CONTINUING TO BUILD ON OUR SOLID FOUNDATION 20 06 AN N UAL R EPORT 400 350 300 250 200 150 100 50 0 400 350 300 250 200 150 100 50 0 200 150 100 50 0 Retail Propane Gallon Sales (Gallons in Millions) Total Gross Profit ($ in Millions) Adjusted EBITDA ($ in Millions) Front cover: An Inergy employee walks through Inergy’s West Coast rail car facility in Bakersfield, California. Inside front cover: Inergy’s United Propane, based in Millersville, Maryland, serves customers in Maryland, Delaware, West Virginia and Washington, DC. The Inergy family of companies includes two separate, publicly traded securities on the NASDAQ Stock Market— Inergy, L.P. (NRGY) and Inergy Holdings, L.P. (NRGP)—which offers investors two distinct ways to invest in Inergy’s growth objectives. Inergy, L.P., headquartered in Kansas City, Missouri, serves approximately 700,000 retail propane customers throughout the eastern half of the United States while also providing logistics, transportation and wholesale marketing for propane to independent dealers and multi-state marketers in the United States and Canada. The Company’s midstream business includes a natural gas storage facility located in New York as well as a natural gas liquids gathering, processing, fractionation, storage and distribution operation located in California. Inergy Holdings, L.P., also headquartered in Kansas City, Missouri, controls the general partners of Inergy, L.P. and its assets consist solely of its ownership interest in Inergy, L.P., including limited partnership interests, special units, and the incentive distribution rights. Inergy Holdings’ primary objective is to increase distributable cash flow to its unitholders through ownership of partnership interests in Inergy, L.P. 360 318 $397 $326 $175 FY 2006 141 $123 $112 $43 FY ’04 FY ’05 Retail Propane Gallon Sales (Gallons in Millions) FY ’06 FY ’04 FY ’06 FY ’05 Total Gross Profit ($ in Millions) FY ’04 FY ’06 FY ’05 Adjusted EBITDA(a) ($ in Millions) 17% Midstream Operations 83% Propane Operations Adjusted EBITDA Mix (In Percent) (a) EBITDA is defined as income (loss) before taxes, plus net interest expense (inclusive of write-offs of deferred financing costs) and depreciation and amortization expense. 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 (one-time conversion bonuses) and equity compensation expense and (3) gains or losses on disposal of property, plant and equipment. Please refer to our SEC filings for further clarification. 418.4 $418.4 $418.4 318.4 140.7 $325.9 $123.4 $110.8 $42.8 25% section name 25% section name 50% section name FY ’04 FY ’05 FY ’06 FY ’04 FY ’05 FY ’06 FY ’04 FY ’05 FY ’06 Retail Propane Gallon Sales (Gallons in Millions) Total Gross Profit ($ in Millions) Adjusted EBITDA ($ in Millions) cash flow (in percent) Dear Fellow Unitholders: First, let me say thank you for your trust and confidence. Our management team takes very seriously our role in protecting and improving your investment in Inergy on a long-term basis. Fiscal 2006 was a tremendous year for Inergy. We significantly expanded each of our business platforms by adding high quality propane and mid- stream assets. The focused execution of our strategy added meaningful size, strength, and asset diversity, propelling the Company to record f inancial performance. Adjusted earnings before interest, taxes, depreciation, and amortization (Adjusted EBITDA) were up over 57% to $175.4 million. Distributable cash flow increased to approximately $119 million from $75 million in 2005. These results allowed us to declare our 20th consecutive quarterly increase in our cash distribution at Inergy, L.P. (NRGY) and to increase the cash distribution at Inergy Holdings (NRGP) in each full quarter since the IPO in 2005. This performance builds on our long- term track record of delivering consis- tent results and growth while improving the quality and stability of our overall business. We have accomplished all of this while adding to the strength of our balance sheet. This strong position will continue to be impor tant going forward as we execute our growth strategy through organic growth projects and additional acquisitions. In our core propane business, we announced the Company’s 50th acqui- sition early in the year. We quickly fol- lowed with the acquisition of Dowdle Gas, the 12th largest propane marketer in the country. The expansion of our retail propane platform continued throughout the year with a total of ten acquisitions, all meeting our disciplined criteria, expanding our geographic foot- print in solid markets. The retail propane market remains fragmented and is consolidating. We believe Inergy will lead the industry’s consolidation in the future as we are well positioned to acquire more high quality propane businesses at values that are attractive to us as investors. Our midstream growth strategy really hit its stride in 2006. In the first season of owning and operat- ing Stagecoach, our natural gas storage business in the Northeast, we exceeded all of our initial expectations from both a financial and operating standpoint. The fundamentals of this business are very strong, and we are expanding our view of its potential as a growth platform. The Stagecoach expansion project has progressed ahead of expectation as well. We are doubling the size of our storage facility from 13 billion cubic feet (BCF) of working gas capacity to more than 26 BCF. When we conducted an “open season” and took indications of interest for new capacity, the response was overwhelming. We received interest exceeding several times our storage and deliverability capacity. Construction is ahead of schedule, and we expect to be fully operational in late summer 2007. We are acquiring the 24 mile lateral pipeline connecting Stagecoach to the Tennessee Gas Pipeline Company’s line 300. The Company has also been granted approval to connect to the Millennium Pipeline project once it is in service. When these projects are completed, Stagecoach will be even more valuable and a very strategic component of the natural gas storage and transmission infrastructure in the Northeast. In our natural gas liquids business, we acquired a 1.2 million barrel propane and butane storage cavern in Bath, New York. This facility complements our propane business. We have already increased the capacity of both our truck ’01 2001 Following a series of strategic acquisitions, Inergy files for an Initial Public Offering. The Company successfully completes its IPO, representing 1.84M common units priced at $22.00 per common unit. Inergy is named by The Wall Street Journal as one of the Top Performing IPO’s of the year. and rail car capabilities. This facility is expandable and because of its proxim- ity to Stagecoach, we are evaluating making it part of our natural gas expan- sion plans. Over the last three years, Inergy has been transformed from a regionally ori- ented propane company into a broad, diversified energy infrastructure and distribution company. Our West Coast natural gas liquids business continues to exceed expecta- tions, and we are in the midst of signifi- cant expansion. In March we announced plans to construct a butane isomeri- zation unit, add storage capacity and build ancillary pipeline facilities. We anticipate these projects will be placed in service by spring 2008. Our strategic location in Bakersfield, California, pro- vides a competitive advantage in serv- ing our West Coast customers. All of these expansion projects are expected to be meaningfully accretive to NRGY and NRGP and should pro- vide steady growth in cash earnings through 2008. As a major propane marketer, we have broad geographic diversity. The Company operates from a position of strength with distinct competitive advantages. Our decentralized operating model, led by outstanding professionals, leads to better and quicker decision-making as it relates to making money for investors and serving customers. Our successful transition and diversifi- cation into the midstream sector has been executed with great discipline and focus. We added talented people with expertise and track records of success in these businesses; we acquired high-quality, long-term fee-based assets at good values in a very competitive acquisition market; integrated those operations; and immediately initiated high-return organic growth projects around those acquisitions. As investors, we now have access to multiple growth platforms. Our objectives, when we committed to a more diversified business mix, were simple: • add further stability to our cash flows; • lower our cost of capital as a result of an improved business mix; and • most importantly, greatly expand the long-term growth potential of the Company. We have executed these impor tant strategic objectives, the capital markets are beginning to recognize the value, and I expect that we will all benefit as investors as we continue to expand the platform in the future. The expansion of Inergy’s Stagecoach natural gas storage facility is expected to double its storage capacity. This project is well underway and ahead of schedule. We anticipate a commercial in-service date in late summer 2007. With an exceptionally strong demand for natural gas in the Northeast, the return on our investment in Stagecoach has exceeded our expectations. 2002 Inergy increases its cash distributions to unitholders in each quarter, and completes two significant acquisitions which more than double its retail customer base. 2003 The Company continues to deliver industry-leading returns. With the completion of twelve acquisitions, Inergy’s one-year total return to unitholders is 87 percent, and its total return since the IPO is 152 percent. Clearly, none of this would be possible without the commitment of an excep- tional team of people. Our manage- ment team and entire workforce have done an outstanding job on your behalf. They are aligned with investors and act as owners do—making daily decisions, big and small, based on maximizing the value of the Company for our unithold- ers. We operate in a performance-based culture that does not value excuses. Our employees are valued and we will continue to provide opportunities to develop their careers and reward them when they achieve your objectives. Looking forward, we are very focused on continued execution of our strategy and taking advantage of our multiple growth platforms. We intend to: • further develop our outstanding pro- pane franchise and grow through acquisition of good companies in good markets; • execute our midstream organic growth projects with a sense of urgency and grow through acquisi- tions where it makes sense; • expand our access to the capital markets with two valuable securities and positive momentum in the debt markets; • protect the stability of your cash dis- tribution, maintain a strong balance sheet, and continue to grow cash earnings over time; and • develop and add talent to our employee team—they are the key to getting the job done. We are pleased to report to you on another year of progress and develop- ment. We have many challenges and opportunities before us. We need to be smart, flexible, and make informed business decisions on your behalf. We think we are building a company equipped to excel in the current envi- ronment. We look forward to meeting the high expectations you have for us. Thank you again for your confidence and trust. John J. Sherman President and CEO INDUSTRY- LEADING TOTA L RETUR NS ( IN P ER CE NT ) 350 300 250 200 150 100 50 0 -50 7/25/01 7/26/01 7/27/01 7/30/01 7/31/01 8/10/01 8/13/01 8/14/01 8/15/01 8/16/01 8/17/01 8/20/01 8/21/01 8/22/01 8/23/01 8/24/01 8/27/01 8/28/01 8/29/01 8/30/01 8/31/01 9/10/01 9/11/01 9/12/01 9/13/01 9/14/01 9/17/01 9/18/01 9/19/01 9/20/01 9/21/01 10/10/01 10/11/01 10/12/01 10/15/01 10/16/01 10/17/01 10/18/01 10/19/01 10/22/01 10/23/01 10/24/01 10/25/01 10/26/01 10/29/01 10/30/01 10/31/01 11/12/01 11/13/01 11/14/01 11/15/01 11/16/01 11/19/01 11/20/01 11/21/01 11/22/01 11/23/01 11/26/01 11/27/01 11/28/01 11/29/01 11/30/01 12/10/01 12/11/01 12/12/01 12/13/01 12/14/01 12/17/01 12/18/01 12/19/01 12/20/01 12/21/01 12/24/01 12/25/01 12/26/01 12/27/01 12/28/01 12/31/01 11/9/01 11/8/01 11/7/01 11/6/01 11/5/01 11/2/01 11/1/01 9/28/01 9/27/01 9/26/01 9/25/01 9/24/01 1/16/02 1/15/02 1/14/02 1/11/02 1/10/02 12/4/01 10/4/01 10/1/01 10/9/01 12/5/01 10/5/01 12/7/01 12/6/01 10/8/01 10/2/01 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Inergy Holdings, L.P. S&P 500 Alerian MLP Index - AMZK 350 300 250 200 150 100 50 0 -50 Inergy, L.P. Inergy Holdings, L.P. S&P 500 Alerian MLP Index–AMZK +301.7% +140.7% +87.1% +31.0% Jul-01 Aug-02 Sep-03 Oct-04 Nov-05 Dec-06 2004 Inergy acquires its f irst midstream operation, a natural gas liquids (NGL) business on the West Coast. The Company’s stock splits two-for-one. 2005 Inergy doubles in size by acquiring the propane operations of Star Gas Partners. The Company also acquires a natural gas storage operation in New York. The initial public offering for Inergy Holdings, L.P. (NRGP) is completed. INERGY OPERATIONS With the Company’s most recent acquisitions, today Inergy serves approximately 700,000 customers from more than 340 customer service centers. The Company’s propane and midstream operations are identified on the map below. Retail Propane Locations West Coast NGL Operations Stagecoach Natural Gas Storage Facility Bath, NY LPG Storage Facility Inergy’s Stagecoach natural gas storage facility is located approximately 150 miles northwest of New York City. The operation is in the midst of expansion and is a significant participant in the northeast United States natural gas distribution system. 2006 Inergy completes its 59th acquisition, bringing the number of retail customers it serves to more than 700,000. The Company announces significant expansion of its midstream platform, and as a result of its financial performance, is named to the Standard & Poor’s Global Challenger’s List of companies poised to emerge as challengers to the world’s leading blue-chip companies. ’06 UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K (Mark One) È ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended September 30, 2006 OR ‘ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from to . Commission file number: 000-32453 INERGY, L.P. (Exact name of registrant as specified in its charter) Delaware (State or other jurisdiction of incorporation or organization) 43-1918951 (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 NASDAQ Stock Market, LLC 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 È 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 È 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 È 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. È 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 È 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 È The aggregate market value of the 38,830,483 common units of the registrant held by non-affiliates computed by reference to the $29.41 closing price of such common units on November 1, 2006, was approximately $1.1 billion. The aggregate market value of the 31,527,643 common units of the registrant held by non-affiliates computed by reference to the $26.75 closing price of such common units on March 31, 2006, the last business day of the registrant’s most recently completed second fiscal quarter, was approximately $843.4 million. As of November 20, 2006, the registrant had 45,192,483 common units outstanding. Portions of the following documents are incorporated by reference into the indicated parts of this report: None. DOCUMENTS INCORPORATED BY REFERENCE GUIDE TO READING THIS REPORT The following information should help you understand some of the conventions used in this report. • Throughout this report, (1) when we use the terms “we,” “us,” “our company,” “Inergy,” or “Inergy, L.P.,” we are referring either to Inergy, L.P., the registrant itself, or to Inergy, L.P. and its operating subsidiaries collectively, as the context requires. (2) when we use the term “our predecessor,” we are referring to Inergy Partners, LLC, the entity that conducted our business before our initial public offering, which closed on July 31, 2001. Inergy, L.P. was formed as a Delaware limited partnership on March 7, 2001 and did not have operations until the closing of our initial public offering. Our predecessor commenced operations in November 1996. The discussion of our business throughout this report relates to the business operations of Inergy Partners, LLC before Inergy, L.P.’s initial public offering and of Inergy, L.P. thereafter. (3) when we use the term “Inergy Propane” we are referring to Inergy Propane, LLC itself, or to Inergy Propane, LLC and its operating subsidiaries collectively, as the context requires. (4) when we use the term “finance company” we are referring to Inergy Finance Corp., a subsidiary of Inergy, L.P., formed on September 21, 2004. (5) when we use the term “managing general partner,” we are referring to Inergy GP, LLC. (6) when we use the term “non-managing general partner,” we are referring to Inergy Partners, LLC. (7) when we use the term “general partners,” we are referring to our managing general partner and our non- managing general partner. (8) when we use the term “Inergy Holdings” we are referring to Inergy Holdings, L.P. (NASDAQ symbol NRGP) itself, or to Inergy Holdings, L.P. and its subsidiaries collectively, as the context requires. • We have a managing general partner and a non-managing general partner. Our managing general partner is responsible for the management of our company and its operations are governed by a board of directors. Our managing general partner does not have rights to allocations or distributions from our company and does not receive a management fee, but it is reimbursed for expenses incurred on our behalf. Our non-managing general partner owns an approximate 1% non-managing general partner interest in our company. INERGY, L.P. INDEX TO ANNUAL REPORT ON FORM 10-K PART I Item 1. Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Item 1A. Risk Factors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Item 1B. Unresolved Staff Comments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Item 2. Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Item 3. Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Item 4. Submission of Matters to a Vote of Security Holders . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . PART II Item 5. Market for the Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Item 6. Selected Financial Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations . . . . Item 7A. Quantitative and Qualitative Disclosures about Market Risk . . . . . . . . . . . . . . . . . . . . . . . . . . . . Item 8. Financial Statements and Supplementary Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure . . . . Item 9A. Controls and Procedures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Item 9B. Other Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . PART III Item 10. Directors and Executive Officers of the Registrant . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Item 11. Executive Compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Item 13. Certain Relationships and Related Transactions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Item 14. Principal Accountant Fees and Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . PART IV Page 1 15 27 27 27 27 28 29 32 52 54 54 54 55 56 60 64 67 68 Item 15. Exhibits and Financial Statement Schedules . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 69 PART I Item 1. Business. Recent Developments Effective on October 1, 2006, we acquired Bath Storage Facility, located in Bath, NY, a liquefied petroleum gas (“LPG”) storage facility from Bath Petroleum Storage, Inc. Bath Storage is a 1.2 million barrel salt cavern storage facility located near Bath, New York, approximately 210 miles northwest of New York City and 60 miles from Inergy’s 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. Bath Storage is a demand driven, fee-based storage facility. On October 6, 2006, we acquired the assets of Columbus Butane Company, Inc. , and related companies (Columbus Butane) headquartered in Columbus, MS. At the time of acquisition, Columbus Butane delivered retail propane to over 15,000 customers from 13 retail locations. On October 31, 2006, Inergy acquired the assets of Hometown Propane, Inc. headquartered in Campbell, NY and on November 8, 2006, Inergy acquired the assets of Mideastern Oil Company, Inc. headquartered in Salisbury, MD. At the time of acquisition, each company delivered retail propane to over 800 customers. General Inergy, L.P., a publicly traded Delaware limited partnership, was formed on March 7, 2001 but did not conduct operations until the closing of our initial public offering on July 31, 2001. We own and operate, principally through Inergy Propane, LLC, a rapidly growing, geographically diverse retail and wholesale propane supply, marketing and distribution business. We also operate a midstream business that includes a natural gas storage facility (“Stagecoach”) and a natural gas liquids (“NGL”) business. Since our predecessor’s inception in November 1996 through September 30, 2006, we have acquired the assets and liabilities of 59 companies for an aggregate purchase price of approximately $1.4 billion, including working capital, assumed liabilities and acquisition costs. The acquisitions include the assets and liabilities of ten propane companies acquired during fiscal 2006 for an aggregate purchase price of approximately $186.3 million. For the fiscal year ended September 30, 2006, we sold and physically delivered approximately 360.3 million gallons of propane to retail customers and approximately 365.3 million gallons of propane to wholesale customers. The address of our principal executive offices is Two Brush Creek Boulevard, Suite 200, Kansas City, Missouri, 64112 and our telephone number at this location is 816-842-8181. Our common units trade on the NASDAQ National Market under the symbol “NRGY”. We electronically file certain documents with the Securities and Exchange Commission (“SEC”). We file annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K (as appropriate), along with any related amendments and supplements. From time-to-time, we also may file registration and related statements pertaining to equity or debt offerings. You may read and download our SEC filings over the internet from several commercial document retrieval services as well as at the SEC’s website at www.sec.gov. You may also read and copy our SEC filings at the SEC’s public reference room located at Judiciary Plaza, 450 Fifth Street, N.W., Washington, D.C. 20549. Please call the SEC 1-800-SEC-0330 for further information concerning the public reference room and any applicable copy charges. In addition, our SEC filings are available at no cost 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, 1 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 including, among others: Arrow Gas, Blue Flame, Bradley Propane, Burnwell Gas, Country Gas, Dowdle Gas, Gaylord Gas, Hancock Gas, Highland Propane, Hoosier Propane, Independent Propane, Maingas, McCracken, Modern Gas, Moulton Gas Service, Northwest Energy, Ohio Gas, Pearl Gas, Pro Gas, Pulver Gas, United Propane, and Tru-Gas. As of November 1, 2006 we serve approximately 700,000 retail customers in Alabama, Arkansas, Connecticut, Florida, Georgia, Illinois, Indiana, Kentucky, Maine, Maryland, Massachusetts, Michigan, Mississippi, New Hampshire, New Jersey, New York, North Carolina, Ohio, Oklahoma, Pennsylvania, Rhode Island, South Carolina, Tennessee, Texas, Vermont, Virginia, West Virginia, and Wisconsin from 341 customer service centers which have an aggregate of approximately 30.6 million gallons of above-ground propane storage capacity. In addition to our retail propane business, we operate a wholesale supply, marketing and distribution business, providing propane procurement, transportation and supply and price risk management services to our customer service centers, as well as to independent dealers, multistate marketers, petrochemical companies, refinery and gas processors and a number of other NGL marketing and distribution companies in 40 states, primarily in the Midwest, Northeast and 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 13.25 bcf of working gas capacity, a maximum withdrawal capability of 500 MMcf/day, and a maximum injection capability of 250 MMcf/day. The facility is fee-based and is currently 100% committed primarily with investment grade-rated companies with term contracts that have a weighted average maturity extending to April 2010. Located 150 miles northwest of New York City, the Stagecoach facility is among the closest natural gas storage facilities to the northeastern United States market. Stagecoach is connected to Tennessee Gas Pipeline Company’s 300-Line. an NGL business in Bakersfield, California, which includes natural gas processing, NGL fractionation, NGL rail and truck terminals, bulk storage, trucking and marketing operations. the Bath Storage Facility, a liquefied petroleum gas (“LPG”) storage facility with a 1.2 million barrel salt cavern storage facility located near Bath, New York, approximately 210 miles northwest of New York City and 60 miles from Inergy’s 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. Including our initial acquisition of McCracken Oil & Propane Company in 1996, and through September 30, 2006, we have completed 59 acquisitions (including two midstream businesses) in numerous states. Effective December 1, 2004, we closed on the purchase of Star Gas Propane, L.P., (“Star Gas”) our largest acquisition. When acquired, Star Gas was servicing approximately 345,000 customers from approximately 120 customer service centers in the Midwest, Northeast, Florida, and Georgia. The following chart sets forth information about each business we acquired during the fiscal year ended September 30, 2006 and through the date of this filing: Acquisition Date October 2005 October 2005 October 2005 January 2006 March 2006 April 2006 July 2006 July 2006 Company Location Atlas Gas Products, Inc. Dowdle Gas, Inc. Graeber Brothers, Inc. Propane Gas Services, Inc. Delta Gas Company Homestead Gas Company Firelands Propane Deyo’s Fuel 2 Costonia, OH Columbus, MS Batesville, MS South Windsor, CT Miami, FL Homestead, FL Ashland, OH Ticonderoga, NY Acquisition Date September 2006 September 2006 Company Location Country Gas, Inc. Fisher’s Hoosier Propane Sumiton, AL Albany, NY Acquisitions after September 30, 2006 October 2006 October 2006 October 2006 November 2006 Bath Storage Facility Columbus Butane Company, Inc. Hometown Propane, Inc. Mideastern Oil Company, Inc. Bath, NY Columbus, MS Campbell, NY Salisbury, MD 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 3 for approximately 41% of the total retail sales of propane in the United States, and that no single marketer has a greater than 10% share of the total retail market in the United States. Most of our customer service centers compete with several marketers or distributors. Each customer service center operates in its own competitive environment because retail marketers tend to locate in close proximity to customers. Our typical customer service center generally has an effective marketing radius of approximately 25 miles, although in certain rural areas the marketing radius may be extended by a satellite location. The ability to compete effectively further depends on the reliability of service, responsiveness to customers and the ability to maintain competitive prices. We believe that our safety programs, policies and procedures are more comprehensive than many of our smaller, independent competitors and give us a competitive advantage over such retailers. We also believe that our service capabilities and customer responsiveness differentiate us from many of these smaller competitors. Our employees are on call 24-hours and seven-days-a-week for emergency repairs and deliveries. Retail propane distributors typically price retail usage based on a per gallon margin over wholesale costs. As a result, distributors generally seek to maintain their operating margins by passing costs through to customers, thus insulating themselves from volatility in wholesale propane prices. During periods of sudden price increases in propane at the wholesale level, distributors may be unable or unwilling to pass entire cost increases through to customers. In these cases, significant decreases in per gallon margins may result. The propane distribution industry is characterized by a large number of relatively small, independently owned and locally operated distributors. Each year, a significant number of these local distributors have sought to sell their business for reasons that include, among others, retirement and estate planning. In addition, the propane industry faces increasing environmental regulations and escalating capital requirements needed to acquire advanced, customer-oriented technologies. Primarily as a result of these factors, the industry is undergoing consolidation, and we, as well as other national and regional distributors, have been active consolidators in the propane market. In recent years, an active, competitive market has existed for the acquisition of propane assets and businesses. We expect this acquisition market to continue for the foreseeable future. The wholesale propane business is highly competitive. Our competitors in the wholesale business include producers and independent regional wholesalers. We believe that our wholesale supply and distribution business provides us with a stronger regional presence and a reasonably secure, efficient supply base, and positions us well for expansion through acquisitions or start-up operations in new markets. Midstream We own, as part of our midstream operations, a high-performance, multi-cycle natural gas storage facility (Stagecoach) in New York which we acquired in August 2005. We also own a natural gas liquids business in California, which includes natural gas processing, NGL fractionation, NGL rail and truck terminals, bulk storage, trucking and marketing operations. We believe these businesses complement our existing wholesale and supply operations and provide us with added long-term strategic benefits. Natural Gas Storage Business According to the National Petroleum Council’s 2003 report Balancing Natural Gas Policy, natural gas supplies approximately 25% of U.S. energy, generating about 19% of electric power, supplying heat to over 60 million households, and providing over 40% of all primary energy for industries. In recent years there has been a fundamental shift in the natural gas supply and demand balance that has resulted in higher and more volatile prices. This is due in part to the following factors: • • the growing demand by more seasonal users such as the residential/commercial and the power generation customer segments; and conflicts in public policy that in certain instances prohibit or limit the exploration and access to gas-prone areas and hinder the pipeline and infrastructure development. 4 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 2025. Most forecasts of North American natural gas supply and demand suggest a continuation of trends that will result in increased demand for natural gas storage capacity. Seasonal and weather sensitive demand sectors (residential and commercial heating demand and gas-fired power generation demand) have been growing and are expected to continue to do so, while the less seasonal industrial demand has been declining. Natural gas supply, meanwhile, has become almost entirely non-seasonal, requiring greater reliance on natural gas storage to respond to demand variability. On average, total North American natural gas consumption levels are approximately 40% higher in the winter months than summer months primarily due to the requirements of residential and commercial market sectors. These markets are very temperature sensitive with demand being highly variable both on a seasonal and a daily basis thus requiring that storage be capable of providing high maximum daily deliverability on the coldest days when storage due to infrastructure constraints provides as much as 50% of the market’s total requirement. Analysis has shown that seasonal winter demand has continued to show steady growth even though warmer winter temperature trends have muted the full impact of this increasing demand. Gas storage has facilitated the creation of a natural gas industry that is characterized by a production profile that is largely non-seasonal and a consumption profile that is highly seasonal and weather sensitive. Natural gas storage is essential in reallocating this inherent supply and demand imbalance. In the natural gas storage business, there are significant barriers to entry, particularly in depleted reservoir storage such as the Stagecoach facility. Barriers include: Geology: rock quality, depth, containment and reservoir size heavily influence development opportunities; Geography: proximity to existing pipeline infrastructure, surface development, and complicated land ownership all combine to further increase the difficulty in developing and operating natural gas storage facilities; Specialized skills: finding and retaining qualified and skilled natural gas storage professionals is a challenge in today’s competitive job market in the oil & gas sectors due to the specialized nature of the skills required; and Development costs: costs for new natural gas storage capacity development have continued to increase. Although there are significant barriers to entry within the natural gas storage industry, competition is robust. Competition for natural gas storage is primarily based on location, connectivity, and the ability to deliver natural gas in a timely and reliable manner. Our natural gas storage facility competes with other means of natural gas storage, including other depleted reservoir facilities, salt dome storage facilities, and liquefied natural gas and pipelines. Storage capacity is held by a wide variety of market participants for a variety of purposes such as: Reliability: local distribution companies (“LDCs”) hold the bulk of capacity and tend to use it in a manner relatively insensitive to gas prices, injecting gas into storage during the summer to meet fairly well-defined 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). 5 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. Natural gas processing separates, for the most part, the NGLs from the methane, and delivers the methane to the local natural gas pipelines. NGLs are retained for further processing within our fractionation facility. NGL fractionation facilities separate mixed NGL streams into discrete NGL products: ethane, propane, normal butane, isobutane, and natural gasoline. The three primary sources of mixed NGLs fractionated in the United States are (i) domestic natural gas processing plants, (ii) domestic crude oil refineries and (iii) imports of butane and propane mixtures. The mixed NGLs delivered from domestic natural gas processing plants and crude oil refineries to our NGL fractionation facility are typically transported by NGL pipelines and, to a lesser extent, by railcar and truck. NGL products (ethane, propane, normal butane, isobutane and natural gasoline) are typically used as raw materials by the petrochemical industry, feedstocks by refiners in the production of motor gasoline and by industrial and residential users as fuel. Ethane is primarily used in the petrochemical industry as feedstock for ethylene production, one of the basic building blocks for a wide range of plastics and other chemical products. Propane is used both as a petrochemical feedstock in the production of ethylene and propylene and as a heating, engine and industrial fuel. Normal butane is used as a petrochemical feedstock in the production of ethylene and butadiene (a key ingredient of synthetic rubber), as a blendstock for motor gasoline and to derive isobutane through isomerization. Isobutane is fractionated from mixed butane (a mixed stream of normal butane and isobutane) or produced from normal butane through the process of isomerization, principally for use in refinery alkylation to enhance the octane content of motor gasoline, in the production of iso-octane, and in the production of propylene oxide. Natural gasoline, a mixture of pentanes and heavier hydrocarbons, is primarily used as a blendstock for motor gasoline or as a petrochemical feedstock. Our NGL business located near Bakersfield, CA encounters competition from fully integrated oil companies, and independent NGL market participants. Each of our competitors has varying levels of financial and personnel resources, and competition generally revolves around price, service and location. The majority of our NGL processing and fractionation activities are processing mixed NGL streams for third-party customers and to support our NGL marketing activities under fee-based arrangements. These fees (typically in cents per gallon) are subject to adjustment for changes in certain fractionation expenses, including natural gas fuel costs. Our integrated midstream energy asset system affords us flexibility in meeting our customers’ needs. While many companies participate in the natural gas processing business, few have a presence in significant downstream activities such as NGL fractionation and transportation, and NGL marketing as we do. Our competitive position and presence in these downstream businesses allow us to extract incremental value while offering our customers enhanced services, including comprehensive service packages. 6 Business Strategy Our primary objective is to increase distributable cash flow for our unitholders, while maintaining the highest level of commitment and service to our customers. We intend to pursue this objective by capitalizing on what we believe are our competitive strengths as follows: Proven Acquisition Expertise Since our predecessor’s inception and through September 30, 2006, we have acquired and successfully integrated 59 companies—57 propane companies and 2 midstream businesses. Our executive officers and key employees, each of whom average more than 15 years experience in the propane and energy-related industries, have developed business relationships with retail propane owners and businesses as well as other midstream industry participants throughout the United States. These significant industry contacts have enabled us to negotiate most of our acquisitions on an exclusive basis. We believe that this acquisition expertise should allow us to continue to grow through strategic and accretive acquisitions. Our acquisition program will continue to seek: • businesses that generate distributable cash flow that is accretive to Inergy common unitholders on a per unit basis; • midstream businesses that generate predictable, stable fee-based cash flow streams; • • • • propane and midstream businesses in attractive market areas; propane businesses with established names with reputations for customer service and reliability; propane businesses with high concentration of propane sales to residential customers; and retention of key employees in acquired businesses. High Percentage of Retail Sales to Residential Customers Our retail propane operations concentrate on sales to residential customers. Residential customers tend to generate higher margins and are generally more stable purchasers than other customers. For the fiscal year ended September 30, 2006, 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. Regional Branding We believe that our success in maintaining customer stability at our customer service centers results from our operation under established, locally recognized trade names. We attempt to capitalize on the reputation of the companies we acquire by retaining their local brand names and employees, thereby preserving the goodwill of the acquired business and fostering employee loyalty and customer retention. We expect our local branch management to continue to manage our marketing programs, new business development, customer service and customer billing and collections. We believe that our employee incentive programs encourage efficiency and allow us to control costs at the corporate and field levels. Operations in Attractive Propane Markets A majority of our propane operations are concentrated in attractive propane market areas, where natural gas distribution is not cost-effective, margins are relatively stable, and tank control is relatively high. We intend to pursue acquisitions in similar attractive markets. 7 Strong Wholesale Supply, Marketing and Distribution Business One of our distinguishing strengths is our procurement and distribution expertise and capabilities. For the fiscal year ended September 30, 2006, we delivered approximately 365.3 million gallons of propane on a wholesale basis to independent dealers, multistate marketers, petrochemical companies, refinery and gas processors and a number of other NGL marketing and distribution companies. These operations are significantly larger on a relative basis than the wholesale operations of most publicly traded propane businesses. We also provide transportation services to these distributors through our fleet of transport vehicles, and price risk management services to our customers through a variety of financial and other instruments. The presence of our trucks serving our wholesale customers allows us to take advantage of various pricing and distribution inefficiencies that exist in the market from time to time. We believe our wholesale business enables us to obtain valuable market intelligence and awareness of potential acquisition opportunities. Because we sell on a wholesale basis to many residential and commercial retailers, we have an ongoing relationship with a large number of businesses that may be attractive acquisition opportunities for us. We believe that we will have an adequate supply of propane to support our growing retail operations at prices that are generally available only to large wholesale purchasers. This purchasing scale and resulting expertise also helps us avoid shortages during periods of tight supply to an extent not generally available to other retail propane distributors. Flexible Financial Structure We have a $350 million revolving credit facility for acquisitions and a $75 million revolving working capital facility. As of November 1, 2006, we had available capacity of approximately $328.5 million under our facilities. We believe our available capacity under these facilities combined with our ability to fund acquisitions through the issuance of additional partnership interests will provide us with a flexible financial structure that will facilitate our acquisition strategy. Operations Our operations reflect our two reportable segments: propane operations and midstream operations. Propane Operations Retail Propane Customer Service Centers At November 1, 2006, we distribute propane to approximately 700,000 retail customers from 341 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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Arkansas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Connecticut . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Florida . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Georgia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Illinois . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Indiana . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Kentucky . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Maine . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Maryland . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47 3 3 20 5 4 27 2 4 10 8 State Massachusetts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Michigan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Mississippi . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . New Hampshire . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . New Jersey . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . New York . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . North Carolina . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Ohio . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Oklahoma . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Pennsylvania . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Rhode Island . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . South Carolina . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Tennessee . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Texas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Vermont Virginia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . West Virginia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Wisconsin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Number of Customer Service Centers 5 32 37 3 4 11 10 25 3 8 1 3 10 35 9 8 3 9 Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 341 From our customer service centers, we also sell, install and service equipment related to our propane distribution business, including heating and cooking appliances. Typical customer service centers consist of an office and service facilities, with one or more 12,000 to 30,000 gallon bulk storage tanks. Some of our customer service centers also have an appliance showroom. We have several satellite facilities that typically contain only large capacity storage tanks. As of November 1, 2006 we have approximately 30.6 million gallons of above- ground propane storage capacity at our customer service centers and satellite locations. Customer Deliveries Retail deliveries of propane are usually made to customers by means of our fleet of bobtail and rack trucks. Propane is pumped from the bobtail truck, which generally holds 2,500 to 3,000 gallons, into a stationary storage tank at the customer’s premises. The capacity of these tanks ranges from 100 gallons to 1,200 gallons, with a typical tank having a capacity of 100 to 300 gallons in milder climates and 500 to 1,000 gallons in colder climates. We also deliver propane to retail customers in portable cylinders, which typically have a capacity of five to thirty-five gallons. These cylinders typically are picked up by us and replenished at our distribution locations, then returned to the retail customer. To a limited extent, we also deliver propane to certain customers in larger trucks known as transports, which have an average capacity of approximately 10,000 gallons. These customers include industrial customers, large-scale heating accounts and large agricultural accounts. During the fiscal year ended September 30, 2006, 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 23% to industrial and commercial customers; and approximately 8% to agricultural customers. No single retail customer accounted for more than 1% of our revenue during the fiscal year ended September 30, 2006. 9 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 nearly 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, however, can significantly affect the total volumes of propane we sell and the margins we realize and, consequently, our results of operations. We believe that sales to the commercial and industrial markets, while affected by economic patterns, are not as sensitive to variations in weather conditions as sales to residential and agricultural markets. Transportation Assets, Truck Fabrication and Maintenance Our transportation assets are operated by L&L Transportation, LLC, a wholly-owned subsidiary of Inergy Propane. The transportation of propane requires specialized equipment. Propane trucks carry specialized steel tanks that maintain the propane in a liquefied state. As of September 30, 2006, we owned a fleet of approximately 129 tractors, 219 transports, 1,158 bobtail and rack trucks and 644 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 fabrication and maintenance facilities located in Indiana, Florida, and Texas. We also have a trucking operation located in California as part of our NGL business. We believe that our ability to build and maintain the trucks we use in our propane operations significantly reduces the costs we would otherwise incur in purchasing and maintaining our fleet of trucks. Pricing Policy Our pricing policy is an essential element in our successful marketing of propane. We base our pricing decisions on, among other things, prevailing supply costs, local market conditions and local management input. We rely on our regional management to set prices based on these factors. Our local managers are advised regularly of any changes in the posted prices of our propane suppliers. We believe our propane pricing methods 10 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 27% of total revenue, this business represented approximately 3% of our gross profit during the fiscal year ended September 30, 2006. Marketing and Distribution One of our distinguishing strengths is our procurement and distribution expertise and capabilities. Because of the size of our wholesale operations, we have developed significant procurement and distribution expertise. This is partly the result of the unique background of our management team, which has significant experience in the procurement aspects of the propane business. We also offer transportation services to these distributors through our fleet of transport trucks and price risk management services to our customers through a variety of financial and other instruments. Our wholesale supply, marketing and distribution business provides us with an additional income stream as well as extensive market intelligence and acquisition opportunities. In addition, these operations provide us with more secure supplies and better pricing for our customer service centers. Moreover, the presence of our trucks across the Midwest and Southeast allows us to take advantage of various pricing and distribution inefficiencies that exist in the market from time to time. 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, 2006, a majority of our sales volume was purchased pursuant to contracts that have a term of one year; the balance of our sales volume 11 was purchased on the spot market. The percentage of our contract purchases varies from year to year. Supply contracts generally provide for pricing in accordance with posted prices at the time of delivery or the current prices established at major storage points, and some contracts include a pricing formula that typically is based on such market prices. Some of these agreements provide maximum and minimum seasonal purchase guidelines. Two suppliers, Sunoco, Inc. (14%) and Exxon Mobil Oil Corp. (11%), accounted for approximately 25% of propane purchases during the past fiscal year. We believe our contracts with these suppliers will enable us to purchase most of our supply needs at market prices and ensures adequate supply. No other single supplier accounted for more than 10% of our propane purchases in the current year. Propane generally is transported from refineries, pipeline terminals, storage facilities and marine terminals to our approximately 600 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 futures transactions on the New York Mercantile Exchange and to forward and option contracts with various third parties to purchase and sell propane at fixed prices in the future. We monitor these activities through enforcement of our risk management policy. Midstream Operations Our natural gas storage facility (Stagecoach) was acquired on August 9, 2005 and is a high performance, multi-cycle natural gas storage facility with approximately 13.25 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. We are currently working on an expansion of our Stagecoach facility, which is expected to increase our working storage capacity of natural gas to approximately 26.35 bcf through the addition of approximately 13.1 bcf of storage to our existing 13.25 bcf working storage capacity. All necessary regulatory approvals have been received and construction of the expansion is underway. The expanded facilities are expected to be in service by fall of 2007. 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. 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. For more information on our reportable business segments, see Note 12 to our Consolidated Financial Statements. Employees As of November 1, 2006, we had 2,908 full-time employees and 113 part-time employees. Of the 3,021 employees, 107 were general and administrative and 2,914 were operational. Of the operational employees, 155 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 12 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. This federal and state regulation extends to such matters as: • • • • • • rate structures; rates of return on equity on invested capital; recovery of costs associated with providing services; the services that our regulated assets are permitted to perform; the acquisition, construction and disposition of assets; and to an extent, the level of competition in that regulated industry. Under the Natural Gas Act of 1938 (“NGA”), FERC has authority to regulate our natural gas facilities that provide natural gas pipeline 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 have been determined not to be just and reasonable by the FERC. 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 FERC’s jurisdiction over rates, existing rates may be challenged by complaint and proposed rate increases may be challenged by protest. The Stagecoach facility currently has market-based rate authority from the FERC; however, 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. There can be no assurance that FERC will continue to pursue its approach of pro-competitive policies as it considers matters such as pipeline rates and rules and policies that may affect rights of access to natural gas transportation capacity, transportation and storage facilities. Any successful complaint or protest against such rates or loss of market-based rate authority could have an adverse impact on our revenues associated with providing storage services. 13 Furthermore, FERC Order No. 2004 sets out Standards of Conduct that apply to interstate gas transmission pipelines and public utilities, governing their relationships with energy affiliates. FERC has found that we are a “transmission provider” and therefore subject to the requirements of Order No. 2004. However, FERC has granted us an exemption from these requirements based on the fact that we are an independent storage company that: (i) is not connected with facilities of affiliated pipelines, (ii) does not exercise market power, (iii) has no exclusive franchise, (iv) has no captive rate payers, (v) does not base its rates on its cost of service, (vi) has no guaranteed rate of return, and (vii) has no ability to cross-subsidize at-risk business with rate payer contributions. 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, 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 14 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. 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. The propane industry is not a growth industry because of increased competition from alternative energy sources. 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 15 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, 2006, we had approximately $660 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. 16 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. 17 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 implementation of stricter 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. 18 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 auditors addressing these assessments. 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 the fiscal years ended September 30, 1999, 2000, 2002, 2004, 2005 and 2006 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; 19 • • • • safety concerns; long-standing customer relationships; the inconvenience of switching tanks and suppliers; and the lack of growth in the industry. We can make no assurances that we will be able to compete successfully on the basis of these factors. If a competitor attempts to increase market share by reducing prices, we may lose customers, which would reduce our revenues. If we are not able to purchase propane from our principal suppliers, our results of operations would be adversely affected. Most of our total volume purchases are made under supply contracts that have a term of one year, are subject to annual renewal, and provide various pricing formulas. Two of our suppliers, Sunoco, Inc. (14%) and ExxonMobil Oil Corp. (11%), accounted for approximately 25% of propane purchases during the fiscal year ended September 30, 2006. 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. 20 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 pipeline transportation services in interstate commerce, including storage services. Natural gas companies may not charge rates that have been determined not to be just and reasonable by the FERC. 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. Pursuant to FERC’s jurisdiction over rates, existing rates may be challenged by complaint and proposed rate increases may be challenged by protest. The Stagecoach facility currently has market-based rate authority from the FERC. Any successful complaint or protest against rates charged for Stagecoach storage and related services, or our 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 it acquires transportation facilities or additional storage capacity, if we or one of our affiliates provides storage or transportation services in the same market area or acquires an interest in another storage field that can link our facilities to the market area or if we or one of our affiliates acquire an interest in or is acquired by an interstate pipeline. There can be no assurance that FERC will continue to pursue its approach of pro-competitive policies as it considers matters such as pipeline rates and rules and policies that may affect rights of access to natural gas transportation capacity, transportation and storage facilities. Any successful complaint or protest against our rates or loss of our market-based rate authority could have an adverse impact on our revenues associated with providing storage services. Failure to comply with applicable regulations under the NGA, Natural Gas Policy Act of 1978, Pipeline Safety Act of 1968 and certain other laws, and with implementing regulations associated with these laws could result in the imposition of administrative and criminal remedies and civil penalties of up to $1,000,000 per day, per violation. Our storage business depends on neighboring pipelines to transport natural gas. To obtain natural gas, our storage business depends on the Tennessee Gas Pipeline Company’s 300-Line to which we have interconnect access. 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 pipeline for transportation to and from our facilities affect the utilization and value of our storage services. Significant changes in the rates charged by the pipeline 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, 21 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 encounter competition from other natural gas storage companies. 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. 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, as well as construction of liquefied natural gas, or LNG, facilities. Expanding our business by constructing new midstream assets subjects us to construction 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’ 22 inability to transmit natural gas to or from these facilities or pipelines for any reason would adversely affect our results of operations. Operations at our facilities could be partially or completely shut down, temporarily or permanently, as the result of any number of circumstances that are not within our control, such as: • • • unscheduled turnarounds or catastrophic events at our physical plants; labor difficulties that result in a work stoppage or slowdown; and a disruption in the supply of natural gas to our storage facilities. Risks Inherent in an Investment in Us Unitholders have less ability to elect or remove management than holders of common stock in a corporation. Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business, and therefore limited ability to influence management’s decisions regarding our business. Unitholders did not elect our managing general partner or its board of directors and will have no right to elect our managing general partner or its board of directors on an annual or other continuing basis. The board of directors of our managing general partner is chosen by the sole member of our managing general partner, Inergy Holdings, L.P. Although our managing general partner has a fiduciary duty to manage our partnership in a manner beneficial to Inergy, L.P. and our unitholders, the directors of our managing general partner also have a fiduciary duty to manage our managing general partner in a manner beneficial to its member, Inergy Holdings, L.P. If unitholders are dissatisfied with the performance of our managing general partner, they will have little ability to remove our managing general partner. Our managing general partner generally may not be removed except upon the vote of the holders of 66 2⁄ 3% of the outstanding units voting together as a single class. Our unitholders’ voting rights are further restricted by a provision in our partnership agreement providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partners and their affiliates, cannot be voted on any matter. The control of our managing general partner may be transferred to a third party without unitholder consent. Our managing general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of our unitholders. Furthermore, there is no restriction in our partnership agreement on the ability of the owner of our managing general partner, Inergy Holdings, L.P., from transferring its ownership interest in our managing general partner to a third party. The new owner of our managing general partner would then be in a position to replace the board of directors and officers of our managing general partner with its own choices and to control the decisions taken by our board of directors and officers. Cost reimbursements due our managing general partner may be substantial and reduce our ability to pay the minimum quarterly distribution. Before making any distributions on our units, we will reimburse our managing general partner for all expenses it has incurred on our behalf. In addition, our general partners and their affiliates may provide us with services for which we will be charged reasonable fees as determined by our managing general partner. The reimbursement of these expenses and the payment of these fees could adversely affect our ability to make distributions to you. Our managing general partner has sole discretion to determine the amount of these expenses and fees. 23 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 8.4% in us, own and control our managing general partner and own and control our non-managing general partner, which owns an approximate 1.0% 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 general partners’ affiliates are not prohibited from engaging in other businesses or activities, including those in direct competition with us. • 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. 24 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 54.9% 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 Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to entity-level taxation by individual states. If the IRS treats us as a corporation or we become subject to a material amount of entity level taxation for state tax purposes, then our cash available for distribution 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. We have not requested, and do not plan to request, a ruling from the IRS on this or any other tax matter that affects us. 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. 25 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. We treat each purchaser of common units as having the same tax benefits without regard to the common units purchased. The IRS may challenge this treatment, which could adversely affect the value of our common units. Because we cannot match transferors and transferees of common units, we have adopted depreciation and amortization positions that may not conform with all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain on the sale of common units and could have a negative impact on the value of our common units or result in audits of and adjustments to our unitholders’ tax returns. 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 26 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. Item 1B. Unresolved Staff Comments. None. Item 2. Properties. As of November 1, 2006, we owned 239 of our 341 retail propane customer service centers and leased the balance. For more information concerning the location of our customer service centers see “Retail Propane” under Item 1. We lease our Kansas City, Missouri headquarters. We lease underground storage facilities with an aggregate capacity of approximately 41.4 million gallons of propane at seven locations under annual lease agreements. We also lease capacity in several pipelines pursuant to annual lease agreements. Tank ownership and control at customer locations are important components to our retail propane operations and customer retention. As of September 30, 2006, we owned the following: • • • approximately 1,200 bulk storage tanks at approximately 600 locations with typical capacities of 12,000 to 30,000 gallons, approximately 575,000 stationary customer storage tanks with typical capacities of 100 to 1,200 gallons, and approximately 120,000 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, 2006. 27 PART II Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities. Since July 31, 2001 our company’s common units representing limited partner interests have been traded on NASDAQ’s National Market under the symbol “NRGY.” The following table sets forth the range of high and low bid prices of the common units, as reported by NASDAQ, as well as the amount of cash distributions declared per common unit for the periods indicated. All high and low bid prices of the common units as well as the amount of cash distributions paid per common unit for the periods below have been adjusted for the two-for-one split of the outstanding units completed on January 12, 2004. Quarters Ended: Fiscal 2006: Low High Cash Distribution Per Unit September 30, 2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . June 30, 2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . March 31, 2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . December 31, 2005 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $25.60 24.84 25.49 25.00 $28.00 27.55 27.80 29.20 Fiscal 2005: September 30, 2005 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . June 30, 2005 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . March 31, 2005 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . December 31, 2004 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $26.72 29.29 27.81 24.60 $33.34 34.04 34.70 31.25 Fiscal 2004: September 30, 2004 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . June 30, 2004 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . March 31, 2004 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . December 31, 2003 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $23.04 19.80 17.61 20.51 $27.45 24.28 25.00 25.00 $0.555 0.545 0.540 0.530 $0.520 0.510 0.500 0.475 $0.425 0.415 0.405 0.395 As of November 20, 2006, our company had issued and outstanding 45,192,483 common units, which were held by approximately 29,960 unitholders. In addition, our company has issued and outstanding 769,941 Special Units which are held by Inergy Holdings, L.P. 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. 28 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, we issued 4,312,500 common units, which included 562,500 common units issued as result of the underwriters exercising their over-allotment provision. There is approximately $896.9 million remaining available under this shelf. No further partnership securities or debt securities have been offered under the shelf registration except as describe above. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Sources of Capital” under Item 7. We did not repurchase any units during the fourth quarter of the fiscal year. The following table sets forth in tabular format, a summary of our company’s equity compensation plan information as of September 30, 2006: Equity Compensation Plan Information Plan category Equity compensation plans approved by security holders . . . . Equity compensation plans not approved by security holders(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Number of securities to be issued upon exercise of outstanding options, warrants and rights (a) — 711,964 711,964 Weighted- average exercise price of outstanding options, warrants and rights (b) — $16.37 $16.37 Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) (c) — 608,780 608,780 (1) The Inergy Long Term Incentive Plan did not require the approval of security holders. Item 6. Selected Financial Data. The following table sets forth selected consolidated financial data and other operating data of Inergy, L.P., and our predecessor, Inergy Partners, LLC. The selected historical consolidated financial data of Inergy, L.P. as of and for the years ended September 30, 2006, 2005, 2004, 2003 and 2002 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 29 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. Statement of Operations Data: Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Cost of product sold (excluding depreciation and amortization as shown below): . . . . . . . . . . . . . . Gross profit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Expenses: Operating and administrative . . . . . . . . . . . . . Depreciation and amortization . . . . . . . . . . . . (Gain) loss on disposal of assets . . . . . . . . . . Operating income . . . . . . . . . . . . . . . . . . . . . . . . . . Other income (expense): Interest expense, net . . . . . . . . . . . . . . . . . . . . Write-off of deferred financing costs . . . . . . . Make whole premium charge . . . . . . . . . . . . . Swap value received . . . . . . . . . . . . . . . . . . . . Finance charges . . . . . . . . . . . . . . . . . . . . . . . Other income . . . . . . . . . . . . . . . . . . . . . . . . . Income (loss) before income taxes . . . . . . . . . . . . . Provision for income taxes . . . . . . . . . . . . . . . . . . . Inergy L.P. and Predecessor Years Ended September 30, 2006 2005 2004 2003 2002 (in thousands, except per unit data) $1,387,561 $1,050,136 $482,496 $363,365 $208,700 990,399 397,162 248,139 76,720 11,446 60,857 (53,842) — — — 2,650 813 10,478 667 724,223 359,053 267,010 134,999 325,913 123,443 96,355 73,701 197,082 50,364 679 77,788 (34,150) (6,990) — — 1,817 235 38,700 63 81,296 21,089 203 20,855 (7,878) (1,216) (17,949)(b) 949 704 106 59,249 13,843 91 23,172 (9,982) — — — 339 86 (4,429) 167 13,615 103 45,300 11,444 (140) 17,097 (8,365) (585) — — 115 140 8,402 93 Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . $ 9,811 $ 38,637 $ (4,596) $ 13,512 $ 8,309 Net income (loss) per limited partner unit: Basic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Weighted average limited partners’ units outstanding: $ $ (0.20) $ (0.20) $ 0.98 0.96 $ $ (0.26) $ (0.26) $ 0.77 0.76 $ $ 0.61 0.60 Basic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41,407 41,407 31,143 22,027 16,676 13,317 31,853 22,027 16,942 13,520 Cash distributions paid per unit . . . . . . . . . . . . . . . $ 2.14 $ 1.91 $ 1.60 $ 1.45 $ 1.28 30 Balance Sheet Data (end of period): Current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Long-term debt, including current portion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Partners’ capital Other Financial Data: EBITDA (unaudited) . . . . . . . . . . . . . . . . . . . . . . . Net cash provided by operating activities . . . . . . . Net cash used in investing activities . . . . . . . . . . . Net cash provided by financing activities . . . . . . . Maintenance capital expenditures(a) (unaudited) . . Other Operating Data (unaudited): Retail propane gallons sold . . . . . . . . . . . . . . . . . . Wholesale propane gallons delivered . . . . . . . . . . . Reconciliation of Net Income (Loss) to EBITDA and Adjusted EBITDA: 2006 2005 2004 2003 2002 $ 295,586 1,639,035 659,672 676,152 $ 303,218 1,502,244 559,731 663,894 $136,610 503,819 137,601 252,043 $ 73,953 362,393 131,127 178,983 $ 70,016 288,232 124,462 120,916 $ 141,040 104,472 (210,925) 108,996 3,731 $ 130,204 87,640 (840,626) 760,162 3,648 $ 42,754 31,927 (98,101) 64,884 1,368 $ 37,440 34,428 (33,667) 670 1,039 $ 28,796 7,779 (94,017) 86,155 1,556 360,303 365,296 318,367 391,296 140,742 368,320 119,697 284,721 88,515 256,893 $ Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . Provision for income taxes . . . . . . . . . . . . . . . Interest expense, net . . . . . . . . . . . . . . . . . . . . Write-off of deferred financing costs . . . . . . . Make whole premium charge . . . . . . . . . . . . . Swap value received . . . . . . . . . . . . . . . . . . . . Depreciation and amortization . . . . . . . . . . . . 9,811 667 53,842 — — — 76,720 $ 38,637 63 34,150 6,990 — — 50,364 $ (4,596) $ 13,512 103 9,982 — — — 13,843 167 7,878 1,216 17,949(b) (949) 21,089 $ 8,309 93 8,365 585 — — 11,444 EBITDA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 141,040 $ 130,204 $ 42,754 $ 37,440 $ 28,796 Non-cash (gain) loss on derivative contracts . . . . . . . . . . . . . . . . . . . . . . . . . . . 19,995 (19,410) (Gain) loss on sale of property, plant and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . 11,446 Long-term incentive and equity compensation expense . . . . . . . . . . . . . . . . 2,891 679 — — 203 — — — 91 (140) — — Adjusted EBITDA . . . . . . . . . . . . . . . . . . . . . . . . . $ 175,372 $ 111,473 $ 42,957 $ 37,531 $ 28,656 (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. 31 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, 32 including a high performance, multicycle natural gas storage facility (“Stagecoach”) and a natural gas liquids (“NGL”) business in California, which includes natural gas processing, NGL fractionation, NGL rail and truck terminals, bulk storage, trucking and marketing operations. We have grown primarily through acquisitions of retail propane operations. Since the inception of our predecessor in November 1996 through September 30, 2006, we have acquired 59 companies, 57 propane companies and 2 midstream businesses, for an aggregate purchase price of approximately $1.4 billion, including working capital, assumed liabilities and acquisition costs. Inergy further intends to pursue its growth objectives through, among other things, future acquisitions, maintaining a high percentage of retail sales to residential customers, operating in attractive markets and focusing its operations under established, and locally recognized trade names. During the fiscal year ended September 30, 2006, we made ten acquisitions, including Dowdle Gas, Inc. headquartered in Columbus, MS, Graeber Brothers, Inc. headquartered in Batesville, MS, Propane Gas Service, Inc. headquartered in South Windsor, CT, Atlas Gas Products, Inc. headquartered in Costonia, OH, Country Gas Inc. headquartered in Sumiton, AL, and five smaller retail propane companies, (collectively “the Acquisitions”). The aggregate purchase price for the Acquisitions, net of cash acquired was $186.3 million. The operating results for all the Acquisitions are included in our consolidated results of operations from the dates of acquisition through September 30, 2006. The purchase price allocation for Dowdle Gas, Inc. was finalized during the quarter ended September 30, 2006, and all applicable changes are reflected in the accompanying consolidated financial statements. The purchase price allocations for all other acquisitions have been prepared on a preliminary basis pending final asset valuation and asset rationalization, and changes are expected when additional information becomes available. For the fiscal year ended September 30, 2006, we sold approximately 360 million gallons of propane to retail customers and sold approximately 365 million gallons of propane to wholesale customers. Our retail business includes the retail marketing, sale and distribution of propane, including the sale and lease of propane supplies and equipment, to residential, commercial, industrial and agricultural customers. In addition to our retail business, we operate a wholesale supply, marketing and distribution business, providing propane procurement, transportation, supply and price risk management services to our customer service centers, as well as to independent dealers, multistate marketers, petrochemical companies, refinery and gas processors and a number of other NGL marketing and distribution companies. 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 33 period assumed to more accurately reflect the average normal weather, in each case as such information is published by the National Oceanic and Atmospheric Administration, for each measuring point in each of our regions. When we discuss “normal” weather in our results of operations presented below we are referring to a 30-year average consisting of the years 1976 through 2006. 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 2005 and 2006, 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. 34 Results of Operations 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 thousands): Year Ended September 30, Change 2006 2005 In Dollars Percentage Revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Cost of product sold . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $1,387,561 990,399 $1,050,136 724,223 $337,425 266,176 32.1% 36.8 Gross profit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Operating and administrative expenses . . . . . . . . . . . . . . . . . . . Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . Loss on disposal of assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Operating income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Interest expense, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Write-off of deferred financing cost . . . . . . . . . . . . . . . . . . . . . Finance charge income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Income before income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . Provision for income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . 397,162 248,139 76,720 11,446 60,857 (53,842) — 2,650 813 10,478 667 325,913 197,082 50,364 679 77,788 (34,150) (6,990) 1,817 235 38,700 63 71,249 51,057 26,356 10,767 (16,931) (19,692) 6,990 833 578 (28,222) 604 21.9 25.9 52.3 * (21.8) (57.7) 100.0 45.8 246.0 (72.9) * Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 9,811 $ 38,637 $ (28,826) (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 $ 701.1 371.2 162.2 $ 526.5 325.1 121.5 In Dollars $174.6 46.1 40.7 Percentage 2006 2005 In Units Percentage 33.2% 360.3 365.3 14.2 — 33.5 318.4 391.3 — 41.9 (26.0) — 13.2% (6.6) — Retail propane . . . . . . . . . . . . . . Wholesale propane . . . . . . . . . . Other retail . . . . . . . . . . . . . . . . Storage, fractionation, and midstream . . . . . . . . . . . . . . . 153.1 77.0 76.1 98.8 — — — — Total . . . . . . . . . . . . . . . . . . . . . $1,387.6 $1,050.1 $337.5 32.1% 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 35 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 by our West Coast operations increased 20.5 million gallons, or 45.7%, to 65.4 million gallons in fiscal 2006 from 44.9 million gallons in fiscal 2005. This increase was attributable to the addition of natural gas liquid marketing 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 $1.39 billion, an increase of approximately $337.5 million, or 32.1% from $1.05 billion 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 as discussed above. 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 $162.2 million in fiscal 2006, an increase of $40.7 million or 33.5% from $121.5 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 described above offset by a $64.7 million decrease due to lower volumes from existing locations also as discussed above. 36 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 as discussed above. 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 and delivery vehicle costs consisting of fuel costs, repair and maintenance and lease expense. These costs 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. 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 as discussed above. 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 $62.6 million in fiscal 2006 compared to $49.7 million in fiscal 2005, an increase of $12.9 million, or 26%, 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. 37 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 $26.3 million, or 52.3%, to $76.7 million in fiscal 2006 from $50.4 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 $11.4 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 $4.8 million. These assets, both those sold and those held for sale, consist primarily of vehicles, tanks and real estate deemed to be excess, redundant or underperforming assets. These assets were identified as a result of the final integration of the larger retail propane acquisitions closed since November 2004 as Inergy 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 57.7%, 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. 38 EBITDA and Adjusted EBITDA. The following table summarizes EBITDA and Adjusted EBITDA for the fiscal years ended September 30, 2006 and 2005, respectively (in thousands): EBITDA: . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net income (loss) Interest expense, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Write-off of deferred financing costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . Provision for income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . EBITDA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Non-cash (gain) loss on derivative contracts . . . . . . . . . . . . . . . . . . . . . . Loss on disposal of assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Long-term incentive and equity compensation expense . . . . . . . . . . . . . . Years Ended September 30, 2006 2005 $ 9,811 53,842 — 667 76,720 $141,040 19,995 11,446 2,891 $ 38,637 34,150 6,990 63 50,364 $130,204 (19,410) 679 — Adjusted EBITDA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $175,372 $111,473 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. 39 Fiscal Year Ended September 30, 2005 Compared to Fiscal Year Ended September 30, 2004 The following table summarizes the consolidated income statement components for the fiscal years ending September 30, 2005 and 2004, respectively (in thousands): Year Ended September 30, Change 2005 2004 In Dollars Percentage Revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Cost of product sold . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $1,050,136 724,223 $482,496 359,053 $567,640 365,170 117.6% 101.7 Gross profit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Operating and administrative expenses . . . . . . . . . . . . . . . . . . . . Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . Loss on disposal of assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Operating income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Interest expense, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Write-off of deferred financing costs . . . . . . . . . . . . . . . . . . . . . . Make whole premium charge . . . . . . . . . . . . . . . . . . . . . . . . . . . . Swap value received . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Finance charge income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Income (loss) before income taxes . . . . . . . . . . . . . . . . . . . . . . . . Provision for income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 325,913 197,082 50,364 679 77,788 (34,150) (6,990) — — 1,817 235 38,700 63 123,443 81,296 21,089 203 20,855 (7,878) (1,216) (17,949) 949 704 106 (4,429) 167 202,470 115,786 29,275 476 56,933 (26,272) (5,774) 17,949 (949) 1,113 129 43,129 (104) 164.0 142.4 138.8 234.5 273.0 (333.5) (474.8) 100.0 (100.0) 158.1 121.7 973.8 (62.3) Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 38,637 $ (4,596) $ 43,233 940.7% The following table summarizes revenues, including associated volume of gallons sold, for the years ending September 30, 2005 and 2004, respectively (in millions): Revenues Gallons Year Ended September 30, Change Year Ended September 30, Change 2005 2004 $ 526.5 325.1 121.5 $196.3 234.9 21.8 In Dollars $330.2 90.2 99.7 Percentage 2005 2004 In Units Percentage 168.2% 318.4 391.3 38.4 — 457.3 140.7 368.3 — 177.7 23.0 — 126.3% 6.2 — Retail propane . . . . . . . . . . . . . . . Wholesale propane . . . . . . . . . . . . Other retail . . . . . . . . . . . . . . . . . . Storage, fractionation, and midstream . . . . . . . . . . . . . . . . . 77.0 29.5 47.5 161.0 — — — — Total . . . . . . . . . . . . . . . . . . . . . . . $1,050.1 $482.5 $567.6 117.6% 709.7 509.0 200.7 39.4% Volume. During fiscal 2005, we sold 318.4 million retail gallons of propane, an increase of 177.7 million gallons, or 126.3%, from the 140.7 million retail gallons sold in fiscal 2004. The increase in retail sales volume was principally due to the December 2004 acquisition of Star Gas and 5 other retail propane companies acquired in fiscal 2005, which combined resulted in a 197.5 million gallon increase. This increase was partially offset by an approximate 19.8 million gallon decline in comparable sales. We believe this is due primarily to a combination of warmer weather and conservation by our customers due to an approximate 24% higher propane cost in our retail operations (excluding the $19.4 million non-cash gain on derivative contracts discussed below) to $0.93 per gallon on average in 2005 compared with $0.75 in 2004. Our retail gallon sales will not fluctuate from year to year on a linear basis with the change in weather in our areas of operations. Reasons for this include comparability of geographic areas in which we operate and varying uses of propane (i.e. space heating, cooking and other applications), among others. Although the weather was only approximately 1% warmer in fiscal 2005 as compared to fiscal 2004 (and approximately 6% warmer than normal) in our retail areas of operations, we 40 experienced erratic weather during the winter months of fiscal 2005 including the months of January and February of 2005 being approximately 12% and 15%, warmer, respectively, than the same months of 2004 while the month of March 2005 was 28% colder than the month of March 2004. Wholesale gallons delivered increased 23.0 million gallons, or 6.2%, to 391.3 million gallons in fiscal 2005 from 368.3 million gallons in fiscal 2004. This increase was primarily attributable to acquisition-related volume, which accounted for 13.2 million gallons of this increase. Additionally, increased sales volumes to new and existing customers, partially offset by the warmer weather in 2005 in our wholesale areas of operations accounted for a net increase of 9.8 million gallons. The fractionation and throughput gallons of NGLs in our West Coast operations increased 40.1 million gallons, or 34.9%, to 154.9 million gallons in fiscal 2005 from 114.8 million gallons in fiscal 2004. These increases were all primarily attributable to increased sales volumes to new and existing customers. From August 9, 2005, the date of the Stagecoach acquisition, Stagecoach had 13.25 bcf of working gas capacity. Storage at Stagecoach was 85% contracted on average from August 9, 2005 to September 30, 2005. Revenues. Revenues in fiscal 2005 were $1.05 billion, an increase of approximately $567.5 million, or 117.6%, from $482.5 million in fiscal 2004. Revenues from retail propane sales were $526.5 million in fiscal 2005, an increase of $330.2 million, or 168.2%, from $196.3 million in fiscal 2004. This increase was primarily the result of $327.9 million of sales related to the Star Gas acquisition and other acquisitions together with an increase of approximately $36.4 million due to higher selling prices of propane due to the higher cost of propane in 2005. These increases were partially offset by a $34.1 million decline in revenues as a result of lower retail volume sales at our existing locations as discussed above. Revenues from wholesale propane sales were $325.1 million in fiscal 2005, an increase of $90.2 million or 38.4%, from $234.9 million in fiscal 2004. Approximately $71.1 million of this increase was attributable to the higher cost of propane, approximately $14.7 million was attributable to acquisition-related volume, and $4.4 million was attributable to volume increases generated in our wholesale propane operations. The higher selling price in our wholesale division in 2005 compared to 2004 is the result of the higher cost of propane. Revenues from other retail sales, primarily service, appliance, transportation, and distillates, were $121.5 million in fiscal 2005, an increase of $99.7 million or 457.3% from $21.8 million in fiscal 2004. This increase was primarily due to the Star Gas acquisition, which contributed approximately $90.2 million of this increase. Revenues from storage, fractionation and other midstream activities were $77.0 million in fiscal 2005, an increase of $47.5 million or 161.0% from $29.5 million in fiscal 2004. Approximately $43.7 million of this increase was due to increased volumes and sales prices of natural gas, butane, and isobutane. Approximately $3.8 million of this increase was due to the acquisition of the Stagecoach natural gas storage facility. Cost of Product Sold. Retail propane cost of product sold in fiscal 2005 was $274.6 million, an increase of $169.5 million or 161.3%, from $105.1 million in fiscal 2004. Approximately $24.6 million of this increase was attributable to the higher average cost of propane (excluding the non-cash gain on derivative contracts discussed below) in our retail division and a net additional increase of approximately $164.3 million as a result of retail propane acquisition-related volume described above in excess of the lesser volumes from existing locations. These increases were offset by a non-cash gain on derivative contracts of $19.4 million which will reverse in the first two quarters of fiscal 2006 as the physical gallons are delivered to retail customers. Wholesale propane cost of product sold in fiscal 2005 was $318.8 million, an increase of $89.7 million or 39.2%, from wholesale cost of product sold of $229.1 million in 2004. Approximately $71.0 million of this increase was a result of the higher average cost of product, approximately $14.4 million of this increase was a result of acquisition-related volume, and approximately $4.3 million of this increase was the result of higher volumes experienced in our wholesale propane areas of operations. 41 Other retail cost of product was $71.8 million, an increase of $64.7 million, from other retail cost of product of $7.1 in fiscal 2004. This increase was primarily due to acquisition-related volume. Fractionation, storage, and other midstream cost of product sold was $59.0 million, an increase of $41.2 million, or 231.5%, from $17.8 million in fiscal 2004. Approximately $40.5 million of this increase was due to higher volumes and cost of natural gas, butane, and isobutane at the West Coast NGL operations, and approximately $0.7 million was due to acquisition-related volume from the Stagecoach natural gas storage facility. Our cost of product sold consists primarily of tangible products sold including all propane, distillates and other natural gas liquids sold and all propane-related appliances sold. Other costs incurred in conjunction with the distribution of these products are included in operating and administrative expenses and consist primarily of wages to delivery personnel and delivery vehicle costs consisting of fuel costs, repair and maintenance and lease expense. These costs approximated $45.6 million and $23.5 million in 2005 and 2004, respectively. In addition, the depreciation expense associated with the delivery vehicles is reported within depreciation and amortization expense and amounted to $10.8 million and $4.7 million in 2005 and 2004, respectively. Since we include these costs in our operating and administrative expenses rather than in cost of product sold, our results may not be comparable to other entities in our lines of business if they include these costs in cost of product sold. Gross Profit. Retail propane gross profit was $251.9 million in fiscal 2005 compared to $91.2 million in fiscal 2004, an increase of $160.7 million, or 176.2%. This increase was primarily attributable to an increase in retail gallons sold primarily as a result of acquisitions, which accounted for approximately $142.8 million, an increase attributable to a non-cash gain of $19.4 million on derivative contracts discussed above, as well as an increase in margin per gallon, which resulted in an increase of approximately $11.8 million. These increases were partially offset by lower retail propane gross profit of approximately $13.3 million at our existing locations as a result of lower volume sales discussed above. The increase in margin per gallon is primarily the result of our ability to increase our selling prices in certain markets in excess of our increased cost of propane. Wholesale propane gross profit was $6.3 million in fiscal 2005 compared to $5.8 million in fiscal 2004, an increase of $0.5 million or 8.6%. Approximately $0.2 million of this increase was a result of increased margin per gallon from our existing business and $0.3 million of the increase was due to acquisition-related volume and increased wholesale volumes from our existing business. Other retail gross profit was $49.7 million in fiscal 2005 compared to $14.7 million in fiscal 2004, an increase of $35.0 million, or 238.1%. This increase was due primarily to acquisition-related volume. Fractionation, storage, and other midstream gross profit was $18.0 million in fiscal 2005 compared to $11.7 million in fiscal 2004, an increase of $6.3 million, or 53.8%. This increase was due primarily to acquisition- related volume of $3.3 million and $3.0 million due to increased volumes and margins to existing customers. Operating and Administrative Expenses. Operating and administrative expenses increased $115.8 million, or 142.4%, to $197.1 million in fiscal 2005 as compared to $81.3 million in fiscal 2004. The increase in our operating and administrative expenses were primarily attributable to acquisition-related costs, including increases in personnel expenses of $70.3 million, general operating expenses of $32.9 million including insurance, professional services and facility costs, and increased vehicle costs of $12.6 million. Depreciation and Amortization. Depreciation and amortization increased $29.3 million, or 138.8%, to $50.4 million in fiscal 2005 from $21.1 million in fiscal 2004 as a result of retail propane acquisitions and the acquisition of the Stagecoach natural gas storage facility. Interest Expense. Interest expense increased $26.3 million, or 333.5%, to $34.2 million in fiscal 2005 as compared to $7.9 million in fiscal 2004. Interest expense increased primarily due to an increase of $368.8 million in average debt outstanding in 2005 compared to 2004 primarily as a result of net borrowings for acquisitions, and an approximate 1.4% higher average interest rate in 2005 compared to 2004. 42 Interest Expense and Income related to Make Whole Premium Charge, Write-off of Deferred Financing Costs, and Swap Value Received. During the fiscal year ended September 30, 2005, we recorded a charge of $7.0 million as a result of the write-off of deferred financing costs associated with the repayment of the previously existing credit agreement and the 364-day facility. During the fiscal year ended September 30, 2004, we repaid in full our $85.0 million senior secured notes before their scheduled maturity dates. As such, we were required to pay an additional amount of approximately $17.9 million as a make whole payment, which was recorded as a charge to earnings in the quarter ended March 31, 2004. We used proceeds from our January 2004 common unit offering and borrowings from our bank credit facility for this repayment. In addition, we also recorded a charge to earnings of approximately $1.2 million in the quarter ended March 31, 2004, to write-off deferred financing costs associated with the senior secured notes. Partially offsetting these charges was a $0.9 million gain from the cancellation of interest rate swap agreements also associated with the Senior Notes. Net Income (Loss). Net income for fiscal 2005 was $38.6 million compared to a net loss of $4.6 million in fiscal 2004. Net income for fiscal 2005 includes a non-cash gain on derivative contracts of $19.4 million. The net loss in fiscal 2004 was primarily a result of net charges of $18.2 million associated with the early retirement of the senior secured notes. EBITDA and Adjusted EBITDA. The following table summarizes EBITDA and Adjusted EBITDA for the fiscal years ending September 30, 2005 and 2004, respectively (in thousands): Years Ended September 30, 2005 2004 EBITDA: . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net income (loss) Interest expense, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Interest expense related to make whole premium charge . . . . . . . . . . . . . . . . . . . . . . . . Interest income related to swap value received . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Write-off of deferred financing costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Provision for income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 38,637 34,150 — — 6,990 63 50,364 $ (4,596) 7,878 17,949 (949) 1,216 167 21,089 EBITDA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Non-cash gain on derivative contracts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Loss on sale of property, plant and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $130,204 (19,410) 679 $42,754 — 203 Adjusted EBITDA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $111,473 $42,957 EBITDA and Adjusted EBITDA. 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, 2005 and 2004, EBITDA was $130.2 million and $42.8 million, respectively. This $87.4 million improvement in EBITDA was primarily attributable to increased sales volumes, higher retail propane margins, and a non-cash gain on derivative contracts associated with retail fixed price propane sales partially offset by an increase in operating and administrative expenses. As indicated in the table, Adjusted EBITDA represents EBITDA excluding the non-cash gain or loss on certain derivative contracts associated with retail fixed price propane sales, the gain or loss on the sale of fixed assets and long-term incentive and equity compensation expenses. Adjusted EBITDA was $111.5 million for fiscal 2005 compared to $43.0 million in fiscal 2004. 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. 43 Liquidity and Sources of Capital Capital Resource Activities In September 2005, we issued 6,500,000 common units to unrelated third parties resulting in net proceeds after underwriters’ discounts, commissions, and offering expenses of $180.4 million. These proceeds were obtained to repay borrowings under our Credit Agreement (as defined below), which were incurred to make certain acquisitions, including the acquisition of the Stagecoach natural gas storage facility. In October 2005, the underwriters of the 6,500,000 common unit offering exercised a portion of their over- allotment and we issued an additional 900,000 common units in a follow-on offering, resulting in proceeds of approximately $24.7 million, net of underwriters’ discounts, commissions, and offering expenses. These funds were used to repay borrowings under the Credit Agreement. On January 11, 2006, we and our wholly owned subsidiary Inergy Finance Corporation issued $200 million aggregate principal amount of 8.25% senior unsecured notes due 2016 in a private placement to eligible purchasers. See “Senior Unsecured Notes” section below for further information. 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, we issued 4,312,500 common units, under the shelf registration statement, which included 562,500 common units issued as result of the underwriters exercising their over-allotment provision. There is approximately $896.9 million remaining available under this shelf. 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 assets that are expected to require a capital investment of approximately $225 million to complete. Through September 30, 2006, we have invested approximately $20.6 million toward completion of these projects. These projects include expansion of our Stagecoach natural gas storage facility, which is expected to increase our working storage capacity of natural gas to approximately 26.35 bcf through the addition of approximately 13.1 bcf of storage to our existing 13.25 bcf working storage capacity. All necessary regulatory approvals have been received and construction of the expansion is underway. The expanded facilities are expected to be in service by fall of 2007. 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. In addition, we presently have an agreement with a customer of Stagecoach whereby that customer provides certain asset management services through utilization of its firm storage capacity and related firm transportation on Tennessee Gas Pipeline. The agreement expires in June 2007 at which time we will either renegotiate this agreement, execute a similar agreement with a different customer or internalize these asset management services within Stagecoach with an additional investment of approximately $26 million. However, we are presently in negotiations with another customer and expect to execute a new asset management services agreement prior to June 2007. 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 January 2008. Cash Flows and Contractual Obligations Net operating cash inflows were $104.4 million and $87.6 million for fiscal years ending September 30, 2006 and 2005, respectively. The $16.8 million increase in operating cash flows was primarily attributable to an 44 increase in gross profit and an increase related to net changes in working capital balances. These higher operating cash flows were partially offset by a reduction of net income as a result of higher operating expenses and interest expense. Net investing cash outflows were $210.9 million and $840.6 million for the fiscal years ending September 30, 2006 and 2005, respectively. We funded acquisitions of $187.2 million in 2006 compared to $810.1 million in 2005, a decrease of $622.9 million. Additionally, proceeds from the sale of assets increased $7.3 million in fiscal year 2006 compared to fiscal year 2005, which reduced cash outflows from investing activities. These reductions in net investing cash outflows related to acquisitions and proceeds from the sale of assets were partially offset by an increase of $0.4 million in capital expenditures and a slight increase in deferred financing and acquisition costs. Net financing cash inflows were $109.0 million and $760.2 million for the fiscal years ending September 30, 2006 and 2005, respectively. Net financing cash inflows were primarily impacted by $187.2 million and $810.1 million of acquisitions financed in 2006 and 2005, respectively. The lesser acquisitions financed in 2006 versus 2005 were the primary reason for a $325.7 million period to period decrease in proceeds from the issuance of long-term debt, net of payments on long-term debt, and a $308.2 million decrease in proceeds from the issuance of common units. Net financing cash outflows were also impacted by a $39.8 million period to period increase in distributions, partially offset by a $4.1 million increase due to the exercise of stock options and $18.4 million decrease in the payments for deferred financing costs. At September 30, 2006 and 2005, we had goodwill of $332.4 million and $249.2 million, representing approximately 20% and 17% of total assets, respectively. This goodwill is attributable to our acquisitions. At September 30, 2006, we were in compliance with all debt covenants to our credit facilities. The following table summarizes our contractual obligations as of September 30, 2006 (in thousands): Aggregate amount of principal and interest to be paid on the outstanding long-term debt (a) . . . . . . . Amount of principal and interest to be paid on other long-term obligations . . . . . . . . . . . . . . . . . . . . . . Future minimum lease payments under Total Less than 1 year 1-3 years 4-5 years After 5 years $1,072,902 $ 65,927 $102,801 $107,762 $796,412 11,449 2,626 8,823 — — noncancelable operating leases . . . . . . . . . . . . . . . Fixed price purchase commitments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Standby letters of credit 22,287 356,454 32,924 6,402 354,468 29,486 9,134 1,986 3,248 3,667 — 190 3,084 — — (a) $147.7 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 7.08% and 8.50% at September 30, 2006. These rates have been applied for each period presented in the table. In addition to our fixed price purchase commitments, we also have forward purchase energy contracts. As of September 30, 2006, total energy contracts had an outstanding net fair value of $(2.8) million, as compared to a net fair value of $8.8 million as of September 30, 2005. This $11.6 million decrease includes a net decrease in fair value of $6.6 million from energy contracts settled during the 2006 fiscal year period and a net decrease of $4.4 million from other changes in fair value related to net unrealized losses on energy contracts still outstanding at the end of fiscal 2006. Of the outstanding fair value as of September 30, 2006, all energy contracts mature within fifteen months. 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. 45 Description of Credit Facility On December 17, 2004, Inergy entered into a 5-Year Credit Agreement (the “Credit Agreement”) with its existing lenders in addition to others. The Credit Agreement consists of a $75 million revolving working capital facility (“Working Capital Facility”) and a $350 million revolving acquisition facility (“Acquisition Facility”). The Credit Agreement carries terms, conditions and covenants as further described below. The Credit Agreement is secured by a first priority lien on substantially all of Inergy’s assets and those of its subsidiaries and the pledge of all of the equity interests or membership interests in its subsidiaries. In addition, the Credit Agreement is guaranteed by each of Inergy’s domestic subsidiaries. The Credit Agreement accrues interest at either prime rate or LIBOR plus applicable spreads, resulting in interest rates between 7.08% and 8.50% at September 30, 2006. At September 30, 2006, there was no amount outstanding under the Acquisition Facility and $22.7 million under the Working Capital Facility. Unused borrowings under the Credit Agreement amounted to $369.4 million and $276.2 million at September 30, 2006 and 2005, respectively. Outstanding standby letters of credit under the Credit Agreement amounted to $32.9 million and $22.0 million at September 30, 2006 and 2005, respectively. 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. 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. Inergy also pays 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 Inergy and its domestic subsidiaries, and the sale or disposition of obsolete or worn-out equipment) to reduce borrowings under the Credit Agreement during any fiscal year in which unapplied net cash proceeds are in excess of $50 million. Any such mandatory prepayments are first applied to reduce borrowings under the Acquisition Facility and then under the Working Capital Facility. In addition, the Credit Agreement contains various covenants limiting 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; 46 • • • 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 Inergy or its 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: • • • • Inergy’s $425 million 6.875% senior notes due December 15, 2014 that were issued on December 22, 2004; Inergy’s $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 Inergy or its material subsidiaries; impairment of the enforceability or the validity of agreements relating to the Credit Agreement; judgments exceeding $2.5 million (to the extent not covered by insurance) against Inergy or any of its subsidiaries are undischarged or unstayed for 30 consecutive days; 47 • • certain defaults under ERISA that could reasonably be expected to result in a material adverse effect on Inergy; or the occurrence of certain change of control events with respect to Inergy. On October 10, 2006, we amended the Credit Agreement with existing lenders to, among other changes, increase to $125.0 million the effective amount of working capital borrowings available through the utilization of the acquisition revolver. 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 (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 2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2014 and thereafter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Percentage 104.125% 102.750% 101.375% 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. 48 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 Inergy). The subsidiaries guarantees rank senior in right of payment to all of Inergy’s 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 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2012 and thereafter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Percentage 103.438% 102.292% 101.146% 100.000% Recent Accounting Pronouncements 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 us for the fiscal year ended September 30, 2008. We will be evaluating the potential financial statement impact of SFAS 157 to our consolidated financial statements. SFAS No. 155, “Accounting for Certain Hybrid Financial Instruments” (“SFAS 155”) amends SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” 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. SFAS 155 is effective for all financial instruments acquired or issued after the beginning of an entity’s first fiscal year that begins after September 15, 2006. We will be evaluating the potential financial statement impact of SFAS 155 to our consolidated financial statements. 49 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 is effective for the accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. The adoption of SFAS 154 is not expected to have an impact on our consolidated financial statements. In March 2005, the Financial Accounting Standards Board (“FASB”) issued FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations—an interpretation of SFAS No. 143” (“FIN 47”). FIN 47 clarifies that the term conditional retirement obligation, as used in SFAS No. 143, “Asset Retirement Obligations,” refers to a legal obligation to perform an asset retirement activity in which the timing or method of settlement, or both, are conditional on a future event that may or may not be within the control of the entity. An entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. FIN 47 was required to be adopted by us for the fiscal year ended September 30, 2006. We have evaluated the impact of FIN 47 and determined that it does not have a material effect on our financial statements in the current year as well as all prior years considered. EITF 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty” addresses the accounting for an entity’s sale of inventory to another entity from which it also purchases inventory to be sold in the same line of business. EITF 04-13 concludes that two or more inventory transactions with the same counterparty should be accounted for as a single non-monetary transaction at fair value or recorded amounts based on inventory classifications. EITF 04-13 is effective for new arrangements entered into, and modifications or renewal of existing arrangements, beginning in the first interim or annual reporting period beginning after March 15, 2006. We have evaluated the impact of EITF 04-13 and determined that it does not have a material effect on our financial position, results of operations and cash flows. 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. 50 We are a 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 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. The cash flow impact of financial instruments is reflected as cash flows from operating activities in the consolidated statements of cash flows. Revenue Recognition. Sales of propane and other liquids are recognized at the 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, 2006. 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. 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. 51 • If we do not continue to make acquisitions on economically acceptable terms, our future financial performance will be reliant upon internal growth and efficiencies. • We cannot assure you that we will be successful in integrating our recent acquisitions. • Sudden and sharp propane price increases that cannot be passed on to customers may adversely affect our profit margins. • Our indebtedness may limit our ability to borrow additional funds, make distributions to unitholders or capitalize on acquisition or other business opportunities. • • The highly competitive nature of the retail propane business could cause us to lose customers, thereby reducing our revenues. If we are not able to purchase propane from our principal suppliers, our results of operations would be adversely affected. • Competition from alternative energy sources may cause us to lose customers, thereby reducing our revenues. • Our business would be adversely affected if service at our principal storage facilities or on the common carrier pipelines we use is interrupted. • Terrorist attacks, such as the attacks that occurred on September 11, 2001, have resulted in increased costs, and war or risk of war may adversely impact our results of operations. • We are subject to operating and litigation risks that could adversely affect our operating results to the extent not covered by insurance. • Our results of operations and financial condition may be adversely affected by governmental regulation and associated environmental regulatory costs. • 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, 2006, we had floating rate obligations totaling approximately $147.7 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 2006 levels, our combined interest expense would change by a total of approximately $1.5 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 52 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, 2006 and 2005 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, 2006 and 2005 (in millions): September 30, 2006 2005 Fixed Price Payor Fixed Price Receiver Fixed Price Payor Fixed Price Receiver Propane and heating oil (barrels) . . . . . . . . . . . . . Natural gas (MMBTU’s) . . . . . . . . . . . . . . . . . . . . 8.0 5.5 7.5 5.4 11.0 1.9 12.7 1.9 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, 2006 and September 30, 2005 was assets of $46.2 million and $58.4 million, respectively, and liabilities of $49.0 million and $49.6 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 propane based financial instruments, for the years 53 ended September 30, 2006, 2005 and 2004 of $(39.5) million, $24.1 million, and $(1.2) million, respectively, are included in cost of product sold in the accompanying consolidated statements of operations. 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 from the previous year is a non-cash gain of $19.4 million related to derivative contracts. No similar gain or loss was recognized in the year ended September 30, 2004. 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, 2006 and 2005 where settlement has not yet occurred (in thousands): Year Ended September 30, 2006 Year Ended September 30, 2005 Net fair value gain (loss) of contracts outstanding at beginning of year . . . . Net unrealized gain acquired through acquisition during the year . . . . . . . . Net change in physical exchange contracts . . . . . . . . . . . . . . . . . . . . . . . . . . Change in fair value of contracts attributable to market movement during the year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Realized gains . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net fair value of contracts outstanding at end of year . . . . . . . . . . . . . . . . . . $ 8,784 — (592) (4,400) (6,639) $(2,847) $ (6,626) 1,881 1,508 16,689 (4,668) $ 8,784 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, 2006 and 2005, $(2.7) million and $8.8 million have or will mature within 12 months, respectively. Contracts with a maturity of greater than one year were not significant. 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 0.3 million gallons of net unbalanced positions at September 30, 2006. Item 8. Financial Statements and Supplementary Data. Reference is made to the financial statements and report of independent registered public accounting firm included later in this report under Item 15. Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure. None. Item 9A. Controls and Procedures. We maintain controls and procedures designed to ensure that information required to be disclosed in our reports that we file or submit under the Securities Exchange Act of 1934 are recorded, processed, summarized and reported within the time periods specified by the rules and forms of the SEC, and that information is 54 accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. An evaluation was performed under the supervision and with the participation of our management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as such terms are defined in Rule 13a-15(e) and 15d-15(e) of the Exchange Act). Based upon that evaluation, management, including the Chief Executive Officer and the Chief Financial Officer, concluded that our disclosure controls and procedures were adequate and effective as of September 30, 2006. There have been no changes in our internal controls over financial reporting (as defined in Rule 13(e)-15 or Rule 15d-15(f) of the Exchange Act) or in other factors during the fiscal year covered by this report that has materially affected, or is reasonably likely to materially affect, the internal controls over financial reporting. 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 acquisitions of Dowdle Gas, Inc., Graeber Brothers, Inc., Propane Gas Service, Inc., Atlas Gas Products, Inc., Country Gas Inc., and five smaller acquisitions, (collectively “the Acquisitions”) which were acquired during fiscal 2006 and are included in the 2006 consolidated financial statements. The financial reporting systems of the Acquisitions were integrated into the company’s financial reporting systems throughout 2006. 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 $132.5 million and $144.1 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, 2006. 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, 2006, our internal control over financial reporting is effective, in all material respects, based upon those criteria. Our independent registered public accounting firm, Ernst & Young LLP, issued an attestation report dated November 30, 2006 on our assessment and on the effectiveness of our internal control over financial reporting, which is included herein. Item 9B. Other Information. None. 55 PART III Item 10. Directors and Executive Officers of the Registrant. Our Managing General Partner Manages Inergy, L.P. Inergy GP, LLC, our managing general partner, manages our operations and activities. Our managing general partner is not elected by our unitholders and will not be subject to re-election on a regular basis in the future. Our managing general partner may not be removed unless that removal is approved by the vote of the holders of not less than 66 2⁄ 3% of the outstanding units, including units held by the general partners and their affiliates, and we receive an opinion of counsel regarding limited liability and tax matters. Any removal of the managing general partner is also subject to the approval of a successor managing general partner by the vote of the holders of a majority of the outstanding common units. Unitholders do not directly or indirectly participate in our management or operation. Our managing general partner owes a fiduciary duty to the unitholders. Our managing general partner is liable, as a general partner, for all of our debts (to the extent not paid from our assets), except for specific nonrecourse indebtedness or other obligations. Whenever possible, our managing general partner intends to incur indebtedness or other obligations that are nonrecourse. Our managing general partner may appoint two independent directors to serve on a conflicts committee to review specific matters which the board of directors believes may involve conflicts of interest. A conflicts committee will determine if the resolution of any conflict of interest submitted to it is fair and reasonable to us. In addition to satisfying certain other requirements, the members of the conflicts committee must meet the independence standards for service on an audit committee of a board of directors, which standards are established by the NASDAQ National Market. Any matters approved by the conflicts committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners, and not a breach by our managing general partner of any duties it may owe us or our unitholders. Two members of the board of directors also serve on a compensation committee, which oversees compensation decisions for the officers of Inergy GP, LLC, as well as the compensation plans described below. The members of the compensation committee are Arthur B. Krause and Warren H. Gfeller. The members of the audit committee must meet the independence standards established by the NASDAQ National Market. The members of the audit committee are Warren H. Gfeller, Arthur B. Krause and Robert D. Taylor. The board of directors of our managing general partner has determined that Mr. Gfeller is an audit committee financial expert based upon the experience stated in his biography. We believe that he is independent of management. The audit committee’s primary responsibilities are to monitor: (a) the integrity of our financial reporting process and internal control system; (b) the independence and performance of the outside auditors; and (c) the disclosure controls and procedures established by management. As is commonly the case with publicly-traded limited partnerships, we are managed and operated by 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. 56 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 . . . . . . . . . . . . . . . . 51 President, Chief Executive Officer and Director Phillip L. Elbert . . . . . . . . . . . . . . . . . 48 Executive Vice President—Propane Operations and Director David G. Dehaemers, Jr. . . . . . . . . . . 46 Executive Vice President—Corporate Development R. Brooks Sherman, Jr. . . . . . . . . . . . 41 Senior Vice President and Chief Financial Officer Carl A. Hughes . . . . . . . . . . . . . . . . . 52 Vice President—Business Development Laura L. Ozenberger . . . . . . . . . . . . . 48 Vice President—General Counsel and Secretary Andrew L. Atterbury . . . . . . . . . . . . . 33 Vice President—Corporate Strategy Warren H. Gfeller . . . . . . . . . . . . . . . 54 Director Arthur B. Krause . . . . . . . . . . . . . . . . 65 Director Robert A. Pascal . . . . . . . . . . . . . . . . 72 Director Robert D. Taylor . . . . . . . . . . . . . . . . 59 Director John J. Sherman. Mr. Sherman has served as President, Chief Executive Officer and a director since March 2001, and of our predecessor from 1997 until July 2001. Prior to joining our predecessor, he was a vice president with Dynegy Inc. from 1996 through 1997. He was responsible for all downstream propane marketing operations, which at the time were the country’s largest. From 1991 through 1996, Mr. Sherman was the president of LPG Services Group, Inc., a company he co-founded and grew to become one of the nation’s largest wholesale marketers of propane before Dynegy acquired LPG Services in 1996. From 1984 through 1991, Mr. Sherman was a vice president and member of the management committee of Ferrellgas, which is one of the country’s largest retail propane marketers. He also serves as President, Chief Executive Officer and director of Inergy Holdings GP, LLC. Phillip L. Elbert. Mr. Elbert has served as Executive Vice President—Propane Operations and director since March 2001. He joined our predecessor as Executive Vice President—Operations in connection with our acquisition of the Hoosier Propane Group in January 2001. Mr. Elbert joined the Hoosier Propane Group in 1992 and was responsible for overall operations, 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 Executive Vice President—Propane Operations of Inergy Holdings GP, LLC. David G. Dehaemers, Jr. Mr. Dehaemers has served as Executive Vice President—Corporate Development since September 2003. Prior to joining Inergy, Mr. Dehaemers served as the Vice President—Corporate Development of Kinder Morgan G.P., Inc. (the general partner of Kinder Morgan Energy Partners, L.P.) and Kinder Morgan, Inc. from 2000 until 2003. He served as Vice President and Chief Financial Officer of Kinder Morgan, Inc. from 1999 until 2000. He served as Vice President, Chief Financial Officer and Treasurer of Kinder Morgan G.P., Inc. from 1997 until 2000. R. Brooks Sherman, Jr. Mr. Brooks Sherman, Jr. (no relation to Mr. John Sherman) has served as Senior Vice President since September 2002 and Chief Financial Officer since March 2001. Mr. Sherman previously 57 served as Vice President from March 2001 until September 2002. He joined our predecessor in December 2000 as Vice President and Chief Financial Officer. From 1999 until joining our predecessor, he served as Chief Financial Officer of MCM Capital Group. From 1996 through 1999, Mr. Sherman was employed by National Propane Partners, a publicly traded master limited partnership, first as its controller and chief accounting officer and subsequently as its chief financial officer. From 1995 to 1996, Mr. Sherman served as chief financial officer for Berthel Fisher & Co. Leasing Inc. and prior to 1995, Mr. Sherman was in public accounting with Ernst & Young and KPMG Peat Marwick. He also serves as Senior Vice President and Chief Financial Officer of Inergy Holdings GP, LLC. Carl A. Hughes. Mr. Hughes has served as Vice President of Business Development since March 2001. He joined our predecessor as Vice President of Business Development in 1998. From 1996 through 1998, he served as a regional manager for Dynegy Inc., responsible for propane activities in 17 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 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, including Assistant Corporate Secretary from 1996 through 2003. Prior to 1990, Ms. Ozenberger was in a private legal practice. She also serves as Vice President—General Counsel and Secretary of Inergy Holdings GP, LLC. Andrew L. Atterbury. Mr. Atterbury has served as Vice President—Corporate Strategy since 2003. Prior to that, Mr. Atterbury served as the Director of Corporate Development from 2002 to 2003. From 1999 to 2001, Mr. Atterbury worked in the Corporate Development Group of Kinder Morgan, Inc. and Kinder Morgan G.P., Inc. From 1996 through 1998, Mr. Atterbury was employed by Lehman Brothers, Inc. in its Real Estate Finance Group. 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 president and chief executive officer of Executive AirShare Corporation, an aircraft fractional ownership company, since November 2001. From August 1998 until September 2001, Mr. Taylor was president of Executive Aircraft Corporation, which sold, maintained and refurbished corporate 58 jets. In August 2002, Executive Aircraft Corporation filed a petition for Chapter 11 protection in the U.S. Bankruptcy Court for the District of Kansas and has subsequently emerged from court protection. Mr. Taylor serves as a director of 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. 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, 2006, 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. 59 Item 11. Executive Compensation. Executive Compensation The following table sets forth for the periods indicated, the compensation paid or accrued (by us or our affiliates) to the chief executive officer of our managing general partner and four other executive officers for services rendered to us and our subsidiaries. In this report, we refer to these five individuals as the “named executive officers.” Summary Compensation Table Annual Compensation Awards Payouts Long Term Compensation Other Annual Compen- sation ($)(1) Restricted Stock Awards ($) Securities Underlying Options/ SARs (#) LTIP Payouts ($) All Other Compen- sation ($) Name and Principal Position John. J. Sherman . . . . . . . . . . . . President and Chief Executive Officer Phillip L. Elbert . . . . . . . . . . . . . Executive Vice President Propane Operations R. Brooks Sherman, Jr. . . . . . . . Senior Vice President and Chief Financial Officer Laura L. Ozenberger . . . . . . . . . Vice President, General Counsel and Secretary Carl A. Hughes . . . . . . . . . . . . . Vice President-Business Development Fiscal Year 2006 2005 2004 2006 2005 2004 2006 2005 2004 2006 2005 2004 2006 2005 2004 Salary Bonus $300,000 $251,506 $250,000 $300,000 $300,000 $ — $240,000 $236,667 $200,000 $240,000 $240,000 $ — $ — $ — $ — $ — $ — $ — $200,000 $178,409 $170,000 $200,000 $300,000(3) $ — $ — $ — $ — $189,363 $155,637 $155,000 $175,000 $275,000(3) $ — $ — $ — $ — $175,000 $126,425 $125,000 $175,000 $175,000 $ — $ — $ — $ — $ — $ — $ — $ — $ — $ — $ — $ — $ — $ — $ — $ — $ — $ — $ — — — — — — — — — — — — — — — — $ — $ — $ — $ — $ — $ — $ — $ — $ — $ — $ — $ — $ — $ — $ — $625,000(2) $ — $ — $250,000(2) $125,000(2) $125,000(2) $100,000(2) $ 50,000(2) $ 50,000(2) $200,000(2) $ — $ — $400,000(2) $ — $ — (1) (2) (3) Excludes perquisites and other benefits, unless the aggregate amount of such compensation is equal to the lesser of $50,000 or 10% of the total annual salary and bonus reported for the named executive officer. Payment of a bonus conditioned upon the conversion of subordinated units. Includes a non-recurring payment of a bonus of $100,000 paid by Inergy Holdings, LP as a result of the completion of the initial public offering of Inergy Holdings, LP. There were no grants of unit options under the Inergy Long Term Incentive Plan to a named executive officer during fiscal 2006. However, in 2005 the following named executive officers were granted 40,000 unit options under the Inergy Holdings Long Term Incentive Plan: Phillip L. Elbert, R. Brooks Sherman and Laura L. Ozenberger. In 2005, Carl A. Hughes was granted 30,000 unit options under the Inergy Holdings Long Term Incentive Plan. 60 The following table sets forth information with respect to each named executive officer concerning the number and value of exercisable and unexercisable unit options held under the Inergy Long Term Incentive Plan as of September 30, 2006. Aggregated Option/SAR Exercises in last Fiscal Year and September 30, 2006 Option Values Name John J. Sherman . . . . . . . . . . . . Phillip L. Elbert . . . . . . . . . . . . R. Brooks Sherman, Jr. . . . . . . . Laura L. Ozenberger . . . . . . . . . Carl A. Hughes . . . . . . . . . . . . . Units Acquired on Exercise (#) — 111,000 55,500 — — Value Realized ($) — 1,767,601 905,558 — — Number of Securities Underlying Unexercised Options at September 30, 2006 Value of Unexercised In- the-Money Options at September 30, 2006(1) Exercisable Unexercisable Exercisable Unexercisable — — — — 77,700 — — 20,000 50,000 — $ — $ — $ — — $ $1,261,848 $ — $ — $250,400 $577,000 $ — (1) Based on the $27.24 per unit fair market value of our common units on September 29, 2006, the last trading day of fiscal 2006, less the option exercise price. Employment Agreements The following named executive officers have entered into employment agreements with our company: • • John J. Sherman, President and Chief Executive Officer; Phillip L. Elbert, Executive Vice President—Propane Operations; • R. Brooks Sherman, Jr., Senior Vice President—Chief Financial Officer; • Laura L. Ozenberger, Vice President—General Counsel and Secretary; and • Carl A. Hughes, 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 exceptions as set forth below. The employment agreements are for terms of approximately three or five years. The annual salaries for these individuals are as follows: • • John J. Sherman Phillip L. Elbert • R. Brooks Sherman, Jr. • Laura L. Ozenberger • Carl A. Hughes $300,000 $240,000 $200,000 $175,000 $175,000 These employees are reimbursed for all expenses in accordance with the managing general partner’s policies. They are also eligible for fringe benefits normally provided to other members of executive management and any other benefits agreed to by the managing general partner. Each of these employees is eligible to participate in the Inergy Long Term Incentive Plan. All of the individuals are each eligible for annual performance bonuses upon meeting certain established criteria for each year during the term of his or her employment. For the fiscal year ended September 30, 2006, the amount of the annual performance bonus for these individuals was primarily based upon attaining certain levels of growth in distributable cash flow per unit. 61 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, 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. Pursuant to the partnership agreement, we will reimburse Inergy Holdings or its affiliates for all expenses of the employment of these individuals related to our activities. Long-Term Incentive Plan Our managing general partner sponsors the Inergy Long-Term Incentive Plan for its directors, consultants and employees and the employees and consultants of its affiliates who perform services for us. The summary of the long-term incentive plan contained herein does not purport to be complete but outlines its material provisions. The long-term incentive plan permits the grant of awards covering an aggregate of 1,735,100 common units which are granted in the form of unit options, phantom units and/or restricted units. Through September 30, 2006, we have granted an aggregate of 1,067,564 unit options and 58,756 restricted units pursuant to the Inergy Long-Term Incentive Plan. The plan is administered by the compensation committee of the managing general partner’s board of directors. Restricted Units. A restricted unit is a common unit that vests over a period of time and that during such time is subject to forfeiture. The compensation committee may make grants of restricted units to employees, directors and consultants containing such terms as the compensation committee determines. The compensation committee will determine the period over which restricted units granted to participants will vest. The compensation committee, in its discretion, may base its determination upon the achievement of specified financial objectives or other events. In addition, the restricted units will vest upon a change in control of the managing general partner of Inergy. If a grantee’s employment, consulting arrangement or membership on the board of directors terminates for any reason, the grantee’s restricted units will be automatically forfeited unless, and to the extent, the compensation committee or the terms of the award agreement provide otherwise. The company intends the restricted units to serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation of the common units. Therefore, plan participants will not pay any consideration for the common units they receive, and Inergy will receive no cash remuneration for the units. Phantom Units. A phantom unit entitles the grantee to receive a common unit upon vesting of the phantom unit or, in the discretion of the compensation committee, cash equivalent to the value of the common unit. We have not granted phantom units under the long-term incentive plan. In the future, the compensation committee may determine to make grants of phantom units under the plan to employees, consultants and directors containing such terms as the compensation committee determines. The compensation committee will determine the period over which phantom units granted to employees and members of our board will vest. The committee, in its discretion, may base its determination upon the achievement of specified financial objectives or other events. In addition, the phantom units will vest upon a Change in Control. If a grantee’s employment, consulting arrangement or membership on the board of directors terminates for any reason, the grantee’s phantom units will be automatically forfeited unless, and to the extent, the compensation committee or the terms of the award agreement provide otherwise. 62 The company intends the issuance of any common units upon vesting of the phantom units under the plan to serve as a means of incentive compensation for the performance and not primarily as an opportunity to participate in the equity appreciation of our common units. Therefore, plan participants will not pay any consideration for the common units they receive, and we will receive no remuneration for the units. Unit Options. The long-term incentive plan currently permits, and our managing general partner has made, grants of options covering common units. Pursuant to the plan, the compensation committee determines which employees and directors shall be granted options and the number of units that will be granted to such individual. Unit options will have an exercise price equal to the fair market value of the units on the date of grant. In general, unit options granted will become exercisable over a period determined by the compensation committee. In addition, under most unit option grants, the unit options will become exercisable upon a change of control of the managing general partner or us. Generally, unit options will expire after 10 years. Upon exercise of a unit option, the managing general partner will acquire common units in the open market, or directly from us or any other person, or use common units already owned by the managing general partner, or any combination of the foregoing. The managing general partner will be entitled to reimbursement by us for the difference between the cost incurred by the managing general partner in acquiring these common units and the proceeds received by the managing general partner from an optionee at the time of exercise. Thus, the cost of the unit options will be borne by us. If we issue new common units upon exercise of the unit options, the total number of common units outstanding will increase and the managing general partner will pay us the proceeds it received from the optionee upon exercise of the unit options. The unit option plan has been designed to furnish additional compensation to employees and directors and to align their economic interests with those of common unitholders. Termination and Amendment. The managing general partner’s board of directors in its discretion may terminate the long-term incentive plan at any time with respect to any common units for which a grant has not yet been made. The managing general partner’s board of directors also has the right to alter or amend the long-term incentive plan or any part of the plan from time to time, including increasing the number of common units with respect to which awards may be granted subject to unitholder approval as required by the exchange upon which the common units are listed at that time. However, no change in any outstanding grant may be made that would materially impair the rights of the participant without the consent of the participant. Unit Purchase Plan Our managing general partner sponsors a unit purchase plan for its employees and the employees of its affiliates. The unit purchase plan permits participants to purchase common units in market transactions from us, our general partners or any other person. All purchases made have been in market transactions, although our plan allows us to issue additional units. We have reserved 100,000 units for purchase under the unit purchase plan. As determined by the compensation committee, the managing general partner may match each participant’s cash base pay or salary deferrals by an amount up to 10% of such deferrals and have such amount applied toward the purchase of additional units. The managing general partner has also agreed to pay the brokerage commissions, transfer taxes and other transaction fees associated with a participant’s purchase of common units. The maximum amount that a participant may elect to have withheld from his or her salary or cash base pay with respect to unit purchases under this plan in any calendar year may not exceed 10% of his or her base salary or wages for the year. Units purchased on behalf of a participant under the unit purchase plan generally are to be held by the participant for at least one year. To the extent a participant desires to sell or dispose of such units prior to the end of this one year holding period, the participant will be ineligible to participate in the unit purchase plan again until the one year anniversary of the date of such sale. The unit purchase plan is intended to serve as a means for encouraging participants to invest in our common units. Common units purchased through the unit purchase plan for the fiscal years ended September 30, 2006, 2005 and 2004 were 12,159 units, 10,496 units, and 9,518 units, respectively. 63 Reimbursement of Expenses of the Managing General Partner Our managing general partner does not receive any management fee or other compensation for its management of Inergy, L.P. Our managing general partner and its affiliates are reimbursed for expenses incurred on our behalf. These expenses include the costs of employee, officer and director compensation and benefits properly allocable to us and all other expenses necessary or appropriate to the conduct of the business of, and allocable to, us. Our partnership agreement provides that our managing general partner will determine the expenses that are allocable to us in any reasonable manner determined by our managing general partner in its sole discretion. Compensation of Directors Officers of our managing general partner who also serve as directors will not receive additional compensation. Mr. Gfeller received an option under our long term incentive plan for 44,400 common units at an exercise price of $11.00 (based on the initial public offering price—split adjusted). Upon joining the board of directors, Mr. Krause received an option under our long-term incentive plan for 40,000 common units at an exercise price of $16.87 (split adjusted) and upon joining the board of directors, Mr. Taylor received an option under our long-term incentive plan for 20,000 common units at an exercise price of $31.32 (equal to the closing trading price on the NASDAQ National Market of our common units on the grant date). In addition, each director receives cash compensation of $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 3, 2006 Messrs. Geller, Krause, Taylor and Pascal each received 939 restricted units under the long term incentive plan. Each non-employee director is reimbursed for out-of-pocket expenses in connection with attending meetings of the board of directors or committees. Each director is fully indemnified for actions associated with being a director to the extent permitted under Delaware law. Compensation Committee Interlocks and Insider Participation The compensation committee of the board of directors of our managing general partner oversees the compensation of our executive officers. Arthur B. Krause and Warren H. Gfeller serve as the members of the compensation committee, and neither of them was an officer or employee of our company or any of its subsidiaries during fiscal 2006. 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, 2006, 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. 64 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) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,787,340 Bonavita, Inc. (fka United Propane, Inc.)(3) (7) 203 Romancoke Rd. Stevensville, MD 21666 . . . . . . . . . . . . . . . . . . . . 2,289,269 8.4% 5.1% 8.4% 5.1% Kayne Anderson Capital Advisors, L.P. and Richard A. Kayne(4) . . . . . 1800 Avenue of the Stars, 2nd FL Los Angeles, CA 90067 3,704,596 8.2% 8.2% John J. Sherman Trusts(5) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,862,483 8.5% Phillip L. Elbert . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — — Andrew L. Atterbury . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20,000 David G. Dehaemers, Jr. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . R. Brooks Sherman, Jr. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Laura L. Ozenberger . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Carl A. Hughes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Warren H. Gfeller(6),(7) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Arthur B. Krause(7) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Robert D. Taylor(7) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8,000 3,320 3,663 90,065 58,067 13,439 12,694 Robert A. Pascal(3),(7) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,289,269 All directors and executive officers as a group (11 persons) . . . . . . 6,361,000 * * * * 0.2% 0.1% * * 5.1% 14.1% 8.5% — * * * * 0.2% 0.1% * * 5.1% 14.1% 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 New Inergy Propane, 789,202 units are held by IPCH Acquisition Corp., both wholly-owned subsidiaries of Inergy Holdings, and 161,104 are held directly by Inergy Holdings. In addition, Inergy Holdings holds 769,941 Special Units that will convert to common units at a specified conversion rate upon the commercial operations of the Phase II expansion project of our natural gas storage facility (Stagecoach). (3) 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 United Propane, Inc., is deemed beneficial owner of the partnership units in Inergy, L.P. held by United Propane, Inc. Information as to the number of common units is furnished in reliance upon the Schedule 13G’s of the corresponding entities or individuals. (4) (5) Mr. Sherman holds an ownership interest in Inergy Holdings through the John J. Sherman Revocable Trust, the John J. Sherman 2005 Grantor Retained Annuity Trusts I and II and has voting control. As trustee of the John J. Sherman Revocable Trust, Mr. John Sherman may be deemed to beneficially own 3,862,483 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 New Inergy Propane, LLC, of which Inergy Holdings L.P. (formerly Inergy Holdings, LLC) has 100% voting control, 161,104 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 75,143 common units are held by the John J. Sherman Revocable Trust or by John J. Sherman. (6) Mr. Gfeller in his capacity as managing member of Clayton-Hamilton, LLC may be deemed to beneficially own 12,728 common units (7) held by Clayton-Hamilton. Includes 939 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. 65 The following table shows the beneficial ownership as of November 1, 2006 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 8.4% of our outstanding limited partner units. Name of Beneficial Owner (1) John J. Sherman Trusts(2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . David G. Dehaemers, Jr.(3) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Phillip L. Elbert(4) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Paul E. McLaughlin(5) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . William C. Gautreaux(6) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Andrew L. Atterbury . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Carl A. Hughes(7) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . R. Brooks Sherman Jr. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 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 (12 persons) Inergy Holdings, L.P. Percent of Class 42.74% 7.60% 5.35% 5.34% 5.22% 5.25% 4.76% 2.31% * * * — * — 68.14% * (1) Less than 1% The address of each person listed above is Two Brush Creek Boulevard, Suite 200, Kansas City, Missouri 64112, other than Paul E. McLaughlin, whose address is 1201 Walnut, Kansas City, Missouri 64141. (2) Mr. Sherman may be deemed to beneficially own (i) the 7,977,347 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) the 320,153 common units held by the John J. Sherman 2005 Grantor Retained Annuity Trust II under trust indenture dated March 31, 2005, of which Mr. Sherman serves as co-trustee, and (iv) Mr. Sherman holds 225 units through the Employee Unit Purchase Plan. (3) Mr. Dehaemers may be deemed to beneficially own the 107,272 common units held by the David G. Dehaemers, Jr. 2005 Grantor Retained Annuity Trust under trust indenture dated March 31, 2005, of which Mr. Dehaemers serves as co-trustee. (4) Mr. Elbert may be deemed to beneficially own (i) 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, (ii) the 40,225 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 (iii) the 40,225 common units held by the Lauren E. Elbert Trust under trust indenture dated March 31, 2005, of which Mr. Elbert serves as co-trustee. (5) Mr. McLaughlin may be deemed to beneficially own (i) 241,350 the common units held by the Paul E. McLaughlin 2005 Grantor Retained Annuity Trust under trust indenture dated March 31, 2005, of which Mr. McLaughlin serves as co-trustee, and (ii) 826,205 common units held by the Paul E. McLaughlin Revocable Trust under trust indenture dated April 24, 2003 of which Mr. McLaughlin serves as co-trustee. (6) 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. (7) Mr. Hughes may be deemed to beneficially own (i) the 710,442 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. 66 Item 13. Certain Relationships and Related Transactions. Related Party Transactions In connection with our acquisition of assets from United Propane, Inc. on July 31, 2003, we entered into ten leases of real property formerly used by United Propane (now known as Bonavita, Inc.) in its business. We entered into five of these leases with United Propane, three of these leases with Pascal Enterprises, Inc. and two of these leases with Robert A. Pascal. Each of these leases provides for an initial five-year term, and is renewable by us for up to two additional terms of five years each. During the initial term of these leases we are required to make monthly rental payments totaling $59,167, of which $17,167 is payable to United Propane, $16,800 is payable to Pascal Enterprises, and $25,200 is payable to Mr. Pascal. On May 1, 2004, Inergy Propane, LLC entered into a lease agreement with United Leasing, Inc. to lease a propane rail terminal known as the Curtis Bay Terminal for the base monthly rent of $15,000. 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. On August 9, 2005 we entered into the Special Unit Purchase Agreement with Inergy Holdings L.P. Inergy Holdings purchased 769,941 special units (the “Special Units”) for $25 million in cash from us. These units are not entitled to current cash distributions, but are convertible to our common units at a special conversion ratio upon the Phase II expansion becoming commercially operational. The purchase price was based on the ten-day average closing price for the common units ending August 8, 2005. On August 9, 2005, we also entered into a separate Registration Rights Agreement with Inergy Holdings relating to the Special Units that allows for the registered resale of these units. On February 10, 2006 we filed a shelf registration statement with the SEC for the resale of the common units issuable upon conversion of the Special Units. 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, 2006 we did not have an amount due from Inergy Holdings. 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 non-managing general partner and its affiliates would receive a 67 distribution of approximately $0.6 million on the approximate 1% general partner interest and a distribution of approximately $4.5 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, 2006, 2005 and 2004 the expense reimbursement to our managing general partner and its affiliates was approximately $8.7, $3.0, and $2.9 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 9.4% 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, 2006 and 2005 (in thousands): For the fiscal year ended September 30, 2006 2005 Audit fees(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Audit-related fees(2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $2,852 101 $1,427 146 Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $2,953 $1,573 (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 2006. 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. 68 PART IV Item 15. Exhibits and Financial Statement Schedules (a) Exhibits, Financial Statements and Financial Statement Schedules: 1. Financial Statements: See Index Page for Financial Statements located on page 74. 2. Financial Statement Schedules: Valuation and Qualifying Accounts Other financial statement schedules have been omitted because they either are not required, are immaterial or are not applicable or because equivalent information has been included in the financial statements, the notes thereto or elsewhere herein. 3. Exhibits: Exhibit Number *2.1 *2.2 *3.1 *3.1 A *3.2 *3.2 A *3.2 B *3.2 C *3.3 Description 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) 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) 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) 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) 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) 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) 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) 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) 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) 69 Exhibit Number *3.4 *3.5 *3.6 *3.7 *3.8 *4.1 *4.2 *4.3 *4.4 *4.5 *4.6 *4.7 *4.8 *10.1 *10.2 *10.3 Description 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) 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) 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) 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) 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) 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) 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) 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) Registration Rights Agreement (incorporated herein by reference to Exhibit 4.1 to Inergy, L.P.’s Form 8-K filed on December 27, 2004) Indenture (incorporated herein by reference to Exhibit 4.2 to Inergy, L.P.’s Form 8-K filed on December 27, 2004) 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) Registration Rights Agreement (incorporated herein by reference to Exhibit 4.1 to Inergy L.P.’s Form 8-K filed on January 18, 2006) Indenture (incorporated herein by reference to Exhibit 4.2 to Inergy L.P.’s Form 8-K filed on January 18, 2006) 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) 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) 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) 70 Exhibit Number *10.4 *10.5 *10.5 A *10.6 *10.6 A *10.6 B *10.7 *10.7 A *10.8 *10.8 A *10.9 *10.10 *10.10A *10.11 *10.12 *10.13 Description Inergy Long-Term Incentive Plan (as amended and restated January 1, 2006) (incorporated herein by reference to Exhibit 10.2 to Inergy, L.P.’s Form 8-K filed on February 14, 2006)*** 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)*** 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)*** 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)*** 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)*** 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)*** 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)*** 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)*** Employment Agreement—Laura L. Ozenberger (incorporated herein by reference to exhibit 10.8 to Inergy L.P.’s Form 10-K filed on December 13, 2005)*** First Amendment to Employment Agreement—Laura L. Ozenberger (incorporated herein by reference to exhibit 10.8A to Inergy L.P.’s Form 10-K filed on December 13, 2005)*** 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) 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)*** 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)*** Separation Agreement and Release with Dean Watson dated August 27, 2005 (incorporated herein by reference to Exhibit 10.1 to Inergy L.P.’s Form 8-K filed on August 29, 2005)*** 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)*** 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) 71 Exhibit Number *10.13A *10.14 *10.15 *10.16 *10.17 *10.18 *10.19 *10.20 *10.21 *10.22 *10.23 **12.1 *14.1 Description 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) 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) 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) 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) 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) 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) 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) 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) 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) 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) 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)*** Computation of ratio of earnings to fixed charges Inergy’s Code of Business Ethics and Conduct 72 Exhibit Number Description **21.1 List of subsidiaries of Inergy, L.P. **23.1 Consent of Ernst & Young LLP **31.1 Certification of the Chief Executive Officer pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended **31.2 Certification of Chief Financial Officer pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended **32.1 Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 **32.2 Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 Previously filed * ** Filed herewith *** Management contracts or compensatory plans or arrangements required to be identified by Item 15(a). (b) Exhibits. See exhibits identified above under Item 15(a)3. (c) Financial Statement Schedules. See financial statement schedules identified above under Item 15(a)2. 73 Inergy, L.P. and Subsidiaries Consolidated Financial Statements September 30, 2006 and 2005 and each of the Three Years in the Period Ended September 30, 2006 Contents Report of Independent Registered Public Accounting Firm . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Report of Independent Registered Public Accounting Firm on Internal Controls . . . . . . . . . . . . . . . . . . . . . . . Audited Consolidated Financial Statements Consolidated Balance Sheets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Consolidated Statements of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Consolidated Statements of Partners’ Capital . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Consolidated Statements of Cash Flows . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Notes to Consolidated Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 75 76 77 78 79 80 82 74 Report of Independent Registered Public Accounting Firm The Board of Directors and Unitholders of Inergy, L.P. We have audited the accompanying consolidated balance sheets of Inergy, L.P. and Subsidiaries (the Partnership) as of September 30, 2006 and 2005, and the related consolidated statements of operations, partners’ capital, and cash flows for each of the three years in the period ended September 30, 2006. 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 Partnership’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Inergy, L.P. and Subsidiaries at September 30, 2006 and 2005, and the consolidated results of their operations and their cash flows for each of the three years in the period ended September 30, 2006 in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein. We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Inergy, L.P. and Subsidiaries’ internal control over financial reporting as of September 30, 2006, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated November 30, 2006 expressed an unqualified opinion thereon. /s/ ERNST & YOUNG LLP Kansas City, Missouri November 30, 2006 75 Report of Independent Registered Public Accounting Firm on Internal Controls The Board of Directors and Unitholders of Inergy, L.P. and Subsidiaries We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control over Financial Reporting, that Inergy, L.P. and Subsidiaries maintained effective internal control over financial reporting as of September 30, 2006, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Inergy, L.P. and Subsidiaries’ management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the company’s internal control over financial reporting based on our audit. We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. As indicated in the accompanying Management’s Report on Internal Control over Financial Reporting and as permitted by the Securities and Exchange Commission, management’s assessment of and conclusion on the effectiveness of internal control over financial reporting did not include the internal controls of its 2006 acquisitions which are included in the 2006 consolidated financial statements of Inergy, L.P. and Subsidiaries and constituted $132.5 million and $144.1 million in total assets and revenues, respectively. Our audit of internal control over financial reporting of Inergy, L.P. and Subsidiaries also did not include an evaluation of the internal control over financial reporting of its 2006 acquisitions. In our opinion, management’s assessment that Inergy, L.P. and Subsidiaries maintained effective internal control over financial reporting as of September 30, 2006, is fairly stated, in all material respects, based on the COSO criteria. Also, in our opinion, Inergy, L.P. and Subsidiaries maintained, in all material respects, effective internal control over financial reporting as of September 30, 2006, based on the COSO criteria. We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements of Inergy, L.P. and Subsidiaries and our report dated November 30, 2006 expressed an unqualified opinion thereon. Kansas City, Missouri November 30, 2006 /s/ ERNST & YOUNG LLP 76 Inergy, L.P. and Subsidiaries Consolidated Balance Sheets (in thousands, except unit information) Assets Current assets: Cash . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accounts receivable, less allowance for doubtful accounts of $2,876 and $2,356 at September 30, 2006 and 2005, respectively . . . . . . . . . . . . . . . . . . . . . . . . . . Inventories (Note 4) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Assets from price risk management activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Prepaid expenses and other current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Property, plant and equipment (Note 4) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Less: accumulated depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Property, plant and equipment, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Intangible assets (Note 2): Customer accounts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Covenants not to compete . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Trademarks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Deferred financing costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Deferred acquisition costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Less: accumulated amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Intangible assets, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Goodwill . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . September 30, 2006 2005 $ 12,044 $ 9,500 99,486 108,048 46,197 29,811 295,586 847,944 124,411 723,533 226,032 54,195 32,845 22,985 305 336,362 52,826 283,536 332,350 94,876 117,812 58,356 22,674 303,218 804,774 72,756 732,018 161,000 30,606 32,845 20,444 725 245,620 30,972 214,648 249,173 Other assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4,030 $1,639,035 3,187 $1,502,244 Liabilities and partners’ capital Current liabilities: Accounts payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accrued expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Customer deposits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Liabilities from price risk management activities . . . . . . . . . . . . . . . . . . . . . . . . . . Current portion of long-term debt (Note 6) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Long-term debt, less current portion (Note 6) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other long-term liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Partners’ capital (Note 8): Common unitholders (45,005,153 and 34,411,329 units issued and outstanding as of September 30, 2006 and 2005, respectively) . . . . . . . . . . . . . . . . . . . . . . . Senior subordinated unitholders (0 and 3,821,884 units issued and outstanding as of September 30, 2006 and 2005, respectively) . . . . . . . . . . . . . . . . . . . . . . . . . Junior subordinated unitholders (0 and 1,145,084 units issued and outstanding as of September 30, 2006 and 2005, respectively) . . . . . . . . . . . . . . . . . . . . . . . . . Special unitholders (769,941 units issued and outstanding as of September 30, 2006 and 2005, respectively) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Non-managing general partner and affiliate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total partners’ capital . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total liabilities and partners’ capital . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 81,463 62,915 97,959 49,044 16,868 308,249 642,804 11,830 $ 104,148 44,366 68,567 49,572 17,931 284,584 541,800 11,966 648,773 623,861 — — 14,276 (3,163) 25,000 2,379 676,152 $1,639,035 25,000 3,920 663,894 $1,502,244 See accompanying notes to the consolidated financial statements. 77 Inergy, L.P. and Subsidiaries Consolidated Statements of Operations (in thousands, except per unit data) Year Ended September 30, 2006 2005 2004 Revenue: Propane . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $1,072,261 315,300 $ 851,613 198,523 $431,202 51,294 Cost of product sold (excluding depreciation and amortization as shown below) Propane . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Gross profit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Expenses: Operating and administrative . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Loss on disposal of assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Operating income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other income (expense): Interest expense, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Write-off of deferred financing costs . . . . . . . . . . . . . . . . . . . . . . . . . . Make whole premium charge . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Swap value received . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Finance charges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Income (loss) before income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Provision for income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,387,561 1,050,136 482,496 779,694 210,705 990,399 397,162 248,139 76,720 11,446 60,857 (53,842) — — — 2,650 813 10,478 667 593,360 130,863 724,223 325,913 197,082 50,364 679 77,788 (34,150) (6,990) — — 1,817 235 38,700 63 334,231 24,822 359,053 123,443 81,296 21,089 203 20,855 (7,878) (1,216) (17,949) 949 704 106 (4,429) 167 Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 9,811 $ 38,637 $ (4,596) Partners’ interest information: Non-managing general partners and affiliate’s interest in net income: . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Limited partners’ interest in net income (loss): Common unit interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Senior subordinated unit interest . . . . . . . . . . . . . . . . . . . . . . . . . Junior subordinated unit interest Total limited partners’ interest in net income (loss) . . . . . . . . . . . . . . Net income (loss) per limited partner unit: Basic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Weighted average limited partners’ units outstanding: Basic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ $ $ $ $ 17,920 $ 8,133 $ 1,182 (8,880) $ 593 178 24,235 5,147 1,122 $ (3,664) (1,814) (300) (8,109) $ 30,504 $ (5,778) (0.20) $ (0.20) $ 0.98 0.96 $ $ (0.26) (0.26) 41,407 41,407 31,143 22,027 31,853 22,027 See accompanying notes to the consolidated financial statements. 78 Inergy, L.P. and Subsidiaries Consolidated Statements of Partners’ Capital (in thousands) Common Unit Capital Senior Subordinated Unit Capital Junior Subordinated Unit Capital Non-Managing General Partners and Affiliate Special Unit Capital Total Partners’ Capital Balance at September 30, 2003 . . . . . . . . . . . . . . . $128,983 $ 46,703 $ (164) $ 3,461 $ — $ 178,983 Net proceeds from issuance of common units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 113,219 Contribution from non-managing general partners . . . . . . . . . . . . . . . . . . . . . . . . . . . — — — — — Senior subordinated units converted to common units . . . . . . . . . . . . . . . . . . . . . . Members’ distributions . . . . . . . . . . . . . . . . . Comprehensive income: 8,127 (22,076) (8,127) (11,416) — (1,833) Net income (loss) . . . . . . . . . . . . . . . . . . Foreign currency translation . . . . . . . . . (3,664) 11 (1,814) 6 (300) 1 Comprehensive income (loss) . . . . . . . . . . — — 113,219 1,791 — (2,047) 1,182 — — — — — — 1,791 — (37,372) (4,596) 18 (4,578) Balance at September 30, 2004 . . . . . . . . . . . . . . . 224,600 25,352 (2,296) 4,387 — 252,043 Net proceeds from issuance of common units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 410,554 Net proceeds from the issuance of Special Units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — — — — — — — — 410,554 25,000 25,000 Senior subordinated units converted to common units . . . . . . . . . . . . . . . . . . . . . . Distributions . . . . . . . . . . . . . . . . . . . . . . . . . Comprehensive income: Net income . . . . . . . . . . . . . . . . . . . . . . . Unrealized gain on derivative instruments . . . . . . . . . . . . . . . . . . . . Foreign currency translation . . . . . . . . . Comprehensive income (loss) . . . . . . . . . . 6,099 (45,909) (6,099) (11,034) — (2,187) — (8,681) 24,235 5,147 1,122 8,133 4,229 53 898 12 196 2 80 1 — — — — — (67,811) 38,637 5,403 68 44,108 Balance at September 30, 2005 . . . . . . . . . . . . . . . 623,861 14,276 (3,163) 3,920 25,000 663,894 Net proceeds from issuance of common units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 127,391 Net proceeds from common unit options exercised . . . . . . . . . . . . . . . . . . . . . . . . . . 4,050 Subordinated units converted to common — — — — units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 958 (6,414) 5,456 Contribution from unit based compensation charges . . . . . . . . . . . . . . . . . . . . . . . . . . . . Distributions . . . . . . . . . . . . . . . . . . . . . . . . . Comprehensive income: 641 (77,577) — (8,368) — (2,445) Net income (loss) . . . . . . . . . . . . . . . . . . Unrealized loss on derivative (8,880) instruments . . . . . . . . . . . . . . . . . . . . Foreign currency translation . . . . . . . . . (21,672) 1 593 (87) — 178 (26) — Comprehensive income (loss) . . . . . . . . . . — — — — (19,215) 17,920 (246) — — 127,391 4,050 — — — 641 — (107,605) — — — 9,811 (22,031) 1 (12,219) Balance at September 30, 2006 . . . . . . . . . . . . . . $648,773 $ — $ — $ 2,379 $25,000 $ 676,152 See accompanying notes to the consolidated financial statements. 79 Inergy, L.P. and Subsidiaries Consolidated Statements of Cash Flows (in thousands) Operating activities Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Adjustments to reconcile net income to net cash provided by operating activities: Year Ended September 30, 2006 2005 2004 $ 9,811 $ 38,637 $ (4,596) Depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Loss on disposal of assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Provision for doubtful accounts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Amortization of deferred financing costs . . . . . . . . . . . . . . . . . . . . . . . . . Unit based compensation charges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net assets (liabilities) from price risk management activities . . . . . . . . . Write-off of deferred financing costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . Make whole premium charge . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Changes in operating assets and liabilities, net of effects from acquisitions: Accounts receivable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Inventories . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Prepaid expenses and other current assets . . . . . . . . . . . . . . . . . . . . Accounts payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accrued expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Customer deposits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 54,611 22,109 11,446 3,579 2,234 641 (10,400) — — 4,655 28,392 (6,193) (47,375) 12,423 18,944 (405) 37,328 13,036 679 1,966 1,825 — (10,008) 6,990 — (19,722) (34,669) 482 19,364 13,820 18,511 (599) 15,325 5,764 203 214 1,686 — 9,730 1,216 17,949 (23,157) (19,048) (1,526) 24,321 (280) 4,089 37 Net cash provided by operating activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . 104,472 87,640 31,927 Investing activities Acquisitions, net of cash acquired . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Purchases of property, plant and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . Proceeds from sale of assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Deferred acquisition costs incurred . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (187,214) (34,509) 11,484 (686) (810,053) (34,093) 4,141 (621) (85,154) (14,292) 2,245 (900) Net cash used in investing activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (210,925) (840,626) (98,101) 80 Inergy, L.P. and Subsidiaries Consolidated Statements of Cash Flows (continued) (in thousands) Year Ended September 30, 2006 2005 2004 Financing activities . . . . . . . . . . . . . . . . . . . . . . . . . Proceeds from issuance of long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . Principal payments on long-term debt Net proceeds from issuance of common units . . . . . . . . . . . . . . . . . . . . . . Net proceeds from unit options exercised . . . . . . . . . . . . . . . . . . . . . . . . . . Deferred financing costs incurred . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Distributions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net proceeds from issuance of Special Units . . . . . . . . . . . . . . . . . . . . . . . Payment of make whole premium charge . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Contribution from non-managing general partner $ 706,100 (615,909) 127,391 4,050 (5,031) (107,605) — — — $ 1,614,579 (1,198,682) 410,554 — (23,478) (67,811) 25,000 — — $ 372,407 (367,238) 113,219 — 26 (37,372) — (17,949) 1,791 Net cash provided by financing activities . . . . . . . . . . . . . . . . . . . . . . . . . . 108,996 760,162 64,884 Effect of foreign exchange rate changes on cash . . . . . . . . . . . . . . . . . . . . Net increase (decrease) in cash . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Cash at beginning of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 2,544 9,500 Cash at end of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 12,044 Supplemental disclosure of cash flow information Cash paid during the year for interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 50,914 68 7,244 2,256 9,500 28,549 18 (1,272) 3,528 2,256 6,251 $ $ $ $ Supplemental schedule of non-cash investing and financing activities Additions to covenants not to compete through the issuance of noncompete obligations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 9,613 $ 7,881 $ 2,569 Additions to property, plant and equipment through accounts payable and accrued expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4,168 29 229 Decrease in the fair value of long-term debt and the related interest rate swap . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (3,589) (1,647) (316) Acquisitions, net of cash acquired: Current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Property, plant and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Intangible assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Goodwill . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Non-compete liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 32,414 29,722 87,515 83,835 153 (36,812) (9,613) $ $ 76,655 520,215 138,799 171,046 2,359 (91,140) (7,881) 6,304 60,503 19,079 11,531 — (9,694) (2,569) $ 187,214 $ 810,053 $ 85,154 See accompanying notes to the consolidated financial statements. 81 Inergy, L.P. and Subsidiaries Notes to Consolidated Financial Statements Note 1. Organization and Basis of Presentation 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”) and its subsidiary Inergy Sales and Service Inc. (“Services”), Inergy Acquisition Company, 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 the 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 the Partnership and all other necessary or appropriate expenses allocable to the Partnership or otherwise reasonably incurred by Inergy GP in connection with operating the Partnership business. These costs, which totaled approximately $8.7 million, $3.0 million, and $2.9 million for the years ended September 30, 2006, 2005, and 2004, respectively, include compensation, bonuses and benefits paid to officers and employees of Inergy GP and its affiliates. As of September 30, 2006, Holdings owns an aggregate 9.4% 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 1% general partnership interest and 8.4% 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. Basis of Presentation The accompanying consolidated financial statements include the accounts of Inergy, L.P. and its subsidiaries, Inergy Propane as well as all of Inergy Propane’s wholly-owned subsidiaries. All significant intercompany balances and transactions have been eliminated in consolidation. 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. 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 82 Inergy, L.P. and Subsidiaries Notes to Consolidated Financial Statements—(Continued) its exposure to interest rate risk. Inergy records all derivative instruments on the balance sheet as either assets or liabilities measured at fair value under the provisions of Statement of Financial Accounting Standards 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 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 $(16.6) million and $5.4 million at September 30, 2006 and 2005, 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 $77.6 million, $56.4 million and $28.2 million during the years ended September 30, 2006, 2005, and 2004, respectively. Credit Risk and Concentrations Inergy is both a retail and wholesale supplier of propane gas. Inergy generally extends unsecured credit to its wholesale customers in the United States and Canada. Credit is generally extended to retail customers through delivery into Company and customer owned propane gas storage tanks. Provisions for doubtful accounts 83 Inergy, L.P. and Subsidiaries Notes to Consolidated Financial Statements—(Continued) receivable are based on specific identification and historical collection results and have generally been within management’s expectations. Finance charges on trade receivables are generally recognized upon billing of customers. 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 as of September 30, 2006. Two suppliers, Sunoco, Inc. (14%) and Exxon Mobil Oil Corp. (11%), accounted for approximately 25% 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 inventories are designated under a fair value hedge program and are consequently marked to market. All Wholesale propane inventories being hedged and carried at market value at September 30, 2006 and 2005 amount to $67.8 million and $85.8 million, respectively. Inventories for facility and 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: Buildings and improvements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Office furniture and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Vehicles . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Tanks and plant equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Years 25 – 40 3 – 10 5 – 10 5 – 30 84 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, 2006. See Note 4 for a discussion of assets held for sale at September 30, 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: Customer accounts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Covenants not to compete . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Deferred financing costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Years 15 2 – 10 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 thousands): Year Ending September 30, 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $24,839 22,933 22,496 20,812 20,090 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 face 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. 85 Inergy, L.P. and Subsidiaries Notes to Consolidated Financial Statements—(Continued) In connection with the goodwill impairment evaluation, the reporting units are identified, which for the Company includes 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. 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, 2006. 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 for the years ended September 30, 2006, 2005 and 2004 was $667,000, $63,000 and $167,000, respectively. At September 30, 2006, the Company had cumulative temporary differences between the book and tax basis of Services of approximately $6.1 million, comprised primarily of a net operating loss carryforward. At September 30, 2006, this results in a deferred tax asset of approximately $2.3 million, which the Company has fully reserved with a valuation allowance of $2.3 million. 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. 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. 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 $649.4 million and $540.1 million as of September 30, 2006 and 2005, respectively. See Note 5 for the fair value of the Company’s derivative financial instruments. 86 Inergy, L.P. and Subsidiaries Notes to Consolidated Financial Statements—(Continued) 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 thousands): Foreign Currency Translation Adjustment Unrealized Gains (Losses) on Derivative Instruments Accumulated Other Comprehensive Income (Loss) As of September 30, 2004 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other Comprehensive income . . . . . . . . . . . . . . . . . . . . . . . . $ As of September 30, 2005 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other Comprehensive income (loss)(a) As of September 30, 2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 18 50 68 (67) 1 $ — 5,403 5,403 (22,031) $ 18 5,453 5,471 (22,098) $(16,628) $(16,627) (a) Other comprehensive income (loss) includes a reclassification of $5,403 to net income during the year ended September 30, 2006. 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, and the subordinated unitholder’s interest, by the weighted average number of limited partner units outstanding. 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) 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. 87 Inergy, L.P. and Subsidiaries Notes to Consolidated Financial Statements—(Continued) The following table presents the calculation of basic and dilutive net income per limited partner unit (in thousands, except per unit data): Year Ended September 30, 2006 2005 2004 Numerator: Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 9,811 $38,637 $ (4,596) Less: Non-managing general partners’ and affiliates interest in net income . . . . . . 17,920 8,133 1,182 Limited partners’ interest in net income (loss)—diluted . . . . . . . . . . . . . . . . . . . . . Less: Senior subordinated interest in net income (loss) . . . . . . . . . . . . . . . . . . . . . . Less: Junior subordinated interest in net income (loss) . . . . . . . . . . . . . . . . . . . . . . $ (8,109) $30,504 5,147 1,122 593 178 $ (5,778) (1,814) (300) Common unit interest in net income (loss)—basic . . . . . . . . . . . . . . . . . . . . . . . . . $ (8,880) $24,235 $ (3,664) Denominator: Weighted average common units outstanding—basic . . . . . . . . . . . . . . . . . . . . . . . Effect of converting senior subordinated units . . . . . . . . . . . . . . . . . . . . . . . . Effect of converting junior subordinated units . . . . . . . . . . . . . . . . . . . . . . . . . Effect of dilutive units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37,094 3,319 994 — 24,742 5,256 1,145 710 13,968 6,914 1,145 — Weighted average limited partners’ units outstanding—dilutive . . . . . . . . . . . . . . 41,407 31,853 22,027 Net income (loss) per limited partner unit: Basic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ (0.20) $ $ (0.20) $ 0.98 0.96 $ (0.26) $ (0.26) Net income per limited partner unit for the senior subordinated units and the junior subordinated units was the same as net income per common limited partner unit for 2005 and 2004. As the effects of including incremental units associated with options were antidilutive for the years ended September 30, 2006 and 2004, due to the limited partners’ interest being a net loss for those periods, 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 years ended September 30, 2006 and 2004. Weighted average antidilutive unit options outstanding totaled 463,620 and 468,412 for the years ended September 30, 2006 and 2004, respectively. 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 (revised 2004), “Share-Based Payment” (“SFAS 123R”), which is a revision of SFAS No. 123, “Accounting for Stock-Based Compensation”. SFAS 123(R) supersedes APB Opinion No. 25, “Accounting for Stock Issued to Employees” (“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 88 Inergy, L.P. and Subsidiaries Notes to Consolidated Financial Statements—(Continued) 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 year ended September 30, 2006 was approximately $0.6 million, including approximately $0.3 million related to unit based compensation for Holdings. 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 years ended September 30, 2005 and 2004. For purposes of pro forma disclosures, the estimated fair value of an option is amortized to expense over the option’s vesting period (in thousands, except per unit data): Net income (loss) as reported . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Deduct: Total unit-based employee compensation expense determined under 2005 2004 $38,637 $(4,596) fair value method for all awards . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 195 227 Pro forma net income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $38,442 $(4,823) Deduct: Non-managing general partners and affiliate’s interest in net income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 8,133 $ 1,182 Pro forma limited partners’ interest in net income (loss) . . . . . . . . . . . . . . . . . . . $30,309 $(6,005) Net income (loss) per limited partner unit Basic—as reported . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Basic—pro forma . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Diluted—as reported . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Diluted—pro forma . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ $ $ $ 0.98 0.97 0.96 0.95 $ (0.26) $ (0.27) $ (0.26) $ (0.27) 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. 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 Inergy for the fiscal year ended September 30, 2008. The Company will be evaluating the potential financial statement impact of SFAS 157 to its consolidated financial statements. 89 Inergy, L.P. and Subsidiaries Notes to Consolidated Financial Statements—(Continued) SFAS No. 155, “Accounting for Certain Hybrid Financial Instruments” (“SFAS 155”) amends SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” 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. SFAS 155 is effective for all financial instruments acquired or issued after the beginning of an entity’s first fiscal year that begins after September 15, 2006. The Company will be evaluating the potential financial statement impact of SFAS 155 to its consolidated financial statements. 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 is effective for the accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. The adoption of SFAS 154 is not expected to have an impact on the Company’s consolidated financial statements. In March 2005, the Financial Accounting Standards Board (“FASB”) issued FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations—an interpretation of SFAS No. 143” (“FIN 47”). FIN 47 clarifies that the term conditional retirement obligation, as used in SFAS No. 143, “Asset Retirement Obligations,” refers to a legal obligation to perform an asset retirement activity in which the timing or method of settlement, or both, are conditional on a future event that may or may not be within the control of the entity. An entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. FIN 47 was required to be adopted by Inergy for the fiscal year ended September 30, 2006. The Company has evaluated the impact of FIN 47 and determined that it does not have a material effect on the consolidated financial statements in the current year as well as all prior years considered. EITF 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty” addresses the accounting for an entity’s sale of inventory to another entity from which it also purchases inventory to be sold in the same line of business. EITF 04-13 concludes that two or more inventory transactions with the same counterparty should be accounted for as a single non-monetary transaction at fair value or recorded amounts based on inventory classifications. EITF 04-13 is effective for new arrangements entered into, and modifications or renewal of existing arrangements, beginning in the first interim or annual reporting period beginning after March 15, 2006. The Company has adopted the provisions of EITF 04-13, which did not have a material effect on its financial position, results of operations and cash flows. Note 3. Acquisitions During the fiscal year ended September 30, 2006, Inergy made ten acquisitions, including Dowdle Gas, Inc. headquartered in Columbus, MS, Graeber Brothers, Inc. headquartered in Batesville, MS, Propane Gas Service, Inc. headquartered in South Windsor, CT, Atlas Gas Products, Inc. headquartered in Costonia, OH, Country Gas Inc. headquartered in Sumiton, AL, and five smaller retail propane companies, (collectively “the Acquisitions”). The aggregate purchase price for the Acquisitions, net of cash acquired was $186.3 million. The operating results for all the Acquisitions are included in the consolidated results of operations from the dates of acquisition through September 30, 2006. The purchase price allocation for Dowdle Gas, Inc. has been finalized and all 90 Inergy, L.P. and Subsidiaries Notes to Consolidated Financial Statements—(Continued) applicable changes are reflected in the accompanying consolidated financial statements. The purchase price allocations for all other acquisitions have been prepared on a preliminary basis pending final asset valuation and asset rationalization, and changes are expected when additional information becomes available. 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 2006 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 2006 acquisitions, the Company acquired $35.2 million of goodwill and $54.1 million of intangible assets, consisting primarily of customer accounts and non-compete agreements. The weighted average amortization period of amortizable intangible assets acquired during the year ended September 30, 2006, is approximately 12 years. During the fourth quarter of 2006, Inergy finalized its purchase price allocation of the fair value of Stagecoach’s assets based on a third party valuation. Based on this valuation, the Company recorded a purchase price adjustment which decreased the value of its fixed assets (including land and buildings) and accumulated depreciation by $84.4 million and $4.3 million, respectively, increased customer accounts and goodwill by $35.1 million and $50.6 million, respectively, and decreased non-competes by $1.3 million. Note 4. Certain Balance Sheet Information Inventories Inventories consist of the following at September 30, 2006 and 2005, respectively (in thousands): Propane gas and other liquids . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Appliances, parts and supplies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 96,097 11,951 $110,085 7,727 2006 2005 $108,048 $117,812 Property, Plant and Equipment Property, plant and equipment consists of the following at September 30, 2006 and 2005, respectively (in thousands): Tanks and plant equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Land and buildings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Vehicles . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Construction in process . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Office furniture and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Less accumulated depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2006 2005 $578,452 135,481 89,267 24,720 20,024 847,944 124,411 $559,403 155,335 66,223 6,758 17,055 804,774 72,756 Property, plant and equipment, net . . . . . . . . . . . . . . . . . . . . . . . . . . $723,533 $732,018 Depreciation expense totaled $54.6 million, $37.3 million, and $15.3 million for the years ended September 30, 2006, 2005 and 2004, respectively. 91 Inergy, L.P. and Subsidiaries Notes to Consolidated Financial Statements—(Continued) During 2006, the Company capitalized $0.4 million of interest related to certain Midstream asset expansion projects. This amount is reflected in construction in process. There was no interest capitalized in the prior year. As discussed in Note 3, the Company recorded a purchase price adjustment in the fourth quarter of 2006 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, 2006 include approximately $6.8 million of propane operations assets deemed held for sale under the provisions of SFAS 144. These assets were identified during the fourth quarter of 2006 as a result of the final integration of the larger retail propane acquisitions closed since November 2004 as Inergy has focused on eliminating redundant operations, mostly including 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 a loss of approximately $6.6 million for the year ended September 30, 2006. This $6.6 million charge is included as a component of operating income as a loss on disposal of assets. When aggregated with other realized losses, such amounts totaled $11.4 million. 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 these derivative financial instruments to manage its exposure to fluctuations in commodity prices and to the variability of future cash flows. The effects of commodity price volatility have generally been mitigated by Inergy’s attempts to maintain a balanced portfolio of derivative financial instruments and inventory positions in terms of notional amounts. Notional Amounts and Terms The notional amounts and terms of these financial instruments include the following at September 30, 2006 and 2005 (in millions): September 30, 2006 2005 Fixed Price Payor Fixed Price Receiver Fixed Price Payor Fixed Price Receiver Propane and heating oil (barrels) . . . . . . . . . . . . . Natural gas (MMBTU’s) . . . . . . . . . . . . . . . . . . . . 8.0 5.5 7.5 5.4 11.0 1.9 12.7 1.9 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. 92 Inergy, L.P. and Subsidiaries Notes to Consolidated Financial Statements—(Continued) Fair Value The fair value of the derivatives and inventory exchange contracts related to price risk management activities as of September 30, 2006 and September 30, 2005 was assets of $46.2 million and $58.4 million, respectively, and liabilities of $49.0 million and $49.6 million, respectively. All intercompany transactions have been appropriately eliminated. 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. 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 propane based financial instruments, for the years ended September 30, 2006, 2005 and 2004 of $(39.5) million, $24.1 million, and $(1.2) million, respectively, are included in cost of product sold in the accompanying consolidated statements of operations. 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 from the previous year is a non-cash gain of $19.4 million related to derivative contracts. No similar gain or loss was recognized in the year ended September 30, 2004. 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, 2006 and 2005 where settlement has not yet occurred (in thousands): Year Ended September 30, 2006 Year Ended September 30, 2005 Net fair value gain (loss) of contracts outstanding at beginning of year . . . . Net unrealized gain acquired through acquisition during the year . . . . . . . . Net change in physical exchange contracts . . . . . . . . . . . . . . . . . . . . . . . . . . Change in fair value of contracts attributable to market movement during the year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Realized gains . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net fair value of contracts outstanding at end of year . . . . . . . . . . . . . . . . . . $ 8,784 — (592) (4,400) (6,639) $(2,847) $ (6,626) 1,881 1,508 16,689 (4,668) $ 8,784 Of the outstanding unrealized gain (loss) as of September 30, 2006 and 2005, $(2.7) million and $8.8 million have or will mature within 12 months, respectively. Contracts with a maturity of greater than one year were not significant. During the years ended September 30, 2006, 2005, and 2004, Inergy recognized a net gain of less than $0.1 million, a net loss of $0.2 million and $0.1 million, respectively, related to the ineffective portion of its fair value commodity hedging instruments and a net loss of $0.4 million, $0.6 million, and $1.0 million, respectively, related to the portion of the fair value commodity hedging instruments excluded from the assessment of hedge effectiveness. 93 Inergy, L.P. and Subsidiaries Notes to Consolidated Financial Statements—(Continued) 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 losses recorded in other comprehensive income as of September 30, 2006 in the amount of $16.6 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, 2006 and 2005, there was no material ineffectiveness related to cash flow hedges. As of September 30, 2005, there was $5.4 million in other comprehensive income which was reclassified to earnings during the fiscal year ended September 30, 2006, 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 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, 2006 and 2005 were propane retailers, resellers, energy marketers and dealers. Note 6. Long-Term Debt Long-term debt consisted of the following (in thousands): Credit agreement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Senior unsecured notes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Obligations under non-compete agreements and notes to former owners of businesses acquired . . . . . . . . . . . . . . . . . . . . . . . . . . . Less current portion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . September 30, 2006 2005 $ 22,700 621,411 $126,800 423,352 15,561 659,672 16,868 9,579 559,731 17,931 $642,804 $541,800 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 94 Inergy, L.P. and Subsidiaries Notes to Consolidated Financial Statements—(Continued) and those of its domestic subsidiaries and the pledge of all of the equity interests or membership interests in its domestic subsidiaries. In addition, the Credit Agreement is guaranteed by each of Inergy’s domestic subsidiaries. Inergy has the option to use up to $125.0 million of available borrowing capacity from its Acquisition Facility for working capital purposes. 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 (amount was $5 million as of September 30, 2005). As such, $10 million and $5 million of the outstanding balance at September 30, 2006 and 2005, respectively, have been classified as a long-term liability in the accompanying consolidated balance sheets. At September 30, 2006, the balance outstanding under the Credit Agreement was $22.7 million under the Working Capital Facility. At September 30, 2005, borrowings under the Credit Agreement were $126.8 million, including $20.0 million under the Working Capital Facility. The prime rate and LIBOR plus the applicable spreads were between 7.08% and 8.50% at September 30, 2006, and between 6.19% and 7.75% at September 30, 2005, 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 $369.4 million and $276.2 million at September 30, 2006 and 2005, respectively. Outstanding standby letters of credit under the Credit Agreement amounted to $32.9 million and $22.0 million at September 30, 2006 and 2005, respectively. On October 1, 2006, Inergy amended the Credit Agreement with existing lenders primarily to increase to $125.0 million from $75.0 million the effective amount of working capital borrowings available through the utilization of the Acquisition Facility. Other terms, conditions, and covenants remained materially unchanged. At September 30, 2006, 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% 95 Inergy, L.P. and Subsidiaries Notes to Consolidated Financial Statements—(Continued) 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 2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2014 and thereafter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Percentage 104.125% 102.750% 101.375% 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. 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 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2012 and thereafter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Percentage 103.438% 102.292% 101.146% 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 2014 Senior Notes and contain call provisions consistent with the underlying 2014 Senior Notes, require the counterparty to pay the Company an amount based on the stated fixed interest rate due every six months. In exchange, Inergy is 96 Inergy, L.P. and Subsidiaries Notes to Consolidated Financial Statements—(Continued) 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. Inergy recognized an approximate $3.6 million decrease in the fair market value of the related 2014 Senior Notes at September 30, 2006 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 2006 with payments due through 2014 and imputed interest ranging from 3.5% to 10.0%. Noninterest- bearing obligations consist of $19.1 million and $11.5 million in total payments due under agreements, less unamortized discount based on imputed interest of $3.5 million and $1.9 million at September 30, 2006 and 2005, 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 $10.3 million at September 30, 2006. 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 thousands): 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Thereafter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other Obligations $ 2,078 3,116 5,125 Long-term debt and Notes Payable $ 16,868 3,607 2,339 1,576 11,334 623,948 $10,319 $659,672 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 thousands): Year Ending September 30, 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Thereafter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 6,402 5,372 3,762 2,461 1,206 3,084 Total minimum lease payments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $22,287 97 Inergy, L.P. and Subsidiaries Notes to Consolidated Financial Statements—(Continued) Rent expense for operating leases for the years ending September 30, 2006, 2005, and 2004 totaled $9.6 million, $7.9 million, and $4.5 million, respectively. Inergy has certain related party leases as discussed in Note 11. Note 8. Partners’ Capital Special Units On August 9, 2005, Inergy issued for aggregate gross proceeds of $25 million, 769,941 special units (the “Special Units”), representing a new class of equity securities in Inergy that are not entitled to a current cash distribution and will convert into common units representing limited partnership interests in Inergy at a specified conversion rate upon the commercial operation of the Stagecoach expansion project. 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. Upon the commercial operation of the Stagecoach expansion project the Special Units will convert into common units at a specified conversion ratio. The initial conversion ratio is 1.0 Special Unit for 1.0 common unit with the conversion rate increasing 3% per three month period thereafter on a compounded basis with a maximum conversion ratio of 1.0 Special Unit for 1.43 common units. As of September 30, 2006, the Special Units were convertible into 866,575 common units, contingent upon the commercial operation of “Phase II” of the Company’s Stagecoach storage facility. On August 9, 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. Common Unit Offerings In December 2004, Inergy issued 3,568,139 common units to unrelated third parties resulting in proceeds of $91.0 million. These proceeds were utilized to partially fund the acquisition of Star Gas. Also in December 2004, the Company issued 4,400,000 common units in a public offering, resulting in proceeds of $121.3 million, net of underwriter’s discount, commission, and offering expenses. These funds were used to repay borrowings under the Credit Agreement. In January 2005, the underwriters of the December 2004 common unit offering exercised their over- allotment provision and issued 660,000 common units in a follow-on offering, resulting in proceeds of approximately $17.9 million, net of underwriters’ discounts, commissions, and offering expenses. These funds were used to repay borrowings under the Credit Agreement. In September 2005, Inergy, L.P. issued 6,500,000 common units to unrelated third parties resulting in net proceeds after underwriters’ discounts, commissions, and offering expenses of $180.4 million. These proceeds were obtained to repay borrowings under the Credit Agreement, which were incurred to make certain acquisitions, including the acquisition of the Stagecoach natural gas storage facility. In October 2005, the underwriters of a September 2005 6,500,000 common unit offering exercised a portion of their over-allotment provision and Inergy issued an additional 900,000 common units in a follow-on offering, resulting in proceeds of approximately $24.7 million, net of underwriters’ discounts, commissions, and offering expenses. These funds were used to repay borrowings under the Credit Agreement. 98 Inergy, L.P. and Subsidiaries Notes to Consolidated Financial Statements—(Continued) 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 to be used to fund capital expenditures made in connection with internal growth projects related to Inergy’s midstream assets. Conversion of Subordinated Units With the payment of the distribution on August 14, 2006 with respect to the quarter ended June 30, 2006, Inergy has 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 converted to common units on a one-for-one basis on August 14, 2006, in accordance with the provisions of the amended and restated Agreement of Limited Partnership of Inergy, L.P. (“Partnership 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. 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 $107.6 million, $67.8 million, and $37.4 million for the years ended September 30, 2006, 2005, and 2004, respectively, or $2.14, $1.91, and $1.60 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 99 Inergy, L.P. and Subsidiaries Notes to Consolidated Financial Statements—(Continued) 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, 2006, 2005, and 2004 were 12,159 units, 10,496 units, and 9,518 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 1,735,100 common units, which can be granted in the form of unit options and/or restricted units; however, not more than 565,600 restricted units may be granted under the plan. With the exception of 56,000 unit options (exercise prices from $1.92 to $5.34) granted to non-executive employees in exchange for option grants made by the predecessor in fiscal 1999, all of which have been grandfathered into the long-term incentive plan and are presented as grants in the table below, all 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 vests over a period of time and that during such time is subject to forfeiture. The compensation committee may make grants of restricted units to employees, directors and consultants containing such terms as the compensation committee determines. The compensation committee will determine the period over which restricted units granted to participants will vest. The compensation committee, in its discretion, may base its determination upon the achievement of specified financial objectives or other events. In addition, the restricted units will vest upon a change in control of the managing general partner of Inergy. If a grantee’s employment, consulting arrangement or membership on the board of directors terminates for any reason, the grantee’s restricted units will be automatically forfeited unless, and to the extent, the compensation committee or the terms of the award agreement provide otherwise. The Company intends the restricted units to serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation of the common units. Therefore, plan participants will not pay any consideration for the common units they receive, and Inergy will receive no cash remuneration for the units. On March 20, 2006, the compensation committee granted 20,000 restricted units. These restricted units vest over a three year period beginning three years from the grant date, subject to the achievement of certain specified performance objectives. Failure to meet the performance objectives will result in forfeiture and cancellation of the restricted units. The Company recognizes expense on these shares each quarter using an estimate of the shares expected to vest multiplied by the closing price of the Company’s common stock of $27.09 on the date of grant. 100 Inergy, L.P. and Subsidiaries Notes to Consolidated Financial Statements—(Continued) On April 3, 2006, the compensation committee granted 3,756 restricted units. These restricted units vest over a three year period beginning one year from the grant date. The Company recognizes expense on these shares each quarter using an estimate of the shares expected to vest multiplied by the closing price of the Company’s common stock of $26.62 on the date of grant. On August 1, 2006, the compensation committee granted 35,000 restricted units. These restricted units cliff vest five years from grant date. The Company recognizes expense on these shares each quarter using an estimate of the shares expected to vest multiplied by the closing price of the Company’s common of $27.01 on the date of grant. Of the total 58,756 restricted shares outstanding, the weighted average remaining contract life is 9.7 years. The compensation expense recorded by the Company related to these restricted stock awards was less than $0.1 million for the year ended September 30, 2006. 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, 2006, 2005, and 2004, is as follows: Outstanding at September 30, 2003 . . . . . . . . . . . . . . . . . . . . . . . . . . . . Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Exercised . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Canceled . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Outstanding at September 30, 2004 . . . . . . . . . . . . . . . . . . . . . . . . . . . . Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Exercised . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Canceled . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Outstanding at September 30, 2005 . . . . . . . . . . . . . . . . . . . . . . . . . . . . Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Exercised . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Canceled . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Range of Exercise Prices $ 1.92 – $20.13 $20.96 – $24.71 — $13.83 – $15.35 $ 1.92 – $24.71 $27.14 – $31.32 — $10.00 – $27.14 $ 1.92 – $31.32 $26.20 – $26.51 $ 1.92 – $16.87 $15.34 – $27.14 Weighted- Average Exercise Price $13.09 $23.11 — $14.51 $13.79 $28.90 — $16.80 $14.81 $26.27 $11.39 $18.75 Number of Units 1,077,064 84,000 — 46,000 1,115,064 95,500 — 103,000 1,107,564 6,500 355,600 46,500 Outstanding at September 30, 2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 8.19 – $31.30 $16.37 711,964 Exercisable at September 30, 2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 8.19 – $27.14 $10.95 249,464 101 Inergy, L.P. and Subsidiaries Notes to Consolidated Financial Statements—(Continued) Information regarding options outstanding and exercisable as of September 30, 2006 is as follows: Range of Exercise Prices $ 6.26 – $ 9.40 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 9.41 – $12.53 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $12.54 – $15.66 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $15.67 – $18.79 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $18.80 – $21.92 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $21.93 – $25.06 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $25.07 – $28.19 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $28.20 – $31.30 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Outstanding Weighted- Average Remaining Contracted Life (years) 0.5 4.8 5.9 6.4 7.0 7.5 8.4 8.8 6.1 Exercisable Weighted- Average Exercise Price Options Exercisable Weighted- Average Exercise Price $ 8.19 10.75 14.76 16.20 20.40 23.94 26.96 29.97 $16.37 1,864 237,600 6,000 3,000 — — 1,000 — 249,464 $ 8.19 10.75 14.50 16.04 — — 27.14 — $10.95 Options Outstanding 1,864 237,600 186,000 91,000 75,000 30,000 31,000 59,500 711,964 The weighted-average remaining contract lives for options outstanding and exercisable at September 30, 2006 were approximately six years and five 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. Weighted average fair value of options granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Expected volatility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Distribution yield . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Expected life of option in years . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Risk-free interest rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2006 2005 2004 $ 1.28 0.167 $ 1.36 0.158 $ 1.41 0.159 8.0% 7.0% 5 5 4.6% 3.5% 6.9% 5 3.2% The aggregate intrinsic values of options outstanding and exercisable at September 30, 2006 were $7.9 million and $4.1 million, respectively. The aggregate intrinsic value of unit options exercised during the year ended September 30, 2006 was $5.6 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 $27.24 on September 29, 2006, and the exercise price multiplied by the number of options outstanding. As of September 30, 2006, there was $3.6 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 $1.9 million related to Holdings unvested share-based compensation awards. That cost is expected to be recognized over a period of five years. 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 $15,000 in 2006. 102 Inergy, L.P. and Subsidiaries Notes to Consolidated Financial Statements—(Continued) 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 $1.8 million, $1.2 million, and $0.4 million in 2006, 2005, and 2004, respectively. Of Inergy’s 3,021 employees, approximately 5% are subject to collective bargaining agreements. For the years ended September 30, 2006 and 2005, Inergy made contributions on behalf of its union employees to union sponsored defined benefit plans of $2.6 million and $1.5 million, respectively. Union contributions in 2004 were insignificant. 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, 2006, the total of these firm purchase commitments was approximately $356.5 million. The Company also enters into 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. At September 30, 2006, Inergy was contingently liable for letters of credit outstanding totaling $32.9 million, which guarantees various transactions. 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, 2006 and 2005, Inergy’s self- insurance reserves were $11.2 million and $6.4 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. In connection with the financing of the Phase II expansion rights on the Stagecoach natural gas storage facility, on August 9, 2005 Inergy entered into the Special Unit Purchase Agreement with Holdings, which 103 Inergy, L.P. and Subsidiaries Notes to Consolidated Financial Statements—(Continued) purchased 769,941 Special Units for $25 million in cash from the Company. These units are not entitled to current cash distributions, but are convertible to common units at a special conversion ratio upon the Phase II expansion becoming commercially operational. The purchase price was based on the ten-day average closing price for the common units ending August 8, 2005. On August 9, 2005, Inergy also entered into a separate Registration Rights Agreement with Holdings relating to the Special Units that allows for the registered resale of these 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 occasion, Holdings reimburses the Company for expenses paid on behalf of Holdings. At September 30, 2006, Inergy did not have an amount due from Holdings. As of September 30, 2005, Inergy had a receivable of $0.3 million from Holdings. The managing general partner and its affiliates will not receive any management fee or other compensation for the management of the Company. The managing general partner and its affiliates will be reimbursed, however, for direct and indirect expenses incurred on Inergy’s behalf. For the fiscal years ended September 30, 2006, 2005 and 2004 the expense reimbursement to the managing general partner and its affiliates was approximately $8.7, $3.0, and $2.9 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, 2006 are included in the propane 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 related to the propane segment. 104 Inergy, L.P. and Subsidiaries Notes to Consolidated Financial Statements—(Continued) Revenues, gross profit, identifiable assets and goodwill for each of Inergy’s reportable segments are presented below (in thousands): Year Ended September 30, 2006 Propane Operations Midstream Operations Intersegment Eliminations Retail propane revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Wholesale propane revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . Storage, fractionation and other midstream revenues . . . . . . . . . Transportation revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Propane-related appliance sales revenues . . . . . . . . . . . . . . . . . . Retail service revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Rental service and other revenues . . . . . . . . . . . . . . . . . . . . . . . . Distillate revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Gross profit Identifiable assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Goodwill $701,048 351,673 — 10,124 23,670 16,708 19,947 91,753 354,815 192,253 258,434 $ — $ — — — — — — — — — — — 19,540 153,098 — — — — — 42,347 15,281 73,916 Year Ended September 30, 2005 Propane Operations Midstream Operations Intersegment Eliminations Retail propane revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Wholesale propane revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . Storage, fractionation and other midstream revenues . . . . . . . . . Transportation revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Propane-related appliance sales revenues . . . . . . . . . . . . . . . . . . Retail service revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Rental service and other revenues . . . . . . . . . . . . . . . . . . . . . . . . Distillate revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Gross profit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Identifiable assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Goodwill $526,531 305,457 — 11,145 11,260 14,770 12,360 71,981 307,077 196,295 226,579 $ — $ — — — — — — — — — — — 19,625 77,007 — — — — — 18,836 20,968 22,594 Year Ended September 30, 2004 Propane Operations Midstream Operations Intersegment Eliminations Retail propane revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Wholesale propane revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . Storage, fractionation and other midstream revenues . . . . . . . . . Transportation revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Propane-related appliance sales revenues . . . . . . . . . . . . . . . . . . Retail service revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Rental service and other revenues . . . . . . . . . . . . . . . . . . . . . . . . Distillate revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Gross profit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Identifiable assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Goodwill $196,312 226,183 — 7,649 4,803 3,428 3,716 2,212 111,056 97,196 75,628 $ — $ — — — — — — — — — — — 8,707 29,486 — — — — — 12,387 8,649 — Total $701,048 371,213 153,098 10,124 23,670 16,708 19,947 91,753 397,162 207,534 332,350 Total $526,531 325,082 77,007 11,145 11,260 14,770 12,360 71,981 325,913 217,263 249,173 Total $196,312 234,890 29,486 7,649 4,803 3,428 3,716 2,212 123,443 105,845 75,628 105 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 thousands, except per unit information): December 31 March 31 June 30 September 30 Quarter Ended Fiscal 2006 Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Gross profit(a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Operating income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net income (loss) per limited partner unit: $450,266 112,474 23,607 10,704 $476,822 151,237 75,212 61,829 $215,618 65,377 (19,524) (32,365) $244,855 68,074 (18,438) (30,357) Basic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ $ 0.17 0.16 $ $ 1.41 1.40 $ $ (0.90) (0.90) $ $ (0.79) (0.79) Fiscal 2005 Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Gross profit(a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Operating income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net income (loss) per limited partner unit:(b) $257,465 64,688 21,225 11,001 $414,428 136,513 64,870 54,959 $173,602 50,604 (15,609) (24,119) $204,641 74,108 7,302 (3,204) Basic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ $ 0.41 0.40 $ $ 1.52 1.49 $ $ (0.72) (0.72) $ $ (0.18) (0.18) (a) During 2006, gross profit reflects a non-cash loss associated with derivative contracts of approximately $20.0 million, of which $19.4 is the reversal of the non-cash gain recorded in the quarter ended September 30, 2005, and an additional $0.6 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. For the quarter ended September 30, 2005 gross profit reflects a non-cash gain associated with derivative contracts of $19.4 million which reversed in the first two quarters of 2006 as the physical gallons were 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 1, 2006, Inergy acquired Bath Storage Facility, located in Bath, NY, a liquefied petroleum gas (“LPG”) storage facility from Bath Petroleum Storage, Inc. Bath Storage is a salt cavern storage facility located near Bath, New York, northwest of New York City and near Inergy’s Stagecoach facility. The facility is supported by both rail and truck terminals. On October 6, 2006, Inergy acquired the assets of Columbus Butane Company, Inc. , and related companies (Columbus Butane) headquartered in Columbus, MS. Columbus Butane delivers retail propane from 13 retail locations. On October 31, 2006, Inergy acquired the assets of Hometown Propane, Inc. headquartered in Campbell, NY and on November 8, 2006, Inergy acquired the assets of Mideastern Oil Company, Inc. headquartered in Salisbury, MD. On November 14, 2006, a quarterly distribution of $.555 per limited partner unit was paid to unitholders of record on November 7, 2006 with respect to the fourth fiscal quarter of 2006, which totaled $31.2 million. 106 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. SIGNATURES INERGY, L.P. By Inergy GP, LLC (its managing general partner) Dated: December 6, 2006 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 December 6, 2006 December 6, 2006 December 6, 2006 December 6, 2006 December 6, 2006 December 6, 2006 December 6, 2006 Signature and Title /s/ JOHN J. SHERMAN John J. Sherman, President, Chief Executive Officer and Director (Principal Executive Officer) /s/ R. BROOKS SHERMAN, JR. R. Brooks Sherman, Jr., Senior Vice President and Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer) /s/ PHILLIP L. ELBERT Phillip L. Elbert, Director /s/ WARREN G. GFELLER Warren H. Gfeller, Director /s/ ARTHUR B. KRAUSE Arthur B. Krause, Director /s/ ROBERT A. PASCAL Robert A. Pascal, Director /s/ ROBERT D. TAYLOR Robert D. Taylor, Director 107 Inergy, L.P. and Subsidiaries Valuation and Qualifying Accounts (in thousands) Schedule II Year ended September 30, Allowance for doubtful accounts 2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2005 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2004 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Balance at beginning of period Charged to costs and expenses Other Additions (recoveries) Deductions (write-offs) Balance at end of period $2,356 1,078 997 $3,579 1,966 214 $ 913 87 1,125 $(3,972) (775) (1,258) $2,876 2,356 1,078 Exhibit 31.1 CERTIFICATIONS I, John J. Sherman, certify that: 1. I have reviewed this annual report on Form 10-K of Inergy, L.P. (the “registrant”); 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over the financial reporting (as defined in Exchange Act Rules 13a-15(f)) for the registrant and have: a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and preparation of financial statements for external purposes in accordance with generally accepted accounting principles; c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and 5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions): a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. Date: December 6, 2006 /s/ JOHN J. SHERMAN John J. Sherman President and Chief Executive Officer Exhibit 31.2 CERTIFICATIONS I, R. Brooks Sherman, Jr., certify that: 1. I have reviewed this annual report on Form 10-K of Inergy, L.P. (the “registrant”); 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over the financial reporting (as defined in Exchange Act Rules 13a-15(f)) for the registrant and have: a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and preparation of financial statements for external purposes in accordance with generally accepted accounting principles; c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and 5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions): a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. Date: December 6, 2006 /s/ R. BROOKS SHERMAN, JR. R. Brooks Sherman, Jr. Senior Vice President and Chief Financial Officer 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 Exhibit 32.1 In connection with the Annual Report of Inergy, L.P. (the “Company”) on Form 10-K for the period ended September 30, 2006 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, John J. Sherman, Chief Executive Officer of Inergy, L.P., certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that: (1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and (2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. Date: December 6, 2006 /s/ JOHN J. SHERMAN John J. Sherman Chief Executive Officer A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request. 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 Exhibit 32.2 In connection with the Annual Report of Inergy, L.P. (the “Company”) on Form 10-K for the period ended September 30, 2006 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, R. Brooks Sherman, Jr., Chief Financial Officer of Inergy, L.P., certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that: (1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and (2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. Date: December 6, 2006 /s/ R. BROOKS SHERMAN, JR. R. Brooks Sherman, Jr. Chief Financial Officer A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request. OFFICERS—INERGY, L.P. John J. Sherman* President and Chief Executive Officer Philip L. Elbert* Executive Vice President, Propane Operations David G. Dehaemers, Jr. Executive Vice President, Corporate Development R. Brooks Sherman, Jr.* Senior Vice President and Chief Financial Officer Andrew L. Atterbury Vice President, Corporate Strategy Carl A. Hughes Vice President, Business Development Laura L. Ozenberger* Vice President and General Counsel Michael J. Campbell Vice President and Treasurer William C. Gautreaux Vice President, Supply and Wholesale Marketing Stanley A. Ross Vice President and Corporate Controller *Also an officer for Inergy Holdings, L.P. PROPANE OPERATIONS LEADERSHIP Ted Jeffcoat Vice President/Retail Operations—East Chris Cafarella President/Mid-Atlantic Division Dave Feheley President/Western New England Division Steve Merhar President/Eastern New England Division John Miller President/Eastern Ohio/Western Pennsylvania Division Bruce Tripp President/New York/Pennsylvania Division Jay Cates Vice President/Retail Operations—South Steve Boyle President/Florida Division James Devens President/Virginia/North Carolina Division Tom Haiar President/Mississippi/Alabama Division INERGY’S EXECUTIVE MANAGEMENT TEAM From left to right: Andy Atterbury, Brooks Sherman, Carl Hughes (seated), David Dehaemers, John Sherman, Phil Elbert and Laura Ozenberger Mike Vaughn President/Texas/Oklahoma Division MIDSTREAM OPERATIONS LEADERSHIP Marlo Young Vice President/Retail Operations—Midwest Dave Bertelsen President/Northern Ohio Division Craig Courts President/Michigan Division Gary Komosa President/Illinois Division Dan Manson President/Indiana Division Ed Moreno President/Wisconsin Division Dave Wright President/Southern Ohio Division Joe Donnell President/L&L Transportation Tom Wright Director/Fleet Operations Richard Kreul Vice President, Inergy Services William Moler Vice President, Midstream Operations DIRECTORS—INERGY HOLDINGS, L.P. John J. Sherman Warren H. Gfeller Arthur B. Krause Richard T. O’Brien DIRECTORS—INERGY, L.P. John J. Sherman Phillip L. Elbert Warren H. Gfeller Arthur B. Krause Robert A. Pascal Robert D. Taylor INVESTOR RELATIONS Michael Campbell Two Brush Creek Blvd., Suite 200 Kansas City, MO 64112 1-877-4-INERGY investorrelations@inergyservices.com K-1 INFORMATION For Inergy, L.P. (NRGY) call 1-800-230-1134 For Inergy Holdings, L.P. (NRGP) call 1-866-792-0046 TRANSFER AGENT American Stock Transfer & Trust Company 59 Maiden Lane, Plaza Level New York, NY 10038 Shareholder Services: 1-800-937-5449 Info@AmStock.com Two Brush Creek Blvd., Suite 200, Kansas City, MO 64112 Phone: 816-842-8181 Fax: 816-531-0746 www.inergypropane.com