive to changes in wholesale prices of propane caused by changes in supply or other market conditions. When there are sudden and sharp increases in the wholesale cost of propane, we may not be able to pass on these increases to our customers through retail or wholesale prices. Propane is a commodity and the price we pay for it can fluctuate significantly in response to supply or

other market conditions. We have no control over supply or market conditions. In addition, the timing of cost pass-throughs can significantly affect margins. Sudden and extended wholesale price increases could reduce our gross profits and could, if continued over an extended period of time, reduce demand by encouraging our retail customers to conserve or convert to alternative energy sources.

We engage in hedging and risk management transactions, including various types of forward contracts, options, swaps and futures contracts, to reduce the effect of price volatility on our product costs, protect the value of our inventory positions, and to help ensure the availability of propane during periods of short supply. We attempt to balance our contractual portfolio by purchasing volumes only when we have a matching purchase commitment from our wholesale customers. However, we may experience net unbalanced positions from time to time which we believe to be immaterial in amount. In addition to our ongoing policy to maintain a balanced position, for accounting purposes we are required, on an ongoing basis, to track and report the market value of our purchase obligations and our sales commitments.

Notional Amounts and Terms

The notional amounts and terms of these financial instruments include the following at September 30, 2007 and 2006 (in millions):


	September 30,
	2007		2006
	Fixed Price Payor	Fixed Price Receiver	Fixed Price Payor	Fixed Price Receiver
Propane, crude and heating oil (barrels)	5.0	4.8	8.0	7.5
Natural gas (MMBTU’s)	7.9	7.9	5.5	5.4

Notional amounts reflect the volume of transactions, but do not accurately measure our exposure to market or credit risks.

Fair Value

The fair value of the derivatives and inventory exchange contracts related to price risk management activities as of September 30, 2007 and September 30, 2006 was assets of $55.0 million and $46.2 million, respectively, and liabilities of $49.6 million and $49.0 million, respectively. All intercompany transactions have been appropriately eliminated.

The net change in unrealized gains and losses related to all price risk management activities, including wholesale inventory accounted for under a fair value hedge and deferred gains and losses accounted for under a cash flow hedge, for the years ended September 30, 2007, 2006 and 2005 of $23.9 million, $(39.5) million, and $24.1 million, respectively, are included in cost of product sold in the accompanying consolidated statements of operations or in Accumulated Other Comprehensive Income in the accompanying consolidated balance sheets. Included in the $23.9 million above is $9.9 million which is deferred in Accumulated Other Comprehensive Income, $16.6 million due to the reversal of the deferred Accumulated Other Comprehensive Income recorded in the year ended September 30, 2006, and changes in fair value of other price risk management activities. Included in the above $(39.5) million is $(19.4) million due to the reversal of the non-cash gain recorded in the year ended September 30, 2005, and changes in fair value of other price risk management activities, including $(16.6) million which is deferred in Accumulated Other Comprehensive Income at September 30, 2006. Included in the above $24.1 million is a non-cash gain of $19.4 million related to derivative contracts maturing in the following year and changes in fair value of other price risk management activities. 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, 2007 and 2006 where settlement has not yet occurred (in millions):


	Year Ended September 30,
	2007			2006
Net fair value gain (loss) of contracts outstanding at beginning of year	$	(2.8	)	$	8.8
Initial recorded value of new contracts entered into during the year		1.4			—
Net change in physical exchange contracts		(2.0	)		(0.6	)
Change in fair value of contracts attributable to market movement during the year		20.6			(4.4	)
Realized gains		(11.8	)		(6.6	)

Net fair value of contracts outstanding at end of year	$	5.4		$	(2.8	)

We use observable market values for determining the fair value of our trading instruments. In cases where actively quoted prices are not available, other external sources are used which incorporate information about commodity prices in actively quoted markets, quoted prices in less active markets and other market fundamental analysis. Our risk management department regularly compares valuations to independent sources and models.

Of the outstanding unrealized gain (loss) as of September 30, 2007 and 2006, $5.5 million and $(2.7) million have or will mature within 12 months, respectively. Contracts with a maturity of greater than one year were $(0.1) million at September 30, 2007 and 2006.

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 0.2 million gallons of net unbalanced positions at September 30, 2007.

Item 8. Financial Statements and Supplementary Data.

Reference is made to the financial statements and report of independent registered public accounting firm included later in this report under Item 15.

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.

None.

Item 9A. Controls and Procedures.

We maintain controls and procedures designed to provide a reasonable assurance that information required to be disclosed in our reports that we file or submit under the Securities Exchange Act of 1934 are recorded, processed, summarized and reported within the time periods specified by the rules and forms of the SEC, and that information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. An evaluation was performed under the supervision and with the participation of our management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as such terms are defined in Rule 13a-15(e) and 15d-15(e) of the Exchange Act). Based upon that evaluation, management, including the Chief Executive Officer and the Chief Financial Officer, concluded that our disclosure controls and procedures were effective as of September 30, 2007 at the reasonable assurance level. There have been no changes in our internal control over financial reporting (as

defined in Rule 13(a)-15(f) or Rule 15d-15(f) of the Exchange Act) or in other factors during the period ended September 30, 2007 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

Management’s Report on Internal Control Over Financial Reporting

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

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

Management’s assessment of and conclusion on the effectiveness of internal control over financial reporting did not include the operations resulting from the 13 acquisitions (collectively “the Acquisitions”) which were acquired during fiscal 2007 and are included in the 2007 consolidated financial statements. The financial reporting systems of the Acquisitions were integrated into the company’s financial reporting systems throughout 2007. 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 $98.5 million and $23.6 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, 2007. 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, 2007, our internal control over financial reporting is effective, in all material respects, based upon those criteria.

Our independent registered public accounting firm, Ernst & Young LLP, issued an attestation report dated November 26, 2007 on the effectiveness of our internal control over financial reporting, which is included herein.

Item 9B. Other Information.

None.

PART III

Item 10. Directors, Executive Officers and Corporate Governance.

Our Managing General Partner Manages Inergy, L.P.

Inergy GP, LLC, our managing general partner, manages our operations and activities. Our managing general partner is not elected by our unitholders and will not be subject to re-election on a regular basis in the future. Our managing general partner may not be removed unless that removal is approved by the vote of the holders of not less than 66²/3% of the outstanding units, including units held by the general partners and their affiliates, and we receive an opinion of counsel regarding limited liability and tax matters. Any removal of the managing general partner is also subject to the approval of a successor managing general partner by the vote of the holders of a majority of the outstanding common units. Unitholders do not directly or indirectly participate in our management or operation. Our managing general partner owes a fiduciary duty to the unitholders. Our managing general partner is liable, as a general partner, for all of our debts (to the extent not paid from our assets), except for specific nonrecourse indebtedness or other obligations. Whenever possible, our managing general partner intends to incur indebtedness or other obligations that are nonrecourse.

As is commonly the case with publicly-traded limited partnerships, we are managed and operated by the officers of our managing general partner and are subject to the oversight of the directors of our managing general partner. The board of directors of our managing general partner is presently composed of six directors.

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

Directors and Executive Officers

The following table sets forth certain information with respect to the executive officers and members of the board of directors of our managing general partner. Executive officers and directors will serve until their successors are duly appointed or elected.


Executive Officers and Directors	Age	Position with our Managing General Partner
John J. Sherman	52	President, Chief Executive Officer and Director

Phillip L. Elbert	49	President and Chief Operating Officer—Propane Operations

R. Brooks Sherman, Jr.	42	Executive Vice President and Chief Financial Officer

Carl A. Hughes	53	Senior Vice President—Business Development

Laura L. Ozenberger	49	Senior Vice President—General Counsel and Secretary

Andrew L. Atterbury	34	Senior Vice President—Corporate Development

Warren H. Gfeller	55	Director

Arthur B. Krause	66	Director

Robert A. Pascal	73	Director

Robert D. Taylor	60	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 President and Chief Operating Officer—Propane Operations since September 2007 and Executive Vice President—Propane Operations and director since March 2001. He joined our predecessor as Executive Vice President—Operations in connection with our acquisition of the Hoosier Propane Group in January 2001. Mr. Elbert joined the Hoosier Propane Group in 1992 and was responsible for overall operations, including Hoosier’s retail, wholesale and transportation divisions. From 1987 through 1992, he was employed by Ferrellgas, serving in a number of management positions relating to retail, transportation and supply. Prior to joining Ferrellgas, he was employed by Buckeye Gas Products, a large propane marketer from 1981 to 1987. He also serves as the President and Chief Operating Officer—Propane Operations of Inergy Holdings GP, LLC.

R. Brooks Sherman, Jr. Mr. Brooks Sherman, Jr. (no relation to Mr. John Sherman) has served as Executive Vice President since September 2007, Senior Vice President since September 2002 and Chief Financial Officer since March 2001. Mr. Sherman previously served as Vice President from March 2001 until September 2002. He joined our predecessor in December 2000 as Vice President and Chief Financial Officer. From 1999 until joining our predecessor, he served as Chief Financial Officer of MCM Capital Group. From 1996 through 1999, Mr. Sherman was employed by National Propane Partners, a publicly traded master limited partnership, first as its controller and chief accounting officer and subsequently as its chief financial officer. From 1995 to 1996, Mr. Sherman served as chief financial officer for Berthel Fisher & Co. Leasing Inc. and prior to 1995, Mr. Sherman was in public accounting with Ernst & Young and KPMG Peat Marwick. He also serves as Executive Vice President and Chief Financial Officer of Inergy Holdings GP, LLC.

Carl A. Hughes. Mr. Hughes has served as Senior Vice President of Business Development since September 2007 and Vice President of Business Development since March 2001. He joined our predecessor as Vice President of Business Development in 1998. From 1996 through 1998, he served as a regional manager for Dynegy Inc., responsible for propane activities in 17 midwestern and northeastern states. From 1993 through 1996, Mr. Hughes served as a regional marketing manager for LPG Services Group. From 1985 through 1992, Mr. Hughes was employed by Ferrellgas where he served in a variety of management positions.

Laura L. Ozenberger. Ms. Ozenberger has served as Senior Vice President—General Counsel since September 2007 and Vice President—General Counsel and Secretary since February 2003. From 1990 to 2003, Ms. Ozenberger worked for Sprint Corporation. While at Sprint, Ms. Ozenberger served in a number of management roles in the Legal and Finance departments. Prior to 1990, Ms. Ozenberger was in a private legal practice. She also serves as Senior Vice President—General Counsel and Secretary of Inergy Holdings GP, LLC.

Andrew L. Atterbury. Mr. Atterbury has served as Senior Vice President—Corporate Development since September 2007 and Vice President—Corporate Strategy since 2003. Prior to that, Mr. Atterbury served as the Director of Corporate Development from 2002 to 2003. From 1999 to 2001, Mr. Atterbury worked in the Corporate Development Group of Kinder Morgan, Inc. and Kinder Morgan G.P., Inc. From 1996 through 1998, Mr. Atterbury was employed by Lehman Brothers, Inc. in its Real Estate Finance Group.

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, has served as chief executive officer of Executive AirShare Corporation, an aircraft fractional ownership company, since November 2001. Mr. Taylor also served as president of Executive AirShare Corporation from November 2001 until November 2007. From August 1998 until September 2001, Mr. Taylor was president of Executive Aircraft Corporation, which sold, maintained and refurbished corporate jets. Mr. Taylor serves as a director of Blue Valley BanCorp. 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.

Independent Directors

Messrs. Gfeller, Krause and Taylor qualify as “independent” in accordance with the published listing requirements of the NASDAQ Global Select National Market. The NASDAQ independence definition includes a series of objective tests, such as that the director is not an employee of the company and has not engaged in various types of business dealings with the company. In addition, as further required by the NASDAQ rules, the board of directors has made a subjective determination as to each independent director that no relationships exist which, in the opinion of the board, would interfere with the exercise of independent judgment in carrying out the responsibilities of a director.

Board Committees

Audit Committee

The members of the audit committee must meet the independence standards established by the NASDAQ Global Select National Market. The members of the audit committee are 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 independent registered public accounting firm; and (c) the disclosure controls and procedures established by management.

Conflicts Committee

Our managing general partner may appoint two independent directors to serve on a conflicts committee to review specific matters which the board of directors believes may involve conflicts of interest. A conflicts committee will determine if the resolution of any conflict of interest submitted to it is fair and reasonable to us. In addition to satisfying certain other requirements, the members of the conflicts committee must meet the independence standards for service on an audit committee of a board of directors, which standards are established by the NASDAQ Global Select National Market. Any matters approved by the conflicts committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners, and not a breach by our managing general partner of any duties it may owe us or our unitholders.

Compensation Committee

Two members of the board of directors also serve on a compensation committee, which oversees compensation decisions for the officers of Inergy GP, LLC, as well as the compensation plans described below. The members of the compensation committee are Arthur B. Krause and Warren H. Gfeller.

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, 2007, all section 16(a) filing requirements applicable to our directors, executive officers and greater than 10% unitholders, were met.

Code of Ethics

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

Item 11. Executive Compensation.

Compensation Discussion and Analysis

Introduction

We do not directly employ any of the persons responsible for managing our business. Inergy GP, LLC, our managing general partner, manages our operations and activities, and its board of directors and officers make decisions on our behalf. The compensation of the directors and certain officers of our managing general partner is determined by the compensation committee of the board of directors of our managing general partner. Certain of our named executive officers also serve as executive officers of the general partner of Inergy Holdings, L.P. and the compensation of the named executive officers discussed below reflects total compensation for services to all Inergy entities. These “shared” officers receive no additional salary or cash compensation for their service to Inergy Holdings, L.P. However, as discussed in greater detail below, from time to time they do receive awards of equity in Inergy Holdings, L.P.

Compensation Philosophy and Objectives

We employ a compensation philosophy that emphasizes pay for performance. The primary measure of our performance is our ability to increase sustainable quarterly cash distributions to our unitholders and the related unitholder value realized. We believe that by tying a substantial portion of each named executive officer’s total compensation to financial performance metrics based on such distributions and unitholder value, our pay-for-performance approach aligns the interests of executive officers with that of our unitholders. Accordingly, the objectives of our total compensation program consist of:

•

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

•

balancing short and long-term performance;

•

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

•

attracting and retaining the best possible executive talent for the benefit of our unitholders.

By accomplishing these objectives, we hope to optimize long-term unitholder value.

Compensation Setting Process

Chief Executive Officer’s Role in the Compensation Setting Process

Our Chief Executive Officer plays a significant role in the compensation-setting process. The most significant aspects of his role are:

•

assisting in establishing business performance goals and objectives;

•

evaluating executive officer and company performance;

•

recommending compensation levels and awards for executive officers; and

•

implementing the approved compensation plans.

The Chief Executive Officer makes recommendations to the compensation committee with respect to financial metrics to be used for performance-based awards as well as other recommendations regarding non-CEO executive compensation, which may be based on our performance, individual performance and the peer group compensation market analysis. The compensation committee considers this information when establishing the total compensation package of the executive officers. The Chief Executive Officer’s performance and compensation is reviewed, evaluated and established separately by the compensation committee based on criteria similar to those used for non-CEO executive compensation.

Benchmarking

To evaluate total executive compensation, the compensation committee utilizes benchmarking data to assist in assessing executive compensation levels, including the individual base salary and incentive components. The data assembled included data from similar companies, as well as companies in the Kansas City region. We selected these “peer” companies because, like us, they are: (i) MLPs with significant propane operations, or (ii) MLPs with growing midstream operations. We chose the regional companies because they are public companies with which we compete for talent in the local employment market.


“Peer” MLP Companies		Regional Companies
Amerigas Partners, L.P.		Applebee’s International, Inc.

Copano Energy, LLC		Compass Minerals International, Inc.

Crosstex Energy, L.P.		DST Systems, Inc.

Energy Transfer Partners, L.P.		Layne Christensen Company

Ferrellgas Partners, L.P.		Kansas City Southern

Markwest Energy Partners, L.P.

Suburban Propane Partners, L.P.

The compensation committee utilizes the benchmarking data as a general guideline in making compensation-related decisions. However, we do not advocate a specific percentile relationship of actual pay to market pay as some companies do, e.g., we do not strive to be in the 50th percentile on actual pay. While our general objective for total compensation is at or above the median of the “peer” group data with a significant portion of total compensation at risk, the compensation committee has the full discretion to disregard the benchmarking data and target compensation at a different range.

In addition, the actual value delivered to any executive may be above or below that range depending upon our financial results, common unit price performance and the individual’s performance.

The compensation committee may in its discretion retain the services of a third-party compensation consultant, but did not retain any such consultants this fiscal year.

Elements of Compensation

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

•

base salary;

•

non-equity incentive (cash bonus) awards;

•

long-term incentive plan awards; and

•

retirement and health benefits.

Base Salary

Base salary is designed to compensate executives for the responsibility of the level of the position they hold and sustained individual performance (including experience, scope of responsibility, results achieved and future potential). The salaries of the named executive officers are reviewed on an annual basis, as well as at the time of promotion and other change in responsibilities or market conditions. The compensation committee uses benchmarking data as a general tool for setting compensation of the named executive officers as compared to the compensation of executives in similar positions with similar responsibility levels in our industry and in our region.

For the past two fiscal years, the named executive officers have received base annual salaries of $300,000, $200,000, $240,000, $175,000 and $175,000 for John J. Sherman, R. Brooks Sherman, Phillip L. Elbert, Laura L. Ozenberger and Carl A. Hughes, respectively. Based on the level of responsibility of the named executive officers, the sustained individual performance of the named executive officers, the financial results we have achieved and benchmarking data, the compensation committee determined that effective October 1, 2007, such salaries should be increased as follows: $350,000, $225,000, $275,000, $200,000 and $200,000 for John J. Sherman, R. Brooks Sherman, Phillip L. Elbert, Laura L. Ozenberger and Carl A. Hughes, respectively.

Non-Equity Incentive Awards (Cash Bonus Awards)

Non-equity incentive awards (cash bonus awards) are designed to reward the performance of key employees, including the named executive officers, by providing annual cash incentive opportunities for the partnership’s achievement of its annual financial performance goals. In particular, these bonus awards are provided to the named executive officers in order to provide competitive incentives to these executives who can significantly impact performance and promote achievement of the our short-term business objectives.

As in past years, the bonuses payable to the named executive officers in fiscal 2007 were based upon our achievement of three financial performance metrics: (i) earnings before income taxes, plus net interest expense, depreciation and amortization expense, further adjusted to exclude the non-cash gain or loss on certain derivative contracts, the gain or loss on sale of fixed assets and long-term incentive and equity compensation expense (“adjusted EBITDA”), (ii) distributable cash flow and (iii) growth in annualized distributions per unit. We have selected these metrics because we believe they closely align the focus of our named executive officers with the increase in unitholder value. In addition, these were the targets we communicated to our unitholders and analysts as guidance at the beginning of the 2007 fiscal year.

The financial performance targets are not weighted. Bonuses are paid to our named executive officers when we achieve or exceed the predetermined performance targets. With respect to the named executive officers, payouts are targeted to be 100% of a named executive officers’ base salary.

The following table summarizes the non-equity incentive award targets and our actual results for the fiscal year ended September 30, 2007 (in millions, except per unit data):


	Target		Actual
Adjusted EBITDA⁽¹⁾	$	194.0	$	211.1
Distributable cash flow	$	132.0	$	155.7
Annualized distribution per unit	$	2.33	$	2.38

⁽¹⁾

Adjusted EBITDA represents EBITDA excluding (1) non-cash gains or losses on derivative contracts associated with fixed price sales to retail propane customers, (2) long-term incentive and equity compensation charges, and (3) gains or losses on disposals of assets. For a reconciliation of EBITDA to Adjusted EBITDA please refer to page 35 of this annual report on Form 10-K.

As reflected in the table, we exceeded the targets for adjusted EBITDA, distributable cash flow and annualized distribution per unit by approximately 9%, 18% and $0.05, respectively. Accordingly, the compensation committee approved the short-term cash incentive awards for fiscal 2007 at 100% of base salary performance.

In addition, upon recommendation from the Chief Executive Officer, the compensation committee may make discretionary cash bonus awards to the named executive officers. The awards are designed to award outstanding individual performance in the fiscal year. In fiscal 2007, Laura L. Ozenberger was awarded a discretionary cash bonus of $25,000 for her leadership on certain critical projects.

Long-Term Incentive Plans

Long-term incentive awards for the named executive officers are granted under the Inergy Long Term Incentive Plan and Inergy Holdings Long Term Incentive Plan, in order to promote achievement of our primary long-term strategic business objective of increasing distributable cash flow and increasing unitholder value. These plans are designed to align the economic interests of key employees and directors with those of our common unitholders and the common unitholders of Inergy Holdings, L.P. and to provide an incentive to management for continuous employment with the managing general partner and its affiliates. Long-term incentive compensation is based upon the common units representing limited partnership interests in us or Inergy Holdings, L.P. and may consist of unit options, restricted units or phantom units.

We do not make systematic annual awards to the named executive officers. Generally, we believe that a two- to five-year grant cycle (and complete vesting over five years) provides a balance between a meaningful retention period for us and a visible, reachable reward for the executive officers. New awards are generally synchronized with the remaining time-vesting requirements of outstanding awards in a manner designed to encourage extended retention of the named executive officers.

Prior equity awards were made in fiscal 2002 and fiscal 2005. Accordingly, consistent with our general policy of granting equity awards on a two- to five-year cycle, no long-term incentive plan awards were granted to any of the named executive officers during the fiscal year ended September 30, 2007. However, on October 1, 2007 restricted units of Inergy Holdings, L.P. were awarded to R. Brooks Sherman (35,000), Phillip L. Elbert (50,000), Laura L. Ozenberger (25,000) and Carl A. Hughes (20,000) under the Inergy Holdings Long Term Incentive Plan. Due to John Sherman’s significant ownership in us and in Inergy Holdings, L.P., he has requested that he receive no awards of restricted units or options. As stated in the introduction, certain of our named executive officers also serve as executive officers of Inergy Holdings GP, LLC. When analyzing total compensation of the named executive officers, we take into account awards under the Inergy Holdings Long Term Incentive Plan.

Other Compensation Related Matters

Retirement and Health Benefits

We offer a variety of health and welfare and retirement programs to all eligible employees. The named executive officers are eligible for the same programs on the same basis as other employees. We maintain 401(k) retirement plan that provides eligible employees with an opportunity to save for retirement on a tax advantages basis. We match 50% of the first 6% of the deferral to the retirement plan (not to exceed the maximum amount permitted by law) made by eligible participants. Our executive officers are also eligible to participate in additional employee benefits available to our other employees.

Perquisites and Other Compensation

We do not provide perquisites or other personal benefits to any of the named executive officers.

Severance Benefits

We maintain employment agreements with all our named executive officers to ensure they will perform their roles for an extended period of time and not compete with us upon termination of employment. These agreements are described in more detail elsewhere in this Annual report. Please read “Narrative Disclosure to Summary Compensation Table and Grants of Plan-Based Awards Table—Employment Agreements.” These agreements do not provide any form of severance payment upon a change in control. However, the agreements do provide for continued salary payments following termination of employment without cause (as defined in the employment agreements). Thus, the continued salary provisions only become operative in the event of a change in control if such change in control is accompanied by a change in employment status (such as the termination of employment). We believe this arrangement is appropriate because it provides assurance to the executive, but does not offer a windfall to the executive when there has been no real change in employment status. In addition, both the Inergy Long Term Incentive Plan and Inergy Holdings Long Term Incentive Plan provide for accelerated vesting triggered upon a change of control.

Tax Deductibility of Compensation

With respect to the deduction limitations under Section 162(m) of the Code, we are a limited partnership and do not meet the definition of a “corporation” under Section 162(m). Nonetheless, the salaries for each of the named executive officers are substantially less than the Section 162(m) threshold of $1,000,000 and we believe the bonus compensation and long-term incentive compensation would qualify for performance-based compensation under Reg. 1.162-27(e) and therefore would not be additive to salaries for purposes of measuring the $1,000,000 tax limitation.

Compensation Committee Report

We have reviewed and discussed the foregoing Compensation Discussion and Analysis with management. Based on our review and discussion with management, we have recommended that the Compensation Discussion and Analysis be included in this Annual Report on Form 10-K for the year ended September 30, 2007.

Arthur B. Krause

Warren H. Gfeller

Members of the Compensation Committee

Summary Compensation Table

The following table sets forth the cash and non-cash compensation earned for the year ended September 30, 2007 by each person who served as the Chief Executive Officer, Chief Financial Officer and the three other highest paid executive officers (the “named executive officers”) during fiscal 2007.


Name and Principal Position	Fiscal Year	Salary ($)	Bonus ($)	Option Awards ($)⁽¹⁾	Non-Equity Incentive Plan Compensation ($)	All Other Compensation ($)⁽²⁾	Total ($)
John. J. Sherman President and Chief Executive Officer	2007	300,000	—	—	300,000	7,888	607,888

R. Brooks Sherman, Jr. Executive Vice President and Chief Financial Officer	2007	200,000	—	12,316	200,000	6,060	418,376

Phillip L. Elbert President and Chief Operating Officer—Propane Operations	2007	240,000	—	20,859	240,000	3,690	504,549

Laura L. Ozenberger Senior Vice President, General Counsel and Secretary	2007	175,000	25,000	16,225	175,000	5,944	397,169

Carl A. Hughes Senior Vice President—Business Development	2007	175,000	—	15,642	175,000	6,263	371,905

⁽¹⁾

The amounts included in the “Option Awards” columns reflect the dollar amount of compensation expense we recognized with respect to these awards for the fiscal year ended September 30, 2007, in accordance with SFAS 123(R) and thus include amounts attributable to awards granted in and prior to fiscal 2007. Assumptions used in the calculation of these amounts are discussed in Note 2 to our Consolidated Financial Statements. These amounts reflect our accounting expense for these awards, and do not correspond to the actual value that will be recognized by the named executive officers. The material terms of our outstanding LTIP awards to our executive officers are described in “Compensation Discussion and Analysis—Long-Term Incentive Plans.”

⁽²⁾

Consists of matching contributions to the partnership’s 401(k) Plan for each named executive officer and the partnership’s payment for the benefit of the named executive officers under the partnership’s group term life insurance policy The partnership does not provide perquisites and other personal benefits exceeding a total value of $10,000 to any named executive officer.

Grants of Plan Based Awards Table

The following table provides information concerning each grant of an award made to our named executive officers in the last completed fiscal year under any plan, including awards that have been transferred. No equity awards were granted to any of the named executive officers in fiscal 2007.


	Estimated Future Payouts Under Non-Equity Incentive Plan Awards
Name	Threshold ($)	Target ($)	Maximum ($)⁽¹⁾
John J. Sherman	0	300,000	300,000
R. Brooks Sherman, Jr.	0	200,000	200,000
Phillip L. Elbert	0	240,000	240,000
Laura L. Ozenberger	0	175,000	175,000
Carl A. Hughes	0	175,000	175,000

⁽¹⁾	The “Maximum” amount may be increased by the discretion of the Compensation Committee as described above in the “Compensation Discussion and Analysis – Non-equity Incentive Awards (Cash Bonus Awards).”

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

A discussion of fiscal 2007 salaries and bonuses is included above in “Compensation Discussion and Analysis.” The following is a discussion of other material factors necessary to an understanding of the information disclosed in the Summary Compensation Table.

Employment Agreements

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

•

John J. Sherman, President and Chief Executive Officer;

•

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

•

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

•

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

•

Carl A. Hughes, Senior Vice President—Business Development

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 material exceptions as set forth below. The employment agreements are for terms of approximately three or five years. During the fiscal year, the annual salaries for these individuals are as follows:

•

John J. Sherman—$300,000*

•

R. Brooks Sherman, Jr.—$200,000*

•

Phillip L. Elbert—$240,000*

•

Laura L. Ozenberger—$175,000*

•

Carl A. Hughes—$175,000*

*	Effective October 1, 2007 annual salaries were increased as follows: $350,000, $225,000, $275,000, $200,000 and $200,000 for John J. Sherman, R. Brooks Sherman, Phillip L. Elbert, Laura L. Ozenberger and Carl A. Hughes, respectively.

These employees are reimbursed for all expenses in accordance with the managing general partner’s policies. They are also eligible for fringe benefits normally provided to other employees.

All of the individuals are each eligible for annual performance bonuses (non-equity incentive plan awards) upon meeting certain established criteria for each year during the term of his or her employment.

Unless waived by the managing general partner, in order for any of these individuals to receive any benefits under (i) the Inergy Long Term Incentive Plan and the Inergy Holdings Long Term Incentive Plan, or (ii) the performance bonus, the individual must have been continuously employed by the managing general partner or one of our affiliates from the date of his or her employment agreement up to the date for determining eligibility to receive such amounts.

Each employment agreement contains confidentiality and noncompetition provisions. Also, each employment agreement contains a disclosure and assignment of inventions clause that requires the employee to disclose the existence of any invention and assign such employee’s right in such invention to the managing general partner.

With respect to each of the named executive officers, in the event such person’s employment is terminated without cause, we will be required to continue making payments to such person for the remainder of the term of such person’s employment agreement.

Inergy Long Term Incentive Plan

Our managing general partner sponsors the Inergy Long Term Incentive Plan for its directors, consultants and employees and the employees and consultants of its affiliates who perform services for us. The plan is administered by the compensation committee of the managing general partner’s board of directors. On September 11, 2007, the compensation committee approved an amendment to the Inergy Long Term Incentive Plan increasing the aggregate number of common units that may be issued under the plan from 1,735,100 to 5,000,000 and eliminated the limitation on the number of common units that may be issued pursuant to phantom unit awards.

Unit Options

The Inergy Long Term Incentive Plan currently permits, and our managing general partner has made, grants of options covering common units. Unit options will have an exercise price equal to the fair market value of the units on the date of grant. In general, unit options, as reflected in the table above, will become exercisable over a five-year period. In addition, the unit options will become exercisable upon a change of control of the managing general partner or us. The unit options will expire after 10 years.

Upon exercise of a unit option, our managing general partner will acquire common units in the open market, or directly from us or any other person, or use common units already owned by the managing general partner, or any combination of the foregoing. The managing general partner will be entitled to reimbursement by us for the difference between the cost incurred by the managing general partner in acquiring these common units and the proceeds received by the managing general partner from an optionee at the time of exercise. Thus, the cost of the unit options will be borne by us. If we issue new common units upon exercise of the unit options, the total number of common units outstanding will increase and the managing general partner will pay us the proceeds it received from the optionee upon exercise of the unit options. The unit option plan has been designed to furnish additional compensation to employees and directors and to align their economic interests with those of common unitholders.

Termination and Amendment

The managing general partner’s board of directors in its discretion may terminate the Inergy Long Term Incentive Plan at any time with respect to any common units for which a grant has not yet been made. The managing general partner’s board of directors also has the right to alter or amend Inergy Long Term Incentive Plan 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.

Inergy Holdings Long Term Incentive Plan

Inergy Holdings GP, LLC, the general partner of Inergy Holdings, L.P., sponsors the Inergy Holdings Long Term Incentive Plan for its directors, consultants and employees and the employees and consultants of its affiliates who perform services for us. The plan is administered by the compensation committee of the general partner’s board of directors.

Unit Options

The Inergy Holdings Long Term Incentive Plan currently permits, and its general partner has made, grants of options covering common units. Unit options will have an exercise price equal to the fair market value of the units on the date of grant. In general, unit options granted will become exercisable over a five-year period. In addition, the unit options will become exercisable upon a change of control of Inergy’s managing general partner or us. The unit options will expire after 10 years.

Upon exercise of a unit option, Holdings’ general partner will acquire common units in the open market, or directly from Holdings or any other person, or use common units already owned by the general partner, or any combination of the foregoing. The general partner will be entitled to reimbursement by Holdings for the difference between the cost incurred by the general partner in acquiring these common units and the proceeds received by the general partner from an optionee at the time of exercise. If Holdings’ issues new common units upon exercise of the unit options, the total number of common units outstanding will increase and the general partner will pay Holdings the proceeds it received from the optionee upon exercise of the unit options. The unit option plan has been designed to furnish additional compensation to employees and directors and to align their economic interests with those of common unitholders.

Termination and Amendment

The general partner’s board of directors in its discretion may terminate the Inergy Holdings Long Term Incentive Plan at any time with respect to any common units for which a grant has not yet been made. The general partner’s board of directors also has the right to alter or amend the Inergy Holdings 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.

Outstanding Equity Awards at Fiscal Year-End Table

The following table summarizes the options outstanding as of September 30, 2007 for the named executive officers. The table includes unit options of Inergy, L.P. (NASDAQ: NRGY) granted under the Inergy Long Term Incentive Plan and unit options of Inergy Holdings, L.P. (NASDAQ: NRGP) granted under the Inergy Holdings Long Term Incentive Plan. There were no equity awards to the named executive officers under either plan in the fiscal year ended September 30, 2007.


		Option Awards
		Number of Securities Underlying Unexercised Options (#)				Option Exercise Price ($)	Option Expiration Date
Name	Security	Exercisable		Unexercisable		Option Exercise Price ($)	Option Expiration Date
John J. Sherman		—		—		—	—
R. Brooks Sherman, Jr.	NRGY	20,000	⁽¹⁾	—		14.72	08/30/12
	NRGP	—		40,000	⁽³⁾	22.50	06/19/15
Phillip L. Elbert	NRGY	—		—		—	—
	NRGP	—		40,000	⁽⁴⁾	22.50	06/19/15
Laura L. Ozenberger	NRGY	—		50,000	⁽²⁾	15.70	02/09/13
	NRGP	—		40,000	⁽³⁾	22.50	06/19/15
Carl A. Hughes	NRGY	—		—		—	—
	NRGP	—		30,000	⁽⁴⁾	22.50	06/19/15

⁽¹⁾	Option vested in full on August 30, 2007 (5 years from the grant date).

⁽²⁾	Option will vest in full on February 10, 2008 (5 years from the grant date).

⁽³⁾	Option will vest as follows: 10,000 on June 20, 2008, 10,000 on June 20, 2009 and 20,000 June 20, 2010.

⁽⁴⁾	Option will vest in full on June 20, 2010 (5 years from the grant date).

Option Exercises and Stock Vested Table

The following table provides information regarding option exercises during the fiscal year ended September 30, 2007 for the named executive officers. No unit awards vested during the covered period.


		Option Awards
Name	Security	Number of Units Acquired On Exercise (#)	Value Realized on Exercise ($)
John J. Sherman		—	—
R. Brooks Sherman, Jr.		—	—
Phillip L. Elbert		—	—
Laura L. Ozenberger		—	—
Carl A. Hughes	NRGY	77,700	1,290,597

Pension Benefits Table

We do not offer any pension benefits.

Nonqualified Deferred Compensation Table

We have no non-qualified deferred compensation plans.

Potential Payments upon a Change in Control or Termination

Employment Agreements

Under the employment agreements with our named executive officers, we may be required to pay certain amounts upon the employment termination of the named executive officer in certain circumstances. Upon the termination of employment of a named executive officer without Cause, the employment agreements entered into between Inergy GP, LLC and each of the named executive officers provide for salary continuation at the rate in effect at termination of the employee through the remaining term of the employment agreement. Consequently, no severance is payable in the event of any termination (i) as a result of death, disability, or legal incompetence, (ii) as a result of Inergy GP, LLC ceasing to carry on its business without assigning the employment agreement, (iii) as a result of Inergy GP, LLC becoming bankrupt, (iv) for Cause or (v) by the employee for any or no reason. For purposes of the employment agreements:

Cause will generally be determined to have occurred in the event the:

•

employee has failed to perform his or her duties as an employee of Inergy GP, LLC, to perform any obligation under the employment agreement or to observe and abide by Inergy GP, LLC’s policies and decisions, provided that Inergy GP, LLC has given employee reasonable notice of that failure and employee is unsuccessful in correcting that failure or in preventing its reoccurrence;

•

employee has refused to comply with specific directions of his/her supervisor or other superior, provided that such directions are consistent with the employee’s position of employment;

•

employee has engaged in misconduct that is injurious to Inergy GP, LLC or any subsidiary, parent or affiliate of Inergy GP, LLC;

•

employee has been convicted of, or has entered a plea of nolo contendere to, any crime involving the theft or willful destruction of money or other property, any crime involving moral turpitude or fraud, or any crime constituting a felony;

•

employee has engaged in acts or omissions against Inergy GP, LLC or any subsidiary, parent or affiliate of Inergy GP, LLC constituting dishonesty, breach of fiduciary obligation, or intentional wrongdoing or misfeasance; or

•

employee has used alcohol or drugs on the job, or has engaged in excessive absenteeism from the performance of his duties as Inergy GP, LLC’s employee, other than for reasons of illness.

If a termination of a named executive officer by Inergy GP, LLC without Cause were to have occurred as of September 30, 2007, our named executive officers would have been entitled to the following:

•

John J. Sherman would have received $875,000, representing base salary for the remaining 35 months of the term of his employment agreement (payable bi-monthly in arrears). For two years following the termination of Mr. Sherman’s employment he will continue to be subject to the non-competition provisions of his employment agreement.

•

R. Brooks Sherman, Jr. would have received $550,000, representing base salary for the remaining 33 months of the term of his employment agreement (payable bi-monthly in arrears). For two years following termination of Mr. Sherman’s employment he will continue to be subject to the non-competition provisions of his employment agreement.

•

Phillip L. Elbert would have received $540,000, representing base salary for the remaining 27 months of the term of his employment agreement (payable bi-monthly in arrears). In addition, to receiving severance payments upon a termination of employment without Cause, Mr. Elbert is entitled to the same benefits if he terminates his employment for “Good Reason” which is defined as (i) Inergy GP, LLC requiring, as a condition of employee’s employment, that employee commit a felony or engage in conduct that is a crime under the Securities Act of 1933, as amended, or the Securities Exchange Act of 1934, as amended; and (ii) employee being required by Inergy GP, LLC to be based at any office or location that is more than 35 miles from the location where employee was employed immediately preceding the date of the voluntary or involuntary termination of employee’s employment. For up to two years following termination of Mr. Elbert’s employment he will continue to be subject to the non-competition provisions of his employment agreement.

•

Laura L. Ozenberger would have received $160,417 representing base salary for the remaining 11 months of the term of her employment agreement (payable bi-monthly in arrears). Effective October 1, 2007, Ms. Ozenberger and Inergy GP, LLC entered into a new Employment Agreement with a three year term with an annual base salary of $200,000. A three year severance benefit at Ms. Ozenberger’s base salary in effect as of September 30, 2007, would equal $525,000. For two years following termination of employment Ms. Ozenberger will continue to be subject to the non-competition provisions of her employment agreement.

•

Carl A. Hughes would have received $510,417, representing base salary for the remaining 37 months of the term of his employment agreement (payable bi-monthly in arrears). ). For two years following termination of Mr. Hughes’ employment he will continue to be subject to the non-competition provisions of his employment agreement.

Inergy Long Term Incentive Plan and Inergy Holdings Long Term Incentive Plan

Upon a change in control, all unit options and restricted units shall automatically vest and become payable or exercisable, as the case may be, in full and any restricted periods or performance criteria shall terminate or be deemed to have been achieved at the maximum level. For purposes of the Inergy Long Term Incentive Plan and Inergy Holdings Long Term Incentive Plan, a “change in control” means, and shall be deemed to have occurred upon one of the following events: (i) any sale, lease, exchange or other transfer (in one or a series of related transactions) of all or substantially all of the assets of the Inergy Partners, LLC or Inergy, L.P. to any person or its affiliates, other than Inergy GP, LLC, the Partnership or any of their affiliates, or (ii) any merger, reorganization, consolidation or other transaction pursuant to which more than 50% of the combined voting power of the equity interests in Inergy GP, LLC or Inergy Partners, LLC ceases to be controlled by Inergy Holdings, L.P.

If a change in control were to have occurred as of September 30, 2007, all awards held by the named executive officers under the Inergy Long Term Incentive Plan as well as the Inergy Holdings Long Term Incentive Plan would have automatically vested and become exercisable, as follows:


Name	Option Awards under the Inergy Long Term Incentive Plan	Exercise Price Per Share under the Long Term Incentive Plan ($)	Option Awards under the Inergy Holdings Long Term Incentive Plan	Exercise Price Per Share under the Holdings Long Term Incentive Plan ($)	Total ($)⁽¹⁾
John J. Sherman	—	—	—	—	0
R. Brooks Sherman, Jr.	—	—	40,000	22.50	987,200
Phillip L. Elbert	—	—	40,000	22.50	987,200
Laura L. Ozenberger	50,000	15.70	40,000	22.50	1,755,700
Carl A. Hughes	—	—	30,000	22.50	740,400

⁽¹⁾

Amounts included in the “Total” column are calculated by subtracting the per share exercise price under the options from the closing per share price of our common units on September 28, 2007 ($31.07) or the closing per share price of the common units of Holdings ($47.18), as applicable, and multiplying the difference by the number of units subject to the option.

Director Compensation Table

The following table sets forth the cash and non-cash compensation earned for the year ended September 30, 2007 by each person who served as a non-employee director of Inergy GP, LLC.


Name	Fees Earned or Paid in Cash ($)	Unit Awards ($)^(1),(2)	Option Awards ($)⁽¹⁾	All Other Compensation ($)⁽³⁾	Total ($)
Warren H. Gfeller	41,000	12,443	—	2,132	55,575
Arthur B. Krause	38,000	12,443	7,324	2,132	59,899
Robert A. Pascal	26,000	12,443	—	2,132	40,575
Robert D. Taylor	34,000	12,443	2,579	2,132	51,154

⁽¹⁾

The amounts included in the “Unit Awards” and “Option Awards” columns reflect the dollar amount of compensation expense we recognized with respect to these awards for the fiscal year ended September 30, 2007, in accordance with SFAS 123(R) and thus include amounts attributable to awards granted in and prior to fiscal 2007. Assumptions used in the calculation of these amounts are discussed in Note 2 to our Consolidated Financial Statements. These amounts reflect our accounting expense for these awards, and do not correspond to the actual value that will be recognized by the directors.

⁽²⁾	As of September 30, 2007, Messrs. Gfeller, Krause, Pascal and Taylor each owned 1,381 restricted units and Messrs. Krause and Taylor each owned 20,000 unit options.

⁽³⁾	Dollar value of distributions paid on restricted units during the fiscal year ended September 30, 2007.

Compensation of Directors

Officers of our managing general partner who also serve as directors will not receive additional compensation. Each director receives cash compensation of $25,000 per year for attending our regularly scheduled quarterly board meetings. Each non-employee director receives $1,000 for each special meeting of the board of directors attended and $1,000 per compensation, audit, or conflicts committee meeting attended. The chairman of the audit committee receives an annual fee of $5,000 per year and the chairman of the compensation committee receives an annual fee of $1,000 per year. Furthermore, each non-employee director receives an annual grant of restricted units under the long-term incentive plan equal to $25,000 in value.

On April 2, 2007, Messrs. Gfeller, Krause, Taylor and Pascal each received 755 restricted units under the Inergy Long Term Incentive Plan. These units vest ratably over three years beginning one year from the grant date. Each non-employee director is reimbursed for out-of-pocket expenses in connection with attending meetings of the board of directors or committees. Each director is fully indemnified for actions associated with being a director to

the extent permitted under Delaware law. Messrs. Gfeller and Krause also receive compensation for their services on the board of directors of Inergy Holdings GP, LLC, which is not reflected in the table above.

Compensation Committee Interlocks and Insider Participation

The compensation committee of the board of directors of our managing general partner oversees the compensation of our executive officers. 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 2007.

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, 2007, 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 executive officers of our managing general partner,

•

each of the directors of our managing general partner, and

•

all of the directors and 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.


Name of Beneficial Owner ⁽¹⁾	Common Units Beneficially Owned	Percentage of Common Units Beneficially Owned		Percentage of Total Limited Partner Units Beneficially Owned

Inergy Holdings, L.P.⁽²⁾	4,706,689	9.5	%	9.5	%

Bonavita, Inc. (fka United Propane, Inc.)^(3) (7) 28 Floral Avenue Key West, FL 33040	1,954,987	3.9	%	3.9	%

Kayne Anderson MLP Investment Company⁽⁴⁾ 1800 Avenue of the Stars, 2^nd FL Los Angeles, CA 90067	3,704,596	7.4	%	7.4	%

John J. Sherman⁽⁵⁾	4,795,984	9.6	%	9.6	%

Phillip L. Elbert	—	—		—

R. Brooks Sherman, Jr.	3,320	*		*

Carl A. Hughes	80,648	0.2	%	0.2	%

Laura L. Ozenberger	3,954	*		*

Arthur B. Krause⁽⁷⁾	24,194	*		*

Robert A. Pascal^(3) (7)	1,956,681	3.9	%	3.9	%

Warren H. Gfeller^(6) (7)	58,822	0.1	%	0.1	%

Robert D. Taylor⁽⁷⁾	13,449	*		*

All directors and executive officers as a group (10 persons)	6,937,052	13.9	%	13.9	%

*	less than 1%

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

⁽²⁾	Of the common units indicated as beneficially owned by Inergy Holdings, 2,837,034 units are held by Inergy Partners, LLC, 789,202 units are held by IPCH Acquisition Corp., both wholly-owned subsidiaries of Inergy Holdings, and 1,080,453 units are held directly by Inergy Holdings.

⁽³⁾

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

⁽⁴⁾	Information as to the number of common units is furnished in reliance upon the Schedule 13G’s of the corresponding entities or individuals.

⁽⁵⁾

Mr. Sherman holds an ownership interest in Inergy Holdings through the John J. Sherman Revocable Trust and the John J. Sherman 2005 Grantor Retained Annuity Trust and has voting control. As trustee of the John J. Sherman Revocable Trust, Mr. John Sherman may be deemed to own 4,706,689 common units. Of these units 789,202 are held by IPCH Acquisition Corp., a wholly-owned subsidiary of Inergy Holdings L.P. (formerly Inergy Holdings, LLC.), 2,837,034 units are held by Inergy Partners, LLC, of which Inergy Holdings L.P. (formerly Inergy Holdings, LLC) has 100% voting control, 1,080,453 common units are held by Inergy Holdings, L.P. (formerly Inergy Holdings, LLC.). Mr. Sherman disclaims beneficial ownership of the reported securities except to the extent of his pecuniary interest. The remaining 89,295 common units are held by the John J. Sherman Revocable Trust or by John J. Sherman though the Inergy, L.P. EUPP.

⁽⁶⁾	Mr. Gfeller in his capacity as managing member of Clayton-Hamilton, LLC may be deemed to beneficially own 12,728 common units held by Clayton-Hamilton.

⁽⁷⁾	Includes 1,381 restricted units granted under the Inergy, L.P. Long Term Incentive Plan, as amended. The restricted units vest at a rate of 33.33% on each anniversary of the grant date.

The following table shows the beneficial ownership as of November 1, 2007 of Inergy Holdings, L.P. of the directors and executive officers of our managing general partner, the directors and executive officers of the general partner of Inergy Holdings, L.P., and each person who beneficially owned more than 5% of such units outstanding. As reflected above, Inergy Holdings owns our managing general partner, non-managing general partner, incentive distribution rights and, through subsidiaries, approximately 9.5% of our outstanding limited partner units.

As of September 30, 2007, no units were pledged by directors or named executive officers.


Name of Beneficial Owner⁽¹⁾	Inergy Holdings, L.P. Percent of Class
John J. Sherman⁽²⁾	39.25	%
David G. Dehaemers, Jr.	5.05	%
Phillip L. Elbert⁽³⁾	4.48	%
William C. Gautreaux⁽⁴⁾	5.31	%
Andrew L. Atterbury	5.34	%
Carl A. Hughes⁽⁵⁾	4.73	%
R. Brooks Sherman Jr.	1.97	%
Laura L. Ozenberger	*
Warren H. Gfeller	*
Arthur B. Krause	*
Richard T. O’Brien	—
Robert A. Pascal	*
Robert D. Taylor	—
All directors and executive officers as a group (11 persons)	56.04	%

*	Less than 1%

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

⁽²⁾

Mr. Sherman may be deemed to beneficially own (i) the 7,681,431 common units held by the John J. Sherman Revocable Trust dated May 4, 1994, of which Mr. Sherman serves as the trustee, (ii) the 249,395 common units held by the John J. Sherman 2005 Grantor Retained Annuity Trust I under trust indenture dated March 31, 2005, of which Mr. Sherman serves as co-trustee, and (iii) Mr. Sherman holds 655 units through the Employee Unit Purchase Plan.

⁽³⁾

Mr. Elbert may be deemed to beneficially own (i) 694,831 common units held by the Philip L. Elbert Revocable Trust dated May 17, 2001 of which Mr. Elbert is the trustee, (ii) the 120,675 common units held by the Phillip L. Elbert 2005 Grantor Retained Annuity Trust under trust indenture dated March 31, 2005, of which Mr. Elbert serves as co-trustee, (iii) the 20,113 common units held by the Charles W. Elbert Trust under trust indenture dated March 31, 2005, of which Mr. Elbert serves as co-trustee, and (iv) the 20,113 common units held by the Lauren E. Elbert Trust under trust indenture dated March 31, 2005, of which Mr. Elbert serves as co-trustee.

⁽⁴⁾

Mr. Gautreaux may be deemed to beneficially own (i) the 843,796 common units held by the William C. Gautreaux Revocable Trust dated March 8, 2004, of which Mr. Gautreaux serves as the trustee, and (ii) the 120,675 common units held by the William C. Gautreaux 2005 Grantor Retained Annuity Trust under trust indenture dated March 31, 2005, of which Mr. Gautreaux serves as co-trustee.

⁽⁵⁾

Mr. Hughes may be deemed to beneficially own (i) the 695,442 common units held by the Carl A. Hughes Revocable Trust dated September 13, 2002, of which Mr. Hughes serves as the trustee, and (ii) the 241,350 common units held by the Carl A. Hughes 2005 Grantor Retained Annuity Trust under trust indenture dated March 31, 2005, of which Mr. Hughes serves as co-trustee.

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

Item 13. Certain Relationships, Related Transactions and Director Independence.

Related Party Transactions

In connection with our acquisition of assets from United Propane, Inc. on July 31, 2003, we entered into ten leases of real property formerly used by United Propane (now known as Bonavita, Inc.) in its business. We entered into five of these leases with United Propane, three of these leases with Pascal Enterprises, Inc. and two of these leases with Robert A. Pascal. Each of these leases 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, we 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. On May 1, 2005 this lease was renewed and the monthly base rent was reduced to $12,500.

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. In August 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 million in cash from us. These units were not entitled to current cash distributions, but would convert to our common units at a special conversion ratio upon the Phase II expansion becoming commercially operational. On August 25, 2007, the Special Units were converted into 919,349 common units as a result of the commercial operation of the Phase II expansion of the Stagecoach Natural Gas Storage Facility.

On occasion, Inergy Holdings reimburses us for expenses paid on behalf of Inergy Holdings. When we have a receivable from Inergy Holdings it is included in prepaid expenses and other current assets on our consolidated balance sheet. At September 30, 2007 we had $0.1 million due from Inergy Holdings. At September 30, 2006 we did not have an amount due from Inergy Holdings.

Review, Approval or Ratification of Transactions with Related Persons

Our board of directors has adopted a Related Person Transactions Policy. Under this Policy, any related person transaction may be entered into or continue only if approved as provided below.

Related person transactions that in the discretion of the managing general partner require approval of the conflicts committee in accordance with our Partnership Agreement may be approved only by the conflicts committee. Related person transactions that in the discretion of the managing general partner do not require

approval of the conflicts committee in accordance with our Partnership Agreement may be entered into or continue only if the related person transaction is in the normal course of our business and is (a) on terms no less favorable to us than those generally being provided to or available from unrelated third parties or (b) fair to us, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to us), then our Chief Executive Officer has authority to approve the transaction applying the criteria specified our Partnership Agreement. Any other related person transaction may be approved in one of the following two ways. First, the managing general partner may seek approval of the conflicts committee. If the managing general partner does not seek approval of the conflicts committee, the transaction may be approved by an independent committee of the board of directors (either the audit committee or a special committee) applying the criteria in our Partnership Agreement.

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

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

Cash distributions will generally be made approximately 99% to the limited partner unitholders, including affiliates of the managing general partner as holders of common units and approximately 1% to the non-managing general partner. In addition, when distributions exceed 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 general partner and its affiliates would receive a distribution of approximately $0.6 million on the approximate 0.9% general partner interest and a distribution of approximately $6.2 million on their common 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, 2007, 2006 and 2005 the expense reimbursement to our managing general partner and its affiliates was approximately $6.6 million, $8.7 million and $3.0 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 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 10.3% 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, 2007 and 2006 (in millions):


	Year Ended September 30,
	2007		2006
Audit fees⁽¹⁾	$	2.1	$	2.9
Audit-related fees⁽²⁾		0.1		0.1

Total	$	2.2	$	3.0

⁽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 2007. 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:

Financial Statements:

See Index Page for Financial Statements located on page 85.

Financial Statement Schedule:

Schedule II: Valuation and Qualifying Accounts located on page 119

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.

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		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 A		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 B		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 C		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)


Exhibit Number		Description
*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)

*4.1		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)

*4.2		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)

*4.3		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)

*4.4		Registration Rights Agreement (incorporated herein by reference to Exhibit 4.1 to Inergy, L.P.’s Form 8-K filed on December 27, 2004)

*4.5		Indenture (incorporated herein by reference to Exhibit 4.2 to Inergy, L.P.’s Form 8-K filed on December 27, 2004)

*4.6		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)

*4.7		Registration Rights Agreement (incorporated herein by reference to Exhibit 4.1 to Inergy L.P.’s Form 8-K filed on January 18, 2006)

*4.8		Indenture (incorporated herein by reference to Exhibit 4.2 to Inergy L.P.’s Form 8-K filed on January 18, 2006)

*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)


Exhibit Number		Description
*10.4		Inergy Long Term Incentive Plan (as amended and restated September 11, 2007) (incorporated herein by reference to Exhibit 10.1 to Inergy, L.P.’s Form 8-K filed on September 14, 2007)***

*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)***

*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 ***

*10.9		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)***

*10.10A		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		Form of Restricted Unit Award Agreement***

*10.12		Amended and Restated Inergy Unit Purchase Plan (incorporated by reference to Exhibit 10.1 to Inergy L.P.’s Form 10-Q filed on February 13, 2004)***

*10.13		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)

*10.13A		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)


Exhibit Number		Description
*10.14		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)

*10.15		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)

*10.16		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)

*10.17		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)

*10.18		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)

*10.19		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)

*10.20		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)

*10.21		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)

*10.22		Asset Purchase Agreement by and among Dowdle Gas, Inc., John Charles Dowdle Investment Management Trust, J. Nutie Dowdle, John C. Dowdle and Inergy Propane, LLC (incorporated herein by reference to Exhibit 10.1 to Inergy L.P.’s Form 10-Q filed on February 9, 2006)

*10.23		Summary of Non-Employee Director Compensation (incorporated herein by reference to Exhibit 10.1 to Inergy, L.P.’s Form 8-K filed on February 14, 2006)***

**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


Exhibit Number		Description

**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

**99.1		Audited balance sheet of Inergy GP, LLC

*	Previously filed

**	Filed herewith

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

(b)

Exhibits.

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

(c)

Financial Statement Schedules.

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

Inergy, L.P. and Subsidiaries

Consolidated Financial Statements

September 30, 2007 and 2006 and each of the

Three Years in the Period Ended

September 30, 2007

Contents


Report of Independent Registered Public Accounting Firm		86

Report of Independent Registered Public Accounting Firm on Internal Controls		87

Audited Consolidated Financial Statements:

Consolidated Balance Sheets		88

Consolidated Statements of Operations		89

Consolidated Statements of Partners’ Capital		90

Consolidated Statements of Cash Flows		91

Notes to Consolidated Financial Statements		93

Report of Independent Registered Public Accounting Firm

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

We have audited the accompanying consolidated balance sheets of Inergy, L.P. and Subsidiaries (the Company) as of September 30, 2007 and 2006, and the related consolidated statements of operations, partners’ capital, and cash flows for each of the three years in the period ended September 30, 2007. Our audits also included the financial statement schedule listed in the Index at Item 15(a). These financial statements and schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.

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

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Inergy, L.P. and Subsidiaries at September 30, 2007 and 2006, and the consolidated results of their operations and their cash flows for each of the three years in the period ended September 30, 2007, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly, in all material respects the information set forth therein.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Inergy, L.P. and Subsidiaries’ internal control over financial reporting as of September 30, 2007, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organization of the Treadway Commission and our report dated November 26, 2007 expressed an unqualified opinion thereon.

/s/ ERNST & YOUNG LLP

Kansas City, Missouri

November 26, 2007

Report of Independent Registered Public Accounting Firm on Internal Controls

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

We have audited Inergy, L.P. and Subsidiaries’ internal control over financial reporting as of September 30, 2007, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Inergy, L.P. and Subsidiaries’ management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit.

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

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

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

As indicated in the accompanying Management’s Report on Internal Control over Financial Reporting, management’s assessment of and conclusion on the effectiveness of internal control over financial reporting did not include the internal controls of its 2007 acquisitions, which are included in the 2007 consolidated financial statements of Inergy, L.P. and Subsidiaries and constituted $98.5 million of total assets as of September 30, 2007 and $23.6 million revenues for the year then ended. Our audit of internal control over financial reporting of Inergy, L.P. and Subsidiaries also did not include an evaluation of the internal control over financial reporting of its 2007 acquisitions.

In our opinion, Inergy, L.P. and Subsidiaries maintained, in all material respects, effective internal control over financial reporting as of September 30, 2007, based on the COSO criteria.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the 2007 consolidated financial statements of Inergy, L.P. and Subsidiaries and our report dated November 26, 2007 expressed an unqualified opinion thereon.

/s/ ERNST & YOUNG LLP

Kansas City, Missouri

November 26, 2007

Inergy, L.P. and Subsidiaries

Consolidated Balance Sheets

(in millions, except unit information)


	September 30,
	2007		2006
Assets
Current assets:
Cash	$	7.7	$	12.0
Accounts receivable, less allowance for doubtful accounts of $3.4 million and $2.9 million at September 30, 2007 and 2006, respectively		112.2		99.5
Inventories (Note 4)		100.5		108.1
Assets from price risk management activities		55.0		46.2
Prepaid expenses and other current assets		23.2		29.8

Total current assets		298.6		295.6

Property, plant and equipment (Note 4)		1,000.3		847.9
Less: accumulated depreciation		179.6		124.4

Property, plant and equipment, net		820.7		723.5

Intangible assets (Note 4):
Customer accounts		238.8		226.0
Other intangible assets		116.8		110.3

		355.6		336.3
Less: accumulated amortization		78.8		52.8

Intangible assets, net		276.8		283.5

Goodwill		347.2		332.4

Other assets		1.1		4.0

Total assets	$	1,744.4	$	1,639.0


Liabilities and partners’ capital
Current liabilities:
Accounts payable	$	100.3	$	81.5
Accrued expenses		61.5		62.9
Customer deposits		73.9		98.0
Liabilities from price risk management activities		49.6		49.0
Current portion of long-term debt (Note 6)		25.5		16.9


Total current liabilities		310.8		308.3

Long-term debt, less current portion (Note 6)		684.7		642.8

Other long-term liabilities		7.7		11.8

Partners’ capital (Note 8):
Common unitholders (49,764,486 and 45,005,153 units issued and outstanding as of September 30, 2007 and 2006, respectively)		739.5		648.8
Special unitholders (769,941 units issued and outstanding as of September 30, 2006)		—		25.0
Non-managing general partner and affiliate		1.7		2.3

Total partners’ capital		741.2		676.1

Total liabilities and partners’ capital	$	1,744.4	$	1,639.0

The accompanying notes are an integral part of these consolidated financial statements.

Inergy, L.P. and Subsidiaries

Consolidated Statements of Operations

(in millions, except per unit data)


	Year Ended September 30,
	2007			2006			2005
Revenue:
Propane	$	1,150.4		$	1,072.3		$	851.6
Other		332.7			317.9			200.3

		1,483.1			1,390.2			1,051.9
Cost of product sold (excluding depreciation and amortization as shown below):
Propane		820.0			779.7			593.4
Other		201.7			210.7			130.8

		1,021.7			990.4			724.2
Gross profit		461.4			399.8			327.7
Expenses:
Operating and administrative		252.2			248.1			197.1
Depreciation and amortization		83.4			76.7			50.3
Loss on disposal of assets		8.0			11.5			0.7

Operating income		117.8			63.5			79.6
Other income (expense):
Interest expense, net		(52.0	)		(53.8	)		(34.2	)
Write-off of deferred financing costs		—			—			(7.0	)
Other income		1.9			0.8			0.3

Income before income taxes		67.7			10.5			38.7
Provision for income taxes		(0.7	)		(0.7	)		(0.1	)

Net income	$	67.0		$	9.8		$	38.6

Partners’ interest information:
Non-managing general partner and affiliates interest in net income	$	27.5		$	17.9		$	8.1
Beneficial conversion value of Special Units (Note 8)		10.3			—			—
Distribution paid on restricted units		0.2			—			—

Total interest in net income not attributable to limited partners’	$	38.0		$	17.9		$	8.1


Common unit interest	$	29.0		$	(8.9	)	$	24.2
Senior subordinated unit interest		—			0.6			5.2
Junior subordinated unit interest		—			0.2			1.1

Total limited partners’ interest in net income (loss)	$	29.0		$	(8.1	)	$	30.5

Net income (loss) per limited partner unit:
Basic	$	0.61		$	(0.20	)	$	0.98

Diluted	$	0.61		$	(0.20	)	$	0.96

Weighted average limited partners’ units outstanding (in thousands):
Basic		47,693			41,407			31,143
Dilutive units		182			—			710

Diluted		47,875			41,407			31,853

The accompanying notes are an integral part of these consolidated financial statements.

Inergy, L.P. and Subsidiaries

Consolidated Statements of Partners’ Capital

(in millions)


	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, 2004	$	224.6		$	25.3		$	(2.3	)	$	4.4		$	—		$	252.0
Net proceeds from issuance of common units		410.6			—			—			—			—			410.6
Net proceeds from the issuance of Special Units		—			—			—			—			25.0			25.0
Senior subordinated units converted to common units		6.1			(6.1	)		—			—			—			—
Distributions		(45.9	)		(11.0	)		(2.2	)		(8.7	)		—			(67.8	)
Comprehensive income:
Net income		24.2			5.2			1.1			8.1			—			38.6
Unrealized gain on derivative instruments		4.2			0.9			0.2			0.1						5.4
Foreign currency translation		0.1			—			—			—			—			0.1

Comprehensive income (loss)																	44.1

Balance at September 30, 2005		623.9			14.3			(3.2	)		3.9			25.0			663.9

Net proceeds from issuance of common units		127.4			—			—			—			—			127.4
Net proceeds from common unit options exercised		4.0			—			—			—						4.0
Subordinated units converted to common units		1.0			(6.4	)		5.4			—			—			—
Contribution from unit based compensation charges		0.6			—			—			—			—			0.6
Distributions		(77.6	)		(8.4	)		(2.4	)		(19.2	)		—			(107.6	)
Comprehensive income:
Net income (loss)		(8.9	)		0.6			0.2			17.9			—			9.8
Unrealized loss on derivative instruments		(21.6	)		(0.1	)		—			(0.3	)		—			(22.0	)

Comprehensive income (loss)																	(12.2	)

Balance at September 30, 2006		648.8			—			—			2.3			25.0			676.1

Net proceeds from issuance of common units		104.5			—			—			—			—			104.5
Net proceeds from common unit options exercised		3.9			—			—			—						3.9
Contribution from unit based compensation charges		0.7			—			—			—			—			0.7
Special Units converted to common units		25.0			—			—			—			(25.0	)		—
Distributions		(108.4	)		—			—			(28.4	)		—			(136.8	)
Comprehensive income:
Net income (loss)		39.5			—			—			27.5			—			67.0
Unrealized gain on derivative instruments		25.5			—			—			0.3			—			25.8

Comprehensive income (loss)																	92.8

Balance at September 30, 2007	$	739.5		$	—		$	—		$	1.7		$	—		$	741.2

The accompanying notes are an integral part of these consolidated financial statements.

Inergy, L.P. and Subsidiaries

Consolidated Statements of Cash Flows

(in millions)


	Year Ended September 30,
	2007			2006			2005
Operating activities
Net income	$	67.0		$	9.8		$	38.6
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation		59.7			54.6			37.3
Amortization		23.7			22.1			13.0
Amortization of deferred financing costs		2.4			2.2			1.8
Unit-based compensation charges		0.7			0.6			—
Provision for doubtful accounts		3.3			3.6			2.0
Loss on disposal of assets		8.0			11.5			0.7
Net assets (liabilities) from price risk management activities		17.6			(10.4	)		(10.0	)
Write-off of deferred financing costs		—			—			7.0
Changes in operating assets and liabilities, net of effects from acquisitions:
Accounts receivable		(16.6	)		4.7			(19.7	)
Inventories		8.4			28.4			(34.7	)
Prepaid expenses and other current assets		6.6			(6.2	)		0.5
Other assets (liabilities)		2.9			(0.4	)		(0.6	)
Accounts payable		13.8			(47.4	)		19.4
Accrued expenses		(5.5	)		12.4			13.8
Customer deposits		(24.1	)		18.9			18.5

Net cash provided by operating activities		167.9			104.4			87.6
Investing activities
Acquisitions, net of cash acquired		(99.6	)		(187.2	)		(810.1	)
Purchases of property, plant and equipment		(100.9	)		(34.5	)		(34.1	)
Deferred acquisition costs incurred		(0.4	)		(0.7	)		(0.6	)
Proceeds from sale of assets		13.1			11.5			4.2

Net cash used in investing activities		(187.8	)		(210.9	)		(840.6	)

The accompanying notes are an integral part of these consolidated financial statements.

Inergy, L.P. and Subsidiaries

Consolidated Statements of Cash Flows (continued)

(in millions)


	Year Ended September 30,
	2007			2006			2005
Financing activities
Proceeds from the issuance of long-term debt	$	394.3		$	706.1		$	1,614.5
Principal payments on long-term debt		(350.3	)		(615.9	)		(1,198.7	)
Distributions		(136.8	)		(107.6	)		(67.8	)
Payments for deferred financing costs		—			(5.0	)		(23.5	)
Net proceeds from issuance of common units		104.5			127.4			410.6
Net proceeds from the issuance of Special Units		—			—			25.0
Net proceeds from unit options exercised		3.9			4.0			—

Net cash provided by financing activities		15.6			109.0			760.1

Effect of foreign exchange rate changes on cash		—			—			0.1

Net increase (decrease) in cash		(4.3	)		2.5			7.2
Cash at beginning of period		12.0			9.5			2.3

Cash at end of period	$	7.7		$	12.0		$	9.5

Supplemental disclosure of cash flow information
Cash paid during the period for interest	$	53.2		$	50.9		$	28.5

Supplemental schedule of noncash investing and financing activities
Additions to covenants not to compete through the issuance of noncompete obligations	$	5.5		$	9.6		$	7.9

Net change to property, plant and equipment through accounts payable and accrued expenses	$	0.5		$	4.1		$	—

Increase (decrease) in the fair value of long-term debt and related interest rate swap liability	$	1.1		$	(2.0	)	$	1.6

Acquisitions, net of cash acquired:
Current assets	$	0.4		$	32.4		$	76.7
Property, plant and equipment		76.5			29.7			520.2
Intangible assets		13.4			77.9			130.9
Goodwill		14.9			83.8			171.0
Other assets		—			0.2			2.4
Current liabilities		(5.6	)		(36.8	)		(91.1	)

	$	99.6		$	187.2		$	810.1

The accompanying notes are an integral part of these consolidated financial statements.

Inergy, L.P. and Subsidiaries

Notes to Consolidated Financial Statements

Note 1. Partnership Organization and Formation

Organization

The consolidated financial statements of Inergy, L.P. (“Inergy”, “The Partnership” or the “Company”) include the accounts of Inergy and its subsidiaries, including Inergy Propane, LLC (“Inergy Propane”), Inergy Midstream, LLC (collectively, the “Operating Companies”) and Inergy Finance Corp.

Inergy Partners, LLC (“Inergy Partners” or the “Non-Managing General Partner”), a subsidiary of Inergy Holdings, L.P. (“Holdings”), owns the Non-Managing General Partner interest in the Company. Inergy GP, LLC (“Inergy GP” or the “Managing General Partner”), a wholly owned subsidiary of Holdings, has sole responsibility for conducting the Company’s business and managing its operations. Holdings is a holding company whose principal business, through its subsidiaries, is its management of and ownership in Inergy, L.P. Holdings also directly owns the incentive distribution rights with respect to Inergy, L.P.

Pursuant to a partnership agreement, Inergy GP or any of its affiliates is entitled to reimbursement for all direct and indirect expenses incurred or payments it makes on behalf of Inergy and all other necessary or appropriate expenses allocable to Inergy or otherwise reasonably incurred by Inergy GP in connection with operating the Company’s business. These costs, which totaled approximately $6.6 million, $8.7 million and $3.0 million for the years ended September 30, 2007, 2006 and 2005, respectively, include compensation, bonuses and benefits paid to officers and employees of Inergy GP and its affiliates.

As of September 30, 2007, Holdings owns an aggregate 10.3% interest in Inergy, L.P., inclusive of ownership of all of the non-managing general partner and the managing general partner. This ownership is comprised of an approximate 0.9% general partnership interest and 9.4% limited partnership interest.

Nature of Operations

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

Principles of Consolidation

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.

Reclassifications

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

Note 2. Summary of Significant Accounting Policies

Financial Instruments and Price Risk Management

Inergy utilizes certain derivative financial instruments to (i) manage its exposure to commodity price risk, specifically, the related change in the fair value of inventories, as well as the variability of cash flows related to forecasted transactions; (ii) to ensure adequate physical supply of commodity will be available; and (iii) manage its exposure to interest rate risk.

Inergy, L.P. and Subsidiaries

Notes to Consolidated Financial Statements—(Continued)

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 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 transaction.

Inergy is party to certain commodity derivative financial instruments that are designated as hedges of selected inventory positions, and qualify as fair value hedges, as defined in SFAS 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. 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. Any ineffective portion of the fair value hedges is recognized as cost of product sold in the current period. Inergy recognized a net gain of $0.1 million in the year ended September 30, 2007, related to the ineffective portion of its fair value hedging instruments. In addition, for the year ended September 30, 2007, Inergy recognized a net gain of $1.0 million related to the portion of fair value hedging instruments that it excluded from its assessment of hedge effectiveness.

Inergy also enters into derivative financial instruments that qualify as cash flow hedges, which hedge the exposure of variability in expected future cash flows predominantly attributable to forecasted purchases to supply fixed price sale contracts. These derivatives are recorded on the balance sheet at fair value as price risk management assets or liabilities. The effective portion of the gain or loss on these cash flow hedges is recorded in other comprehensive income in partner’s capital and reclassified into earnings in the same period in which the hedge transaction affects earnings. Any ineffective portion of the gain or loss is recognized as cost of product sold in the current period. Accumulated other comprehensive income (loss) was $9.2 million and $(16.6) million at September 30, 2007 and 2006, respectively.

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 later of the time product is shipped or delivered to the customer. Gas processing and fractionation fees are recognized upon delivery of the product. Revenue from the sale of propane appliances and equipment is recognized at the later of the time of sale or installation. Revenue from repairs and maintenance is recognized upon completion of the service. Revenue from storage contracts is recognized during the period in which storage services are provided.

Expense Classification

Cost of product 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 those described above in cost of product sold and depreciation and amortization. Certain of Inergy’s operating and administrative expenses and depreciation and amortization are incurred in the distribution of the product sales but are not included in cost of product sold. These amounts were $96.8 million, $93.1 million and $67.1 million during the years ended September 30, 2007, 2006 and 2005, respectively.

Inergy, L.P. and Subsidiaries

Notes to Consolidated Financial Statements—(Continued)

Credit Risk and Concentrations

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

Inergy enters into netting agreements with certain wholesale customers to mitigate the Company’s credit risk. As a result of adopting EITF 04-13 in the year ended September 30, 2006, appropriate receivables and payables are reflected at a net balance.

Three suppliers, ExxonMobil Oil Corp. (13%), BP Amoco Corp. (12%) and Sunoco, Inc. (12%), accounted for approximately 37% of propane purchases during the past fiscal year. The Company believes that contracts with these suppliers will enable Inergy to purchase most of its supply needs at market prices and ensure adequate supply. No other single supplier accounted for more than 10% of propane purchases in the current year.

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

Use of Estimates

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

Inventories

Inventories for retail operations, which mainly consist of propane gas and other liquids, are stated at the lower of cost or market and are computed using the average-cost method. Wholesale propane and other liquids inventories are designated under a fair value hedge program and are consequently marked to market. All wholesale propane and other liquids inventories being hedged and carried at market value at September 30, 2007 and 2006 amount to $59.5 million and $67.8 million, respectively. Inventories for midstream operations are stated at the lower of cost or market determined using the first-in-first-out method.

Shipping and Handling Costs

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

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

Inergy, L.P. and Subsidiaries

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” (“SFAS 144”), 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, 2007. See Note 4 for a discussion of assets held for sale at September 30, 2007 and 2006.

Identifiable Intangible Assets

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

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


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

Trademarks have been assigned an indefinite economic life and are not being amortized, but are subject to an annual impairment evaluation.

Estimated amortization, including amortization of deferred financing costs reported as interest expense, for the next five years ending September 30, is as follows (in millions):


Year Ending September 30,
2008	$	25.0
2009		24.4
2010		22.6
2011		21.7
2012		21.0

Goodwill

Goodwill is recognized pursuant to Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets,” (“SFAS 142”) for various acquisitions by Inergy as the excess of the cost of the acquisitions over the fair value of the related net assets at the date of acquisition. Under SFAS 142, goodwill is subject to at least an annual assessment for impairment by applying a fair-value-based test.

Inergy, L.P. and Subsidiaries

Notes to Consolidated Financial Statements—(Continued)

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

Inergy has completed the impairment test for each of its reporting units and determined that no impairment existed as of September 30, 2007.

Income Taxes

The earnings of the Partnership and the Operating Company are included in the Federal and state income tax returns of the individual partners. Federal and state income taxes are provided on the taxable income of Services and certain state taxes for the Partnership have been included in the accompanying financial statements as income taxes due to the nature of the tax. Net earnings for financial statement purposes may differ significantly from taxable income reportable to unitholders as a result of differences between the tax basis and the financial reporting basis of assets and liabilities and the taxable income allocation requirements under the partnership agreement.

The provision for income tax was $0.7 million for the years ended September 30, 2007 and 2006, and $0.1 million for the year ended September 30, 2005. At September 30, 2007, the Company had cumulative temporary differences between the book and tax basis of Inergy Sales and Service, Inc. (“Services”), a subsidiary of Inergy, of approximately $8.9 million, comprised primarily of a net operating loss carryforward. At September 30, 2007 and 2006, this resulted in a deferred tax asset of approximately $3.4 million and $2.3 million, respectively, which the Company has fully reserved with a valuation allowance of $3.4 million and $2.3 million, respectively. In order to fully realize the deferred tax asset Services will need to generate future taxable income. A valuation allowance is provided when it is more likely than not that some or all of the deferred tax asset will not be realized. Based on the level of current taxable income and projections of future taxable income of Services over the periods in which the deferred tax asset would be deductible, the Company is providing a full valuation allowance that it is more likely than not that that it will not realize the full benefit of the deferred tax asset.

Taxes Collected from Customers and Remitted to Governmental Authorities

Inergy accounts for the collection and remittance of all taxes on a net tax basis. As a result, these amounts are not reflected in the consolidated statements of operations.

Customer Deposits

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

Cash and Cash Equivalents

Inergy defines cash equivalents as all highly liquid investments with maturities of three months or less when purchased.

Inergy, L.P. and Subsidiaries

Notes to Consolidated Financial Statements—(Continued)

Computer Software Costs

Inergy includes in property, plant and equipment costs associated with the acquisition of computer software. Inergy amortizes computer software costs on a straight-line basis over expected periods of benefit, which generally are five years.

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 $703.3 million and $649.4 million as of September 30, 2007 and 2006, respectively. See Note 5 for the fair value of the Company’s 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. Accumulated other comprehensive income (loss) consists of the following components (in millions):


	Foreign Currency Translation Adjustment			Unrealized Gains (Losses) on Derivative Instruments			Accumulated Other Comprehensive Income (Loss)
As of September 30, 2005	$	0.1		$	5.4		$	5.5
Other Comprehensive loss ^(a)		(0.1	)		(22.0	)		(22.1	)

As of September 30, 2006		—			(16.6	)		(16.6	)
Other Comprehensive income ^(a)		—			25.8			25.8

As of September 30, 2007	$	—		$	9.2		$	9.2

^(a)	Other comprehensive income (loss) includes a reclassification of $(16.6) million and $5.4 million to net income during the years ended September 30, 2007 and 2006, respectively.

Pursuant to SFAS 133, Inergy records the effective portion of the unrealized gains and losses on its derivative financial instruments that qualify as cash flow hedges as other comprehensive income.

Income Per Unit

The Company calculates basic net income per unit by dividing net income, after considering the Non-Managing General Partner’s interest, including priority distributions, beneficial conversion value (see Note 8), and the subordinated unitholder’s interest, by the weighted average number of limited partner units outstanding. When applicable, basic net income per unit is calculated for subordinated units by dividing the earnings allocated to each class of subordinated units by the weighted average number of units outstanding. Under this method, the calculation of net income per unit reflects an allocation of earnings to each class of units that is consistent with the partnership agreement’s treatment of the respective classes’ capital accounts. Diluted net income per limited partner unit is computed by dividing net income, after considering the Non-Managing General Partner’s interest, by the sum of (a) weighted average number of common units, (b) if applicable, the additional common units that would be issued assuming the subordinated units were converted to common units, and (c) the effect of other dilutive units.

Inergy, L.P. and Subsidiaries

Notes to Consolidated Financial Statements—(Continued)

As the effect of including incremental units associated with options were antidilutive for the year ended September 30, 2006 due to the limited partners’ interest being a net loss for that period, no unit options or other dilutive units were reflected in the applicable dilutive earnings per unit computation. As a result, both basic earnings per unit and diluted earnings per unit reflect the same calculation for the year ended September 30, 2006. Weighted average antidilutive unit options outstanding totaled 463,620 for the year ended September 30, 2006.

Accounting for Unit-Based Compensation

Inergy has a unit-based employee compensation plan, which is accounted for under the provisions of Statement of Financial Accounting Standards (“SFAS”) No. 123(R), “Share-Based Payment” (“SFAS 123(R)”). SFAS 123(R) supersedes APB Opinion No. 25, “Accounting for Stock Issued to Employees” (“APB 25”), and amends SFAS No. 95, “Statement of Cash Flows.” SFAS 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.

The Company adopted SFAS 123(R) on October 1, 2005 using the modified prospective method. Under the modified prospective method, compensation cost is recognized beginning with the effective date (a) for all share-based payments granted after the effective date and (b) for all awards granted to employees prior to effective date of SFAS 123(R) that remain unvested as of the effective date. Under this method, SFAS 123(R) applies to new awards and to awards modified, repurchased, or cancelled after the adoption date of October 1, 2005. The compensation cost for the portion of awards for which the requisite service has not been rendered that are outstanding as of October 1, 2005 will be recognized as the requisite service is rendered. The compensation cost for that portion of awards is based on the fair value of those awards as of the grant-date and was calculated for pro forma disclosures under SFAS 123. The compensation cost for those earlier awards is attributed to periods beginning on or after October 1, 2005 using the attribution method that was used under SFAS 123.

The amount of compensation expense recorded by the Company under the provisions of SFAS 123(R) during the years ended September 30, 2007 and 2006 was approximately $0.7 million and $0.6 million, respectively. The compensation expense for the years ended September 30, 2007 and 2006 includes approximately $0.3 million of unit-based compensation expense on Inergy Holdings, L.P. units.

The following table illustrates the effect on net income and net income per limited partner unit as if Inergy had applied the fair value recognition provision of SFAS 123(R) to unit-based employee compensation for the year ended September 30, 2005. For purposes of pro forma disclosures, the estimated fair value of an option is amortized to expense over the option’s vesting period (in millions, except per unit data):


	2005
Net income as reported	$	38.6
Deduct: Total unit-based employee compensation expense determined under fair value method for all awards		0.2

Pro forma net income (loss)	$	38.4

Deduct: Non-managing general partners and affiliate’s interest in net income (loss)	$	8.1

Pro forma limited partners’ interest in net income (loss)	$	30.3

Net income per limited partner unit
Basic—as reported	$	0.98
Basic—pro forma	$	0.97
Diluted—as reported	$	0.96
Diluted—pro forma	$	0.95

Inergy, L.P. and Subsidiaries

Notes to Consolidated Financial Statements—(Continued)

Segment Information

SFAS No. 131, “Disclosures about Segments of an Enterprise and Related Information” (“SFAS 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 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 131, Inergy examined the way it organizes its business internally for making operating decisions and assessing business performance. See Note 12 for disclosures related to Inergy’s propane and midstream segments.

Recently Issued Accounting Pronouncements

SFAS No. 155, “Accounting for Certain Hybrid Financial Instruments” (“SFAS 155”) amends SFAS 133, and SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishment of Liabilities.” SFAS 155 permits fair value remeasurement for any hybrid financial instrument that contains an embedded derivative that otherwise would require bifurcation. It also establishes a requirement to evaluate securitized financial assets to identify interests that are freestanding derivatives or that are hybrid financial instruments that contain an embedded derivative requiring bifurcation. The Company has adopted SFAS 155 for all financial instruments acquired or issued on or after October 1, 2006. The adoption of SFAS 155 has not had a material effect on the consolidated financial statements in the current year as well as all prior years considered.

Staff Accounting Bulletin No. 108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements” (“SAB 108”), provides guidance on the quantification of prior year misstatements. SAB 108 requires that registrants use both the income statement (roll-over) approach and the balance sheet (iron curtain) approach when evaluating the materiality of a misstatement and contains guidance for correcting the errors under this dual approach. The Company has adopted SAB 108 for the fiscal year ended September 30, 2007, which did not have a material effect on the consolidated financial statements in the current year as well as all prior years considered.

SFAS No. 154, “Accounting Changes and Error Corrections” (“SFAS 154”) is a replacement of APB Opinion No. 20, “Accounting Changes,” and SFAS No. 3, “Reporting Accounting Changes in Interim Financial Statements.” SFAS 154 applies to all voluntary changes in accounting principle and changes the accounting for and a reporting of a change in accounting principle. SFAS 154 requires retrospective application to the prior periods’ financial statements of a voluntary change in accounting principle unless it is impracticable. The Company has adopted SFAS 154 for the fiscal year ended September 30, 2007, which did not have a material effect on the consolidated financial statements in the current year as well as all prior years considered.

EITF Issue No. 06-3, “How Taxes Collected from Customers and Remitted to Governmental Authorities Should be Presented in the Income Statement (That Is, Gross Versus Net Presentation)” requires companies to disclose their policy regarding the presentation of tax receipts. The scope of this guidance includes any tax assessed by a governmental authority that is directly imposed on a revenue-producing transaction between a seller and a customer and may include, but is not limited to, sales, use, value added, and some excise taxes (gross receipts taxes are excluded). An entity is not required to reevaluate its existing policies related to taxes assessed by a governmental authority as a result of this consensus. In addition, for any such taxes that are reported on a gross basis, an entity should disclose the amounts of those taxes in interim and annual financial statements for each period for which an income statement is presented if those amounts are significant. The Company has early adopted the consensus reached in this EITF for the fiscal year ended September 30, 2007, which did not have a material effect on the consolidated financial statements in the current year as well as all prior years considered.

100

Inergy, L.P. and Subsidiaries

Notes to Consolidated Financial Statements—(Continued)

SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS 159”) was issued in February 2007 to permit entities to choose to measure many financial instruments and certain other items at fair value at specified election dates. A business entity is required to report unrealized gains and losses on items for which the fair value option has been elected in earnings at each subsequent reporting date. SFAS 159 is required to be adopted by the Company for the fiscal year ended September 30, 2009. The Company is evaluating the potential financial statement impact of SFAS 159 to its consolidated financial statements.

SFAS No. 157, “Fair Value Measurements” (“SFAS 157”) was issued in September 2006 to define fair value, establish a framework for measuring fair value according to generally accepted accounting principles, and expand disclosures about fair value measurements. SFAS 157 is required to be adopted by the Company for the fiscal year ended September 30, 2009. The Company is evaluating the potential financial statement impact of SFAS 157 to its consolidated financial statements.

FASB Interpretation No. 48 (“FIN 48”), “Accounting for Uncertainty in Income Taxes — an interpretation of FASB Statement No. 109” provides a recognition threshold and measurement attribute for the recognition and measurement of a tax position taken or expected to be taken in a tax return and also provides guidance on derecognition, classification, treatment of interest and penalties, and disclosure. FIN 48 is required to be adopted by the Company for the fiscal year ended September 30, 2008. The Company is evaluating the potential financial statement impact of FIN 48 to its consolidated financials statements.

Note 3. Acquisitions

During the fiscal year ended September 30, 2007, Inergy made 13 acquisitions, including Columbus Butane Company, Inc., Hometown Propane, Inc., Quality Propane, Inc., Bay Cities Gas Corporation, Prince Oil Company, Inc., DeCock Bottled Gas & Appliance, Inc. and the propane assets of five other retail locations. Inergy also acquired a natural gas liquids storage facility located near Bath, New York (the “Bath Storage Facility”), and completed the acquisition of the 24-mile lateral pipeline (“South Lateral Pipeline”) connecting its Stagecoach natural gas storage facility to Tennessee Gas Pipeline Company’s Line 300. The aggregate purchase price of these 13 acquisitions, net of cash acquired, was approximately $98.9 million. The purchase price allocation for these acquisitions has been prepared on a preliminary basis pending final asset valuation and asset rationalization, and changes are expected when additional information becomes available. Changes to final asset valuation of prior fiscal year acquisitions have been included in the Company’s consolidated financial statements but are not material.

Regulation S-X of the Securities and Exchange Commission requires that for any significant subsidiary, which is defined as any significant business combination or disposition of assets, pro-forma information must be disclosed. None of the fiscal 2007 acquisitions were, individually or in the aggregate, considered a significant subsidiary. Therefore, no pro-forma results from operations are provided.

As a result of the fiscal 2007 acquisitions, the Company acquired $14.4 million of goodwill and $19.5 million of intangible assets, consisting of the following (in millions):


Customer accounts	$	12.8
Non-compete agreements		6.7

Total intangible assets	$	19.5

The weighted average amortization period of amortizable intangible assets acquired during the year ended September 30, 2007, is approximately 10 years.

101

Inergy, L.P. and Subsidiaries

Notes to Consolidated Financial Statements—(Continued)

During the fourth quarter of 2007, Inergy finalized its purchase price allocation of the fair value of the Bath Storage Facility’s assets based on certain third party information. The Company recorded a purchase price adjustment which increased the fair value of its fixed assets (including land and wells) and accumulated depreciation by $14.4 million and $0.9 million, respectively, decreased goodwill, non-compete agreements and accumulated amortization by $12.4 million, $3.2 million and $0.3 million respectively, and increased customer accounts by $1.2 million.

Note 4. Certain Balance Sheet Information

Inventories

Inventories consist of the following at September 30, 2007 and 2006, respectively (in millions):


	2007		2006
Propane gas and other liquids	$	88.5	$	96.1
Appliances, parts and supplies		12.0		12.0

	$	100.5	$	108.1

Property, Plant and Equipment

Property, plant and equipment consists of the following at September 30, 2007 and 2006, respectively (in millions):


	2007		2006
Tanks and plant equipment	$	619.2	$	578.4
Land and buildings		233.9		135.5
Vehicles		97.7		89.3
Construction in process		27.7		24.7
Office furniture and equipment		21.8		20.0

		1,000.3		847.9
Less: accumulated depreciation		179.6		124.4

Property, plant and equipment, net	$	820.7	$	723.5

Depreciation expense totaled $59.7 million, $54.6 million and $37.3 million for the years ended September 30, 2007, 2006 and 2005, respectively.

At September 30, 2007 and 2006, the Company capitalized interest of $3.1 million and $0.4 million, respectively, related to certain Midstream asset expansion projects.

As discussed in Note 3, the Company recorded a purchase price adjustment in the fourth quarter of 2007 related to the Bath Storage Facility acquisition which increased the value of fixed assets and accumulated depreciation by $14.4 million and $0.9 million, respectively. In the fourth quarter of 2006, the Company recorded a purchase price adjustment related to the Stagecoach acquisition which decreased the value of fixed assets and accumulated depreciation by $84.4 million and $4.3 million, respectively.

The property, plant and equipment balances above at September 30, 2007 and 2006 include approximately $8.5 million and $6.8 million, respectively, of propane operations assets deemed held for sale under the provisions of

102

Inergy, L.P. and Subsidiaries

Notes to Consolidated Financial Statements—(Continued)

SFAS 144. These assets were identified primarily during the fourth quarters of 2007 and 2006 as a result of the integration of the larger retail propane acquisitions closed since November 2004 as Inergy has focused on eliminating redundant operations, primarily tanks and equipment, vehicles and certain real estate. As a result, the carrying value of these assets was reduced to their estimated recoverable value less anticipated disposition costs, resulting in losses of approximately $6.2 million and $6.6 million for the years ended September 30, 2007 and 2006, respectively. The $6.2 million and $6.6 million charges are included as components of operating income as losses on disposal of assets. When aggregated with other realized losses, such amounts totaled $8.0 million and $11.5 million, respectively.

Intangible Assets

Intangible assets consist of the following at September 30, 2007 and 2006, respectively (in millions):


	2007			2006
Customer accounts	$	238.8		$	226.0
(accumulated amortization—customer accounts)		(48.6	)		(33.7	)
Covenants not to compete		60.9			54.2
(accumulated amortization—covenants not to compete)		(22.6	)		(14.6	)
Deferred financing and other costs		23.1			23.3
(accumulated amortization—deferred financing costs)		(7.6	)		(4.5	)
Trademarks		32.8			32.8

Total intangible assets, net	$	276.8		$	283.5

Amortization and interest expense associated with the above described intangible assets at September 30, 2007, 2006 and 2005 amounted to $26.1 million, $24.3 million and $14.8 million, respectively.

Note 5. Price Risk Management and Financial Instruments

Commodity Derivative Instruments and Price Risk Management

Inergy, through its wholesale operations, sells propane to energy related businesses and may use a variety of financial and other instruments including forward contracts involving physical delivery of propane. In addition, Inergy manages its own commodity risks 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.

As discussed in Note 2, all of these financial instruments are accounted for under SFAS 133. Inergy has entered into 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.

103

Inergy, L.P. and Subsidiaries

Notes to Consolidated Financial Statements—(Continued)

Notional Amounts and Terms

The notional amounts and terms of these financial instruments include the following at September 30, 2007 and 2006 (in millions):


	September 30,
	2007		2006
	Fixed Price Payor	Fixed Price Receiver	Fixed Price Payor	Fixed Price Receiver
Propane, crude and heating oil (barrels)	5.0	4.8	8.0	7.5
Natural gas (MMBTU’s)	7.9	7.9	5.5	5.4

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

Fair Value

The Company uses observable market values for determining the fair value of its trading instruments. In cases where actively quoted prices are not available, other external sources are used which incorporate information about commodity prices in actively quoted markets, quoted prices in less active markets and other market fundamental analysis. The Company’s risk management department regularly compares valuations to independent sources and models.

104

Inergy, L.P. and Subsidiaries

Notes to Consolidated Financial Statements—(Continued)


	Year Ended September 30,
	2007			2006
Net fair value gain (loss) of contracts outstanding at beginning of year	$	(2.8	)	$	8.8
Initial recorded value of new contracts entered into during the year		1.4			—
Net change in physical exchange contracts		(2.0	)		(0.6	)
Change in fair value of contracts attributable to market movement during the year		20.6			(4.4	)
Realized gains		(11.8	)		(6.6	)

Net fair value of contracts outstanding at end of year	$	5.4		$	(2.8	)

During the years ended September 30, 2007, 2006 and 2005, Inergy recognized a net gain of $0.1 million and less than $0.1 million, and a net loss of $0.2 million, respectively, related to the ineffective portion of its fair value commodity hedging instruments and a net gain of $1.0 million, and a net loss of $0.4 million and $0.6 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 133.

The total amount of deferred cash flow hedge gains recorded in other comprehensive income as of September 30, 2007 in the amount of $9.2 million is expected to be reclassified to future earnings predominantly within the next twelve months, contemporaneously with the timing that related physical purchase of the underlying commodity affect earnings. During the years ended September 30, 2007 and 2006, there was no material ineffectiveness related to cash flow hedges. The total amount of deferred cash flow hedge losses recorded in other comprehensive income as of September 30, 2006 in the amount of $16.6 million was reclassified to earnings during the fiscal year ended September 30, 2007, none of which was related to forecasted transactions that were no longer considered probable of occurring. 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 Company’s 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 takes an active role in managing and controlling market and credit risk and have established control procedures, which are reviewed on an ongoing basis. Inergy monitors market risk through a variety of techniques, including daily reporting of the portfolio’s position to senior management. The Company attempts to minimize credit risk exposure through credit policies and periodic monitoring procedures as well as through customer deposits, letters of credit and entering into netting agreements that allow

105

Inergy, L.P. and Subsidiaries

Notes to Consolidated Financial Statements—(Continued)

for offsetting counterparty receivable and payable balances for certain financial transactions, as deemed appropriate. The counterparties associated with assets from price risk management activities as of September 30, 2007 and 2006 were propane retailers, resellers, energy marketers and dealers.

Note 6. Long-Term Debt

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


	September 30,
	2007		2006
Credit agreement	$	71.0	$	22.7
Senior unsecured notes		622.4		621.4
Obligations under non-compete agreements and notes to former owners of businesses acquired		16.8		15.6

		710.2		659.7
Less current portion		25.5		16.9

	$	684.7	$	642.8

Credit Agreement

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. In October 2006, Inergy amended the Credit Agreement with existing lenders primarily to increase the effective amount of working capital borrowing capacity available under the two facilities from $150 million to $200 million utilizing capacity under the acquisition credit facility for working capital needed during the winter heating season. Other terms, conditions, and covenants remained materially unchanged.

Inergy is required to reduce the principal outstanding on the Working Capital Facility to $10 million or less for a minimum of 30 consecutive days during the period commencing March 1 and ending September 30. As such, $10 million of the outstanding balance at September 30, 2007 and 2006 have been classified as a long-term liability in the accompanying consolidated balance sheets. At September 30, 2007, the balance outstanding under the Credit Agreement was $71.0 million, including $40.0 million under the Acquisition Facility and $31.0 million under the Working Capital Facility. At September 30, 2006, borrowings under the Credit Agreement were $22.7 million under the Working Capital Facility. The prime rate and LIBOR plus the applicable spreads were between 7.0% and 7.2% at September 30, 2007, and between 7.08% and 8.50% at September 30, 2006, for all outstanding debt under the 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 $327.4 million and $369.4 million at September 30, 2007 and 2006, respectively. Outstanding standby letters of credit under the Credit Agreement amounted to $26.6 million and $32.9 million at September 30, 2007 and 2006, respectively.

106

Inergy, L.P. and Subsidiaries

Notes to Consolidated Financial Statements—(Continued)

At September 30, 2007, the Company was in compliance with all of its debt covenants.

Senior Unsecured Notes

2016 Senior Notes

On January 11, 2006, Inergy and its wholly owned subsidiary, Inergy Finance Corp. (“Finance Corp.” and together with Inergy, the “Issuers”) issued $200 million aggregate principal amount of 8.25% senior unsecured notes due 2016 (“2016 Senior Notes”) in a private placement to eligible purchasers. The 2016 Senior Notes contain covenants similar to the 2014 Senior Notes. Inergy used the net proceeds of the offering to repay outstanding indebtedness under the revolving acquisition credit facility. The 2016 Senior Notes represent senior unsecured obligations of Inergy and rank pari passu in right of payment with all other present and future senior indebtedness of Inergy. The 2016 Senior Notes are jointly and severally guaranteed by all of Inergy’s current domestic subsidiaries and have certain call features which allow Inergy to redeem the notes at specified prices based on the date redeemed as described below.

On May 18, 2006, Inergy completed an offer to exchange its existing 8.25% 2016 Senior Notes for $200 million of 8.25% senior notes due 2016 (the “2016 Exchange Notes”) that are registered and do not carry transfer restrictions, registration rights and provisions for additional interest. The 2016 Exchange Notes did not provide Inergy with any additional proceeds and satisfied Inergy’s obligations under the registration rights agreement.

Before March 1, 2009, Inergy may, at any time or from time to time, redeem up to 35% of the aggregate principal amount of the 2016 Senior Notes with the net proceeds of a public or private equity offering at 108.25% 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 150 days of the date of the closing of such equity offering.

The 2016 Senior Notes are redeemable, at Inergy’s option, in whole or in part, at any time on or after March 1, 2011, in each case at the redemption prices described in the table below, together with any accrued and unpaid interest to the date of the redemption.


Year	Percentage
2011	104.125	%
2012	102.750	%
2013	101.375	%
2014 and thereafter	100.000	%

2014 Senior Notes

On December 22, 2004, the Issuers completed a private placement of $425 million in aggregate principal amount of 6.875% senior unsecured notes due 2014 (the “2014 Senior Notes”). The 2014 Senior Notes contain covenants similar to the Credit Agreement. The net proceeds were used to repay outstanding indebtedness.

The 2014 Senior Notes represent senior unsecured obligations and rank pari passu in right of payment with all the Company’s other present and future senior indebtedness. The 2014 Senior Notes are jointly and severally guaranteed by all current domestic subsidiaries and have certain call features, which allow the Company to redeem the 2014 Senior Notes at specified prices based on the date redeemed as described below.

107

Inergy, L.P. and Subsidiaries

Notes to Consolidated Financial Statements—(Continued)

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

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 2014 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 2014 Senior Notes are redeemable, at Inergy’s option, in whole or in part, at any time on or after December 15, 2009, in each case at the redemption prices described in the table below, together with any accrued and unpaid interest to the date of the redemption.


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

Inergy is party to five interest rate swap agreements scheduled to mature in December 2014, each designed to hedge $25 million in underlying fixed rate senior unsecured notes in order to manage interest rate risk exposure. These swap agreements, which expire on the same date as the maturity date of the related senior unsecured notes due 2014 and contain call provisions consistent with the underlying senior unsecured notes, require the counterparty to pay the Company an amount based on the stated fixed interest rate due every six months. In exchange, Inergy is required to make semi-annual floating interest rate payments on the same dates to the counterparty based on an annual interest rate equal to the 6-month LIBOR interest rate plus spreads between 0.92% and 2.20% applied to the same notional amount of $125 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. At September 30, 2007, Inergy had recorded an approximate $2.5 million reduction in the fair market value of the related senior unsecured notes 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

Non-interest bearing obligations due under noncompetition agreements and other note payable agreements consist of agreements between Inergy and the sellers of retail propane companies acquired from fiscal years 1999 through 2007 with payments due through 2017 and imputed interest ranging from 3.5% to 9.0%. Noninterest-bearing obligations consist of $20.4 million and $19.1 million in total payments due under agreements, less unamortized discount based on imputed interest of $3.7 million and $3.5 million at September 30, 2007 and 2006, respectively. Additionally, the Company has a long term obligation related to a long-term asset management agreement for certain transportation services provided to one of Inergy’s subsidiaries. The unpaid balance of this obligation was $8.2 million at September 30, 2007.

108

Inergy, L.P. and Subsidiaries

Notes to Consolidated Financial Statements—(Continued)

The aggregate amounts of principal to be paid on the outstanding long-term debt and other long-term obligations during the next five years ending September 30 and thereafter are as follows (in millions):


	Other Obligations		Long-term debt and Notes Payable
2008	$	3.1	$	25.5
2009		5.1		3.1
2010		—		2.5
2011		—		52.3
2012		—		1.4
Thereafter		—		625.4

Total debt and other obligations	$	8.2	$	710.2

Note 7. Leases

Inergy has certain noncancelable operating leases, mainly for office space and vehicles, which expire at various times over the next ten years. Certain of these leases contain terms that provide that the rental payment be indexed to published information.

Future minimum lease payments under noncancelable operating leases for the next five years ending September 30 and thereafter consist of the following (in millions):


Year Ending September 30,
2008	$	6.7
2009		5.1
2010		3.9
2011		2.6
2012		1.8
Thereafter		3.0

Total minimum lease payments	$	23.1

Rent expense for operating leases for the years ending September 30, 2007, 2006 and 2005, totaled $9.7 million, $9.6 million and $7.9 million, respectively.

Inergy has certain related party leases as discussed in Note 11.

Note 8. Partners’ Capital

Special Units

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

109

Inergy, L.P. and Subsidiaries

Notes to Consolidated Financial Statements—(Continued)

In August 2005, Inergy also entered into a separate Registration Rights Agreement with Holdings relating to the Special Units that allows for the registered resale of the units. On February 10, 2006 the Company filed a shelf registration statement with the SEC for the resale of the common units issuable upon conversion of the Special Units. The shelf registration statement has not yet been declared effective by the SEC.

On April 25, 2007, the 769,941 Special Units converted into 919,349 common units as a result of the commercial operation of the Phase II expansion of the Stagecoach Natural Gas Storage Facility. This beneficial conversion feature present in these Special Units was valued at $10.3 million and has been recognized as a non-cash allocation of (income) to the holder of the converted units for the purpose of calculating earnings per limited partner unit.

Common Unit Offerings

On March 23, 2006, Inergy’s shelf registration statement (File No. 333-132287) was declared effective by the Securities and Exchange Commission for the periodic sale of up to $1.0 billion of common units, partnership securities and debt securities, or any combination thereof. Pursuant to the shelf registration statement, Inergy is permitted to issue these securities from time to time for general business purposes, including debt repayment, future acquisitions, capital expenditures and working capital, or for other potential uses identified in a prospectus supplement.

In June 2006, Inergy issued 4,312,500 common units, under the shelf registration statement, in a public offering, which included 562,500 common units issued as result of the underwriters exercising their over-allotment provision. The issuance of these common units resulted in net proceeds of approximately $102.7 million, after deducting underwriters’ discounts, commissions and other offering expenses. These proceeds were partially used to repay indebtedness under the Credit Agreement with the remainder used to fund capital expenditures made in connection with internal growth projects related to Inergy’s midstream assets.

In February 2007, Inergy issued 3,450,000 common units, under the shelf registration statement, which included 450,000 common units issued as a result of the underwriters exercising their over-allotment provision. The issuance of these common units resulted in net proceeds of approximately $104.5 million, after deducting underwriters’ discounts, commissions and other offering expenses. The net proceeds from this offering were used to repay indebtedness under Inergy’s Credit Agreement.

Quarterly Distributions of Available Cash

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

Distributions by Inergy in an amount equal to 100% of its Available Cash will generally be made 99% to the common and subordinated unitholders and approximately 1% to the General Partner, subject to the payment of incentive distributions to the holders of Incentive Distribution Rights to the extent that certain target levels of cash distributions are achieved. To the extent there is sufficient Available Cash, the holders of common units had the right to receive the Minimum Quarterly Distribution ($0.30 per unit), plus any arrearages, prior to any distribution of Available Cash to the holders of subordinated units.

110

Inergy, L.P. and Subsidiaries

Notes to Consolidated Financial Statements—(Continued)

Inergy is expected to make distributions of its Available Cash within 45 days after the end of each fiscal quarter ending December, March, June, and September to holders of record on the applicable record date. Inergy made distributions to unitholders, including the non-managing general partner, totaling $136.8 million, $107.6 million and $67.8 million for the years ended September 30, 2007, 2006 and 2005, respectively, or $2.28, $2.14 and $1.91 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 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, 2007, 2006 and 2005, were 8,681 units, 12,159 units and 10,496 units, respectively.

Long-Term Incentive Plan

Inergy’s managing general partner sponsors the long-term incentive plan for its employees, consultants, and directors and the employees of its affiliates that perform services for Inergy. The long-term incentive plan currently permits the grant of awards covering an aggregate of 5,000,000 common units, which can be granted in the form of unit options, phantom units and/or restricted units. With the exception of 56,000 unit options (exercise prices from $1.92 to $5.34) granted to non-executive employees in exchange for option grants made by the predecessor in fiscal 1999, all of which have been grandfathered into the long-term incentive plan and are presented as grants in the table below, all units granted under the plan will vest in accordance with the Unit Option Agreements, which typically provide that unit options begin vesting five years from the anniversary date of the applicable grant date. Shares issued as a result of unit option exercises are newly issued shares.

Restricted Units

A restricted unit is a common unit that participates in distributions and vests over a period of time yet during such time is subject to forfeiture. The compensation committee may make grants of restricted units to employees, directors and consultants containing such terms as the compensation committee determines. The compensation committee will determine the period over which restricted units granted to participants will vest. The compensation committee, in its discretion, may base its determination upon the achievement of specified financial objectives or other events. In addition, the restricted units will vest upon a change in control of the managing general partner of Inergy. If a grantee’s employment, consulting arrangement or membership on the board of directors terminates for any reason, the grantee’s restricted units will be automatically forfeited unless, and to the extent, the compensation committee or the terms of the award agreement provide otherwise.

111

Inergy, L.P. and Subsidiaries

Notes to Consolidated Financial Statements—(Continued)

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

During the 2006 fiscal year, the Company granted 58,756 restricted units. During the current fiscal year, the Company has granted an additional 69,520 restricted units. The majority of the restricted units are 100% vested on the fifth anniversary of the grant date, subject to the provisions as outlined in the restricted unit award agreement. Some of these units are subject to the achievement of certain specified performance objectives and failure to meet the performance objectives will result in forfeiture and cancellation of the restricted units. The Company recognizes expense on these units each quarter by multiplying the closing price of the Company’s common units on the date of grant by the number of units granted, and expensing that amount over the vesting period.

The compensation expense recorded by the Company related to these restricted stock awards was $0.4 million and less than $0.1 million for the years ended September 30, 2007 and 2006, respectively.

Unit Options

Unit options issued under the long-term incentive plan have an exercise price equal to the fair market value of the units on the date of the grant. In general, unit options will expire after 10 years and are subject to vesting periods as outlined in the unit option agreement. In addition, most unit option grants made under the plan provide that the unit options will become exercisable upon a change of control of the managing general partner or Inergy.

A summary of Inergy’s unit option activity for the years ended September 30, 2007, 2006 and 2005, is as follows:


	Range of Exercise Prices		Weighted- Average Exercise Price		Number of Units
Outstanding at September 30, 2004	$	1.92 – $24.71	$	13.79	1,115,064
Granted	$	27.14 – $31.32	$	28.90	95,500
Exercised		—		—	—
Canceled	$	10.00 – $27.14	$	16.80	103,000

Outstanding at September 30, 2005	$	1.92 – $31.32	$	14.81	1,107,564
Granted	$	26.20 – $26.51	$	26.27	6,500
Exercised	$	1.92 – $16.87	$	11.39	355,600
Canceled	$	15.34 – $27.14	$	18.75	46,500

Outstanding at September 30, 2006	$	8.19 – $31.32	$	16.37	711,964
Granted		—		—	—
Exercised	$	8.19 – $27.14	$	11.89	325,464
Canceled	$	13.75 – $20.13	$	19.54	56,000

Outstanding at September 30, 2007	$	13.75 – $31.32	$	20.25	330,500

Exercisable at September 30, 2007	$	13.75 – $14.95	$	14.68	68,000

112

Inergy, L.P. and Subsidiaries

Notes to Consolidated Financial Statements—(Continued)

Information regarding options outstanding and exercisable as of September 30, 2007 is as follows:


	Outstanding				Exercisable
Range of Exercise Prices	Options Outstanding	Weighted- Average Remaining Contracted Life (years)	Weighted- Average Exercise Price		Options Exercisable	Weighted- Average Exercise Price
$12.53 – $15.66	108,000	4.7	$	14.82	68,000	$	14.68
$15.66 – $18.79	78,000	5.5		16.12	—		—
$18.79 – $21.92	25,000	6.0		20.96	—		—
$21.92 – $25.06	30,000	6.5		23.94	—		—
$25.06 – $28.19	30,000	7.4		26.95	—		—
$28.19 – $31.32	59,500	7.8		29.97	—		—

	330,500	5.9	$	20.25	68,000	$	14.68

The weighted-average remaining contract lives for options outstanding and exercisable at September 30, 2007 were approximately six years and four years, respectively. The fair value of each option grant was estimated as of the grant date using the Black-Scholes option pricing model using the assumptions outlined in the table below. Expected volatility was based on a combination of historical and implied volatilities of the Company’s stock over a period at least as long as the options’ expected term. The expected life represents the period of time that the options granted are expected to be outstanding. The risk-free rate is based on the applicable U.S. Treasury yield curve in effect at the time of the grant of the share options.


	2007		2006			2005
Weighted average fair value of options granted	—		$	1.28		$	1.36
Expected volatility	0.231			0.167			0.158
Distribution yield	7.4	%		8.0	%		7.0	%
Expected life of option in years	5			5			5
Risk-free interest rate	4.2	%		4.6	%		3.5	%

The aggregate intrinsic values of options outstanding and exercisable at September 30, 2007 were $3.8 million and $1.2 million, respectively. The aggregate intrinsic value of unit options exercised during the year ended September 30, 2007 was $5.9 million. Aggregate intrinsic value represents the positive difference between the Company’s closing stock price on the last trading day of the fiscal period, which was $31.62 on September 28, 2007, and the exercise price multiplied by the number of options outstanding.

As of September 30, 2007, there was $4.4 million of total unrecognized compensation cost related to unvested share-based compensation awards granted to employees under the restricted stock and unit option plans, including approximately $1.8 million related to Holdings unvested share-based compensation awards. That cost is expected to be recognized over a five-year period.

Note 9. Employee Benefit Plans

A 401(k) plan is available to all of Inergy’s employees after meeting certain requirements. The plan permits employees to make contributions up to 75% of their salary, up to statutory limits, which was $15,500 in 2007. 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 $1.9 million, $1.8 million and $1.2 million in 2007, 2006 and 2005, respectively.

113

Inergy, L.P. and Subsidiaries

Notes to Consolidated Financial Statements—(Continued)

Of Inergy’s 2,971 employees, approximately 5% are subject to collective bargaining agreements. For the years ended September 30, 2007, 2006 and 2005, Inergy made contributions on behalf of its union employees to union sponsored defined benefit plans of $2.6 million, $2.6 million and $1.5 million, respectively.

Note 10. Commitments and Contingencies

Inergy periodically enters into agreements with suppliers to purchase fixed quantities of propane, distillates, natural gas and liquids at fixed prices. At September 30, 2007, the total of these firm purchase commitments was approximately $292.4 million and the purchases associated with these commitments will occur over the course of the next year. The Company also enters into non-binding agreements with suppliers to purchase quantities of propane, distillates, natural gas and liquids at variable prices at future dates at the then prevailing market prices.

Inergy has entered into certain purchase commitments in connection with the identified growth projects related to the Stagecoach and West Coast NGL midstream assets. At September 30, 2007, the total of these firm purchase commitments was approximately $37.9 million and the purchases associated with these commitments will occur over the course of the next year.

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

Inergy utilizes third-party insurance subject to varying retention levels of self-insurance, which management considers prudent. Such self-insurance relates to losses and liabilities primarily associated with medical claims, workers’ compensation claims and general, product, vehicle, and environmental liability. Losses are accrued based upon management’s estimates of the aggregate liability for claims incurred using certain assumptions followed in the insurance industry and based on past experience. At September 30, 2007 and 2006, Inergy’s self-insurance reserves were $13.2 million and $11.2 million, respectively.

Note 11. Related Party Transactions

In connection with the acquisition of assets from United Propane, Inc. on July 31, 2003, the Company entered into ten leases of real property formerly used by United Propane (now known as Bonavita, Inc.) in its business. Five of these leases are with United Propane, three of the leases are with Pascal Enterprises, Inc. and two with Robert A. Pascal. Each of these leases provides for an initial five-year term, and is renewable for up to two additional terms of five years each. During the initial term of these leases the Company is 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 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. On May 1, 2005 this lease was renewed and the monthly base rent was reduced to $12,500.

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

114

Inergy, L.P. and Subsidiaries

Notes to Consolidated Financial Statements—(Continued)

but would convert into common units representing limited partnership interests in Inergy at a specified conversion rate upon the commercial operation of the Stagecoach expansion project.

On occasion, Holdings reimburses the Company for expenses paid on behalf of Holdings and the Company reimburses Holdings for expenses it incurs on behalf of the Company. At September 30, 2007 Inergy had $0.1 million due from Inergy Holdings. No amount was due from Inergy Holdings at September 30, 2006.

The managing general partner and its affiliates will not receive any management fee or other compensation for the management of the Company. The managing general partner and its affiliates will be reimbursed, however, for direct and indirect expenses incurred on Inergy’s behalf. For the fiscal years ended September 30, 2007, 2006 and 2005 the expense reimbursement to the managing general partner and its affiliates was approximately $6.6 million, $8.7 million and $3.0 million, respectively, with the reimbursement related primarily to personnel costs.

Note 12. Segments

Inergy’s financial statements reflect two operating and reportable segments: propane operations and midstream operations. Inergy’s propane operations include propane sales to end users, the sale of propane-related appliances and service work for propane-related equipment, the sale of distillate products and wholesale distribution of propane and marketing and price risk management services to other users, retailers and resellers of propane. Inergy’s midstream operations include storage of natural gas for third parties, fractionation of natural gas liquids, processing of natural gas and the distribution of natural gas liquids. Results of operations for acquisitions that occurred during the year ended September 30, 2007, excluding the Bath Storage Facility and the South Lateral Pipeline, are included in the propane segment. The results of operations for the Bath Storage Facility and the South Lateral Pipeline are included in the midstream segment.

The identifiable assets associated with each reportable segment 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 primarily related to the propane segment.

115

Inergy, L.P. and Subsidiaries

Notes to Consolidated Financial Statements—(Continued)

Revenues, gross profit, identifiable assets, property, plant and equipment and goodwill for each of Inergy’s reportable segments are presented below (in millions):


	Year Ended September 30, 2007
	Propane Operations		Midstream Operations		Intersegment Operations			Corporate Assets		Total
Retail propane revenues	$	733.2	$	—	$	—		$	—	$	733.2
Wholesale propane revenues		393.8		23.4		—			—		417.2
Storage, fractionation and other midstream revenues		—		164.4		(0.5	)		—		163.9
Transportation revenues		12.3		—		—			—		12.3
Propane-related appliance sales revenues		23.0		—		—			—		23.0
Retail service revenues		16.7		—		—			—		16.7
Rental service and other revenues		24.7		—		—			—		24.7
Distillate revenues		92.1		—		—			—		92.1
Gross profit		398.3		63.1		—			—		461.4
Identifiable assets		187.1		25.6		—			—		212.7
Goodwill		261.5		85.7		—			—		347.2
Property, plant and equipment		672.4		319.1		—			8.8		1,000.3

	Year Ended September 30, 2006
	Propane Operations		Midstream Operations		Intersegment Operations			Corporate Assets		Total
Retail propane revenues	$	701.1	$	—	$	—		$	—	$	701.1
Wholesale propane revenues		351.7		19.5		—			—		371.2
Storage, fractionation and other midstream revenues		—		153.5		(0.4	)		—		153.1
Transportation revenues		10.1		—		—			—		10.1
Propane-related appliance sales revenues		23.7		—		—			—		23.7
Retail service revenues		16.7		—		—			—		16.7
Rental service and other revenues		22.5		—		—			—		22.5
Distillate revenues		91.8		—		—			—		91.8
Gross profit		357.4		42.4		—			—		399.8
Identifiable assets		192.3		15.3		—			—		207.6
Goodwill		258.5		73.9		—			—		332.4
Property, plant and equipment		654.7		185.4		—			7.8		847.9

	Year Ended September 30, 2005
	Propane Operations		Midstream Operations		Intersegment Operations			Corporate Assets		Total
Retail propane revenues	$	526.5	$	—	$	—		$	—	$	526.5
Wholesale propane revenues		305.5		19.6		—			—		325.1
Storage, fractionation and other midstream revenues		—		77.0		—			—		77.0
Transportation revenues		11.1		—		—			—		11.1
Propane-related appliance sales revenues		11.2		—		—			—		11.2
Retail service revenues		14.8		—		—			—		14.8
Rental service and other revenues		14.2		—		—			—		14.2
Distillate revenues		72.0		—		—			—		72.0
Gross profit		308.9		18.8		—			—		327.7
Identifiable assets		196.3		21.0		—			—		217.3
Goodwill		226.6		22.6		—			—		249.2
Property, plant and equipment		563.1		235.1		—			6.6		804.8

116

Inergy, L.P. and Subsidiaries

Notes to Consolidated Financial Statements—(Continued)

Note 13. Quarterly Financial Data (Unaudited)

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


	Quarter Ended
	December 31		March 31		June 30			September 30
Fiscal 2007
Revenues	$	408.3	$	553.6	$	247.7		$	273.5
Gross profit		129.7		184.3		76.7			70.7
Operating income (loss)		42.9		99.2		(8.6	)		(15.7	)
Net income (loss)		29.4		86.5		(20.6	)		(28.3	)
Net income (loss) per limited partner unit:
Basic	$	0.52	$	1.70	$	(0.77	)	$	(0.72	)
Diluted	$	0.51	$	1.70	$	(0.77	)	$	(0.72	)
Fiscal 2006
Revenues	$	450.9	$	477.7	$	216.3		$	245.3
Gross profit^(a)		113.1		152.1		66.1			68.5
Operating income (loss)		24.2		76.1		(18.8	)		(18.0	)
Net income (loss)		10.7		61.8		(32.4	)		(30.3	)
Net income (loss) per limited partner unit:^(b)
Basic	$	0.17	$	1.41	$	(0.90	)	$	(0.79	)
Diluted	$	0.17	$	1.40	$	(0.90	)	$	(0.79	)

^(a)

During 2006, gross profit reflects a non-cash loss associated with derivative contracts of approximately $20.0 million, of which $19.4 million is the reversal of the non-cash gain recorded in the quarter ended September 30, 2005, and an additional $0.6 million reflects a non-cash loss associated with derivative contracts which will reverse over the subsequent two quarters as the physical gallons are delivered to retail customers.

^(b)	The accumulation of basic and diluted net income (loss) per limited partner unit does not total the amount for the fiscal year due to changes in ownership percentages throughout the respective years.

Note 14. Subsequent Events

On October 4, 2007, Inergy acquired the assets of Riverside Oil and Gas Company headquartered in Chestertown, New York. Riverside Oil and Gas delivers retail propane to approximately 3,800 customers.

On October 5, 2007, Inergy acquired the membership interests of Arlington Storage Company, LLC (“ASC”). ASC is the majority owner and operator of the Steuben Gas Storage Company (“Steuben”), which owns a natural gas storage facility located in Steuben County, New York. In addition to Steuben, ASC owns the development rights to the Thomas Corners storage project, also located in Steuben County.

On November 14, 2007 a quarterly distribution of $0.595 per limited partner unit was paid to unitholders of record on November 7, 2007 with respect to the fourth fiscal quarter of 2007, which totaled $38.2 million.

117

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: November 28, 2007	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
November 28, 2007		/s/ JOHN J. SHERMAN John J. Sherman, President Chief Executive Officer and Director (Principal Executive Officer)

November 28, 2007		/s/ R. BROOKS SHERMAN JR. R. Brooks Sherman Jr., Executive Vice President and Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)

November 28, 2007		/s/ PHILLIP L. ELBERT Phillip L. Elbert, President and Chief Operating Officer

November 28, 2007		Warren H. Gfeller, Director

November 28, 2007		/s/ ARTHUR B. KRAUSE Arthur B. Krause, Director

November 28, 2007		/s/ ROBERT A. PASCAL Robert A. Pascal, Director

November 28, 2007		/s/ ROBERT D. TAYLOR Robert D. Taylor, Director

118

Schedule II

Inergy, L.P. and Subsidiaries

Valuation and Qualifying Accounts

(in millions)


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
2007	$	2.9	$	3.3	$	0.5	$	(3.3	)	$	3.4
2006		2.4		3.6		0.9		(4.0	)		2.9
2005		1.1		2.0		0.1		(0.8	)		2.4

119