Form 10-Q

(Former name, former address and former fiscal year, if changed since last report)

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

Indicate by check mark whether the registrant 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.

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

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

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

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

Pursuant to a partnership agreement, Inergy GP or any of its affiliates is entitled to reimbursement for all direct and indirect expenses incurred or payments it makes on behalf of Inergy and all other necessary or appropriate expenses allocable to Inergy or otherwise reasonably incurred by Inergy GP in connection with operating the Company’s business. These costs, which totaled approximately $0.5 million and $0.6 million for the three months ended June 30, 2007 and 2006, and $5.5 million and $4.2 million for the nine months ended June 30, 2007 and 2006, respectively, include compensation, bonuses and benefits paid to officers and employees of Inergy GP and its affiliates.

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

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 propane market is seasonal because propane is used primarily for heating in residential and commercial buildings, as well as for agricultural purposes. Inergy’s retail operations are primarily concentrated in the Midwest, Northeast, and South regions of the United States.

The financial information contained herein as of June 30, 2007 and for the three-month and nine-month periods ended June 30, 2007 and 2006 is unaudited. The Company believes this information has been prepared in accordance with accounting principles generally accepted in the United States for interim financial information and Article 10 of Regulation S-X. The Company also believes this information includes all adjustments (consisting only of normal recurring adjustments) necessary to present fairly the financial position, results of operations and cash flows for the periods then ended. The retail distribution business is largely seasonal due to propane’s primary use as a heating source in residential and commercial buildings. Accordingly, the results of operations for the three-month and nine-month periods ended June 30, 2007 are not indicative of the results of operations that may be expected for the entire fiscal year.

The accompanying consolidated financial statements should be read in conjunction with the consolidated financial statements of Inergy, L.P. and subsidiaries and the notes thereto included in Form 10-K as filed with the Securities and Exchange Commission for the fiscal year ended September 30, 2006.

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

Inergy utilizes certain derivative financial instruments to (i) manage its exposure to commodity price risk, specifically, the related change in the fair value of inventories, as well as the variability of cash flows related to forecasted transactions; (ii) ensure adequate physical supply of commodity will be available; and (iii) manage its 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 recognized an immaterial net gain in both the three and nine months ended June 30, 2007, related to the ineffective portion of its fair value hedging instruments. In addition, during the three and nine months ended June 30, 2007, Inergy recognized a net loss of $0.3 million and a net gain of $0.9 million, respectively, related to the portion of fair value hedging instruments that Inergy excluded from its assessment of hedge effectiveness.

Inergy also enters into derivative financial instruments that qualify as cash flow hedges, which hedge the exposure of variability in expected future cash flows predominantly attributable to forecasted purchases to supply fixed price sale contracts. These derivatives are recorded on the balance sheet at fair value as price risk management assets or liabilities. The effective portion of the gain or loss on these cash flow hedges is recorded in other comprehensive income in partner’s capital and reclassified into earnings in the same period in which the hedge transaction affects earnings. Any ineffective portion of the gain or loss is recognized as cost of product sold in the current period. Accumulated other comprehensive income was $2.4 million and $7.9 million at June 30, 2007 and 2006, respectively.

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

Sales of propane and other liquids are recognized at the later of the time the 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.

Cost of product sold consists of tangible products sold including all propane, distillates and 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 $19.5 million and $18.6 million for the three months ended June 30, 2007 and 2006, respectively, and $62.6 million and $60.0 million for the nine months ended June 30, 2007 and 2006, respectively.

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 for retail operations, which mainly consist of propane gas and other liquids, are stated at the lower of cost or market and are computed using the average-cost method. Wholesale propane and other liquids inventories are designated under a fair value hedge program and are consequently marked to market. All wholesale propane and other liquids inventories being hedged and carried at market value at June 30, 2007 and September 30, 2006 amount to $44.4 million and $67.8 million, respectively. Inventories for midstream operations are stated at the lower of cost or market determined using the first-in-first-out method.

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

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 amortized over the term of the related debt. Additionally, an acquired intangible asset is separately recognized if the benefit of the intangible asset is obtained through contractual or other legal rights, or if the intangible asset can be sold, transferred, licensed, rented or exchanged, regardless of the acquirer’s intent to do so.

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

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

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

The Company calculates basic net income per unit by dividing net income, after considering the Non-Managing General Partner’s interest, including priority distributions, beneficial conversion value (see Note 6), and the subordinated unitholder’s interest, by the weighted average number of limited partner units outstanding. When applicable, basic net income per unit is calculated for subordinated units by dividing the earnings allocated to each class of subordinated units by the weighted average number of units outstanding. Under this method, the calculation of net income per unit reflects an allocation of earnings to each class of units that is consistent with the partnership agreement’s treatment of the respective classes’ capital accounts. Diluted net income per limited partner unit is computed by dividing net income, after considering the Non-Managing General Partner’s interest, by the sum of (a) weighted average number of common units, (b) if applicable, the additional common units that would be issued assuming the subordinated units were converted to common units, and (c) the effect of other dilutive units.

As the effect of including incremental units associated with options were antidilutive for the three months ended June 30, 2007 and 2006 due to the net loss reported for those periods, no unit options or other dilutive units were reflected in the applicable dilutive earnings per unit computations. As a result, both basic earnings per unit and diluted earnings per unit reflect the same calculation for the three-month periods ended June 30, 2007 and 2006, respectively. Weighted average antidilutive unit options outstanding totaled 184,471 and 463,783 for the three months ended June 30, 2007 and 2006, respectively.

Inergy has a unit-based employee compensation plan, which is accounted for under the provisions of Statement of Financial Accounting Standards (“SFAS”) No. 123(R), “Share-Based Payment” (“SFAS 123(R)”). SFAS 123(R) supersedes APB Opinion No. 25, “Accounting for Stock Issued to Employees” (“APB 25”), and amends SFAS No. 95, “Statement of Cash Flows.” SFAS 123(R) requires all share-based payments to employees, including grants of employee stock options, to be recognized in the income statement based on their fair values.

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

The amount of compensation expense recorded by the Company under the provisions of SFAS 123(R) during the nine months ended June 30, 2007 and 2006 was approximately $0.5 million and $0.2 million, respectively. The compensation expense for the nine months ended June 30, 2007 includes unit-based compensation expense for options on Inergy Holdings, L.P. units.

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 8 for disclosures related to Inergy’s propane and midstream segments.

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

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

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

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

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

At June 30, 2007 and September 30, 2006, the Company had capitalized interest of $2.4 million and $0.4 million, respectively, related to certain midstream asset expansion projects. These amounts are reflected in construction in process.

The Company’s credit agreement (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”). On October 1, 2006, Inergy amended the Credit Agreement with existing lenders primarily to increase the effective amount of working capital borrowings available through the utilization of the Acquisition Facility from $75 million to $125 million. Other terms, conditions, and covenants remained materially unchanged. The Credit Agreement is guaranteed by each of Inergy’s domestic subsidiaries.

At June 30, 2007 and September 30, 2006, the balance outstanding under the Credit Agreement was $1.3 million and $22.7 million, respectively, all drawn under the Working Capital Facility. The interest rates of these revolvers are based on prime rate and LIBOR plus the applicable spreads, which was 8.25% at June 30, 2007, and between 7.08% and 8.50% at September 30, 2006, for all outstanding debt under the Credit Agreement. Unused borrowings under the Credit Agreement amounted to $397.2 million and $369.4 million at June 30, 2007 and September 30, 2006, respectively. Outstanding standby letters of credit under the Credit Agreement amounted to $26.5 million and $32.9 million at June 30, 2007 and September 30, 2006, respectively.

Inergy is party to five interest rate swap agreements scheduled to mature in December 2014, each designed to hedge $25 million in underlying fixed rate senior unsecured notes in order to manage interest rate risk exposure. These swap agreements, which expire on the same date as the maturity date of the related senior unsecured notes due 2014 and contain call provisions consistent with the underlying senior unsecured notes, require the counterparty to pay the Company an amount based on the stated fixed interest rate due every six months. In exchange, Inergy is required to make semi-annual floating interest rate payments on the same dates to the counterparty based on an annual interest rate equal to the 6-month LIBOR interest rate plus spreads between 0.92% and 2.20% applied to the same notional amount of $125 million. The swap agreements have been recognized as fair value hedges. Amounts to be received or paid under the agreements are accrued and recognized over the life of the agreements as an adjustment to interest expense. At June 30, 2007, Inergy had recorded an approximate $5.7 million reduction in the fair market value of the related senior unsecured notes with a corresponding change in the fair value of its interest rate swaps, which are recorded in other long-term liabilities.

During October 2006, Inergy closed the following three asset acquisitions: a natural gas liquids storage facility located near Bath, New York (the “Bath Storage Facility”), Columbus Butane Company, Inc., and Hometown Propane, Inc. In November 2006, Inergy acquired the propane assets of Mideastern Oil Company, Inc. Additionally, in December 2006, Inergy acquired the assets of the Jacksonville, Florida location of Sun Belt Energy of Florida, LLC and Stevens Gas Service, Inc. In February 2007, Inergy completed the acquisition of the 24-mile lateral pipeline (“South Lateral Pipeline”) connecting its Stagecoach natural gas storage facility to Tennessee Gas Pipeline Company’s Line 300. In May 2007, Inergy acquired the propane assets of The F&S Oil Company located in Waterbury, Connecticut. In June 2007, Inergy acquired the propane assets of two retail locations in Alabama. The aggregate purchase price of these nine acquisitions, net of cash acquired, was approximately $87.0 million. The Company has allocated $32.5 million to goodwill and $16.2 million to intangible assets, consisting primarily of customer accounts and non-compete agreements, as a result of the above acquisitions. The purchase price allocation for these acquisitions has been prepared on a preliminary basis pending final asset valuation and asset rationalization, and changes are expected when additional information becomes available. Changes to final asset valuation of prior fiscal year acquisitions have been included in the Company’s consolidated financial statements but are not material.

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

The operating results for these acquisitions are included in the consolidated results of operations from the dates of acquisition through June 30, 2007.

In August 2005, Inergy issued 769,941 special units (the “Special Units”), representing a new class of equity securities in Inergy that were not entitled to cash distributions but would convert into common units representing limited partnership interests in Inergy. On April 25, 2007, the Special Units converted into 919,349 common units as a result of the commercial operation of the Phase II expansion of the Stagecoach Natural Gas Storage Facility. This beneficial conversion feature present in these Special Units was valued at $10.3 million and has been recognized as a non-cash allocation of (income) to the holder of the converted units for the purpose of calculating earnings per limited partner unit.

In February 2007, Inergy issued 3,450,000 common units in a public offering, which included 450,000 common units issued as a result of the underwriters exercising their over-allotment provision. The issuance of these common units resulted in net proceeds of approximately $104.5 million, after deducting underwriters’ discounts, commissions and other offering expenses. The net proceeds from this offering were used to repay indebtedness under Inergy’s Credit Agreement.

A summary of Inergy’s limited partner quarterly distributions for the nine months ended June 30, 2007 and 2006 is presented below:

On July 25, 2007, Inergy declared a distribution of $0.585 per limited partner unit to be paid on August 14, 2007 to unitholders of record on August 7, 2007 for a total distribution of $37.2 million with respect to its third fiscal quarter of 2007. On August 14, 2006, a quarterly distribution of $0.545 per limited partner unit was paid to unitholders of record on August 7, 2006 with respect to the third fiscal quarter of 2006, for a total distribution of $29.9 million.

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.

During the 2006 fiscal year, the Company granted 58,756 restricted units. During the current fiscal year, the Company has granted an additional 44,020 restricted units. The majority of the restricted units are 100% vested on the fifth anniversary of the grant date, subject to the provisions as outlined in the restricted unit award agreement. Some of these units are subject to the achievement of certain specified performance objectives and failure to meet the performance objectives will result in forfeiture and cancellation of the restricted units. The Company recognizes expense on these units each quarter by multiplying the closing price of the Company’s common units on the date of grant by the number of units granted, and expensing that amount over the vesting period.

The compensation expense recorded by the Company related to these restricted unit awards was insignificant for the three and nine months ended June 30, 2007 and 2006.

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 the vesting provisions 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 nine months ended June 30, 2007 is as follows:

The weighted-average remaining contract life for outstanding options at June 30, 2007 was approximately six years. 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 units 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 unit options.

The aggregate intrinsic value of outstanding options at June 30, 2007 was $6.9 million. The aggregate intrinsic value of unit options exercised during the nine months ended June 30, 2007 was $5.2 million. There were no options exercised during the nine months ended June 30, 2006. Aggregate intrinsic value represents the positive difference between the Company’s closing unit price on the last trading day of the fiscal period, which was $36.20 on June 29, 2007, and the exercise price multiplied by the number of options outstanding.

As of June 30, 2007, there was $4.6 million of total unrecognized compensation cost related to unvested unit-based compensation awards granted to employees under the restricted unit and unit option plans, including approximately $1.8 million related to Holdings unvested unit-based compensation awards. That cost is expected to be recognized over a five-year period.

Inergy periodically enters into agreements with suppliers to purchase fixed quantities of propane, distillates, natural gas and liquids at fixed prices. At June 30, 2007, the total of these firm purchase commitments was approximately $183.6 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.

Inergy has entered into certain purchase commitments in connection with the identified growth projects related to the Stagecoach and West Coast NGL midstream assets. At June 30, 2007, the total of these firm purchase commitments was approximately $37.8 million.

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 June 30, 2007 and September 30, 2006, Inergy’s self-insurance reserves were $14.2 million and $11.2 million, respectively.

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 three and nine months ended June 30, 2007, excluding the Bath Storage Facility and the South Lateral Pipeline, are included in the propane segment. The results of operations for the Bath Storage Facility and the South Lateral Pipeline are included in the midstream segment.

The identifiable assets associated with each reportable segment include accounts receivable and inventories. Goodwill is also presented for each segment. The net asset/liability from price risk management, as reported in the accompanying consolidated balance sheets, is primarily related to the propane segment.

Revenues, gross profit, identifiable assets and goodwill for each of Inergy’s reportable segments are presented below (in millions):

“Management’s Discussion and Analysis of Financial Condition and Results of Operations” should be read in conjunction with the accompanying consolidated financial statements and “Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the Annual Report on Form 10-K of Inergy, L.P. for the fiscal year ended September 30, 2006.

The statements in this Quarterly Report on Form 10-Q that are not historical facts, including most importantly, those statements preceded by, or that include the words “may”, “believes”, “expects”, “anticipates” or the negation thereof, or similar expressions, constitute “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. Such forward-looking statements include, but are not limited to, statements that: (i) we believe our wholesale supply, marketing and distribution business complements our retail distribution business, (ii) we expect recovery of goodwill through future cash flows associated with acquisitions, and (iii) we believe that anticipated cash from operations and borrowings under our credit facility will be sufficient to meet our liquidity needs for the foreseeable future. Such forward-looking statements involve risks, uncertainties and other factors which may cause the actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements. Such factors include, but are not limited to, the following: weather in our area of operations; market price of propane; availability of financing; changes in, or failure to comply with, government regulations; the costs, uncertainties and other effects of legal and administrative proceedings and other risks and uncertainties detailed in our Securities and Exchange Commission filings. For those statements, we claim the protections of the safe harbor for forward-looking statements contained in the Reform Act. We will not undertake and specifically decline any obligation to publicly release the result of any revisions to any forward-looking statements to reflect events or circumstances after the date of such statements or to reflect events or circumstances after anticipated or unanticipated events.

We are a growing retail and wholesale propane supply, marketing and distribution business. We also own and operate a growing midstream operation, including a high performance, multicycle natural gas storage facility (“Stagecoach”) 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 June 30, 2007, we have acquired 68 companies, 64 propane companies and 4 midstream businesses, for an aggregate purchase price of approximately $1.5 billion, including working capital, assumed liabilities and acquisition costs. We further intend to pursue our growth objectives through, among other things, future acquisitions, maintaining a high percentage of retail sales to residential customers, operating in attractive markets and focusing our operations under established, and locally recognized trade names.

During October 2006, we closed the following three asset acquisitions: a natural gas liquids storage facility located near Bath, New York (the “Bath Storage Facility”), Columbus Butane Company, Inc., and Hometown Propane, Inc. In November 2006, we acquired the propane assets of Mideastern Oil Company, Inc. Additionally, in December 2006, we acquired the assets of the Jacksonville, Florida location of Sun Belt Energy of Florida, LLC and Stevens Gas Service, Inc. In February 2007, we completed the acquisition of the 24-mile lateral pipeline (“South Lateral Pipeline”) connecting our Stagecoach natural gas storage facility to Tennessee Gas Pipeline Company’s Line 300. In May 2007, we acquired the propane assets of The F&S Oil Company located in Waterbury, Connecticut. In June 2007, we acquired the propane assets of two retail locations in Alabama. The aggregate purchase price of these nine acquisitions, net of cash acquired, was approximately $87.0 million. The purchase price allocation for these acquisitions has been prepared on a preliminary basis pending final asset valuation and asset rationalization, and changes are expected when additional information becomes available. Changes to final asset valuation of prior fiscal year acquisitions have been included in our consolidated financial statements but are not material.

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.

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).

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

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:

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.

Three Months Ended June 30, 2007 Compared to Three Months Ended June 30, 2006

The following table summarizes the consolidated income statement components for the three months ended June 30, 2007 and 2006, respectively (in millions):

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

Volume. During the three months ended June 30, 2007, we sold 50.0 million retail gallons of propane, an increase of 3.4 million gallons or 7.3% from the 46.6 million retail gallons sold during the same three-month period in 2006. The increase was principally due to acquisition-related volume, which resulted in an increase of 3.0 million gallons in the quarter ended June 30, 2007, as well as colder weather in the 2007 period.

Wholesale gallons delivered during the three months ended June 30, 2007 were 58.6 million gallons compared to 53.8 million gallons during the same three-month period in 2006. The increase of 4.8 million gallons was primarily attributable to the colder weather experienced in the 2007 period.

The total natural gas liquid gallons sold by our midstream operations increased 4.2 million gallons, or 27.5%, to 19.5 million gallons during the three months ended June 30, 2007 from 15.3 million gallons during the same three-month period in 2006. This increase was primarily attributable to a new product sales agreement. Stagecoach had 17.45 and 13.25 bcf of working gas storage capacity during each of the three months ended June 30, 2007 and 2006, respectively.

Revenues. Revenues for the three months ended June 30, 2007 were $246.8 million, an increase of $31.2 million, or 14.5%, from $215.6 million during the same three-month period in 2006.

Revenues from retail propane sales were $102.5 million for the three months ended June 30, 2007, an increase of $11.3 million, or 12.4%, from $91.2 million during the same three-month period in 2006. These higher revenues were primarily the result of increased sales of approximately $4.9 million due to higher selling prices of propane, $5.5 million in acquisition-related sales, and the higher retail volume sales of $0.9 million at our existing locations.

Revenues from wholesale propane sales for the three months ended June 30, 2007 were $65.8 million compared to $52.5 million during the same three-month period in 2006. This $13.3 million, or 25.3%, increase was primarily due to higher selling prices, which contributed approximately $8.6 million of the increase, and the higher sales volume, which contributed the remaining $4.7 million increase.

Revenues from other retail sales, primarily service, appliance, transportation, and distillates, were $35.1 million for the three months ended June 30, 2007, an increase of $1.9 million or 5.7% from $33.2 million during the same three-month period in 2006. Approximately $1.1 million of this increase was due to higher transportation sales and higher volume sales of distillates, with the remaining $0.8 million due to acquisition-related sales.

Revenues from storage, fractionation and other midstream activities were $43.4 million for the three months ended June 30, 2007, an increase of $4.7 million, or 12.1%, from $38.7 million during the same three-month period in 2006. Of the $4.7 million increase, $3.4 million represents an increase due to the acquisition of the Bath Storage Facility and the initial Stagecoach Phase II expansion placed into service in April 2007. The remaining $1.3 million is attributable to increases in the recurring Stagecoach operations and the West Coast operations.

Cost of Product Sold. Retail propane cost of product sold for the three months ended June 30, 2007 was $58.7 million compared to $50.9 million during the same three-month period in 2006. This $7.8 million, or 15.3%, increase resulted from an approximate 9% higher average per gallon cost of propane, which contributed $4.9 million of the increase, a $3.3 million increase due to acquisition-related sales and a $0.5 million increase resulting from higher retail volume sales at our existing locations. These increases to cost of product sold were partially offset by an approximate $0.9 million decrease due to changes in non-cash charges from derivative contracts associated with retail propane fixed price sales contracts. The Company recorded a $0.5 million non-cash gain during the three months ended June 30, 2007 as compared to a non-cash charge of $0.4 million recorded in the same three-month period in 2006.

Wholesale propane cost of product sold for the three months ended June 30, 2007 was $64.0 million, an increase of $13.6 million or 27.0%, from $50.4 million during the same three-month period in 2006. Approximately $9.1 million of this increase resulted from the higher average cost of propane, with the remaining $4.5 million resulting from higher volumes sold by our wholesale propane operations.

Other retail cost of product sold was $20.1 million for the three months ended June 30, 2007 compared to $20.4 million during the same three-month period in 2006. This $0.3 million decline resulted from a $0.4 decrease due primarily to lower appliance sales partially offset by a $0.1 million increase in acquisition-related sales.

Fractionation, storage, and other midstream cost of product sold was $28.2 million for the three months ended June 30, 2007 compared to $28.5 million during the same three-month period in 2006. This $0.3 million decline was primarily related to lower transportation expense associated with the acquisition of the Stagecoach Lateral, partially offset by increased cost of sales in the West Coast operations and Stagecoach Phase II placed in service in April 2007.

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, including fuel costs, repair and maintenance and lease expense. These costs approximated $15.8 million and $14.8 million for the three months ended June 30, 2007 and 2006, respectively. In addition, depreciation expense associated with the delivery vehicles is reported within depreciation and amortization expense and amounted to $3.7 million and $3.8 million for the three months ended June 30, 2007 and 2006, respectively. Since we include these costs in our operating and administrative expenses rather than in cost of product sold, our results may not be comparable to other entities in our lines of business if they include these costs in cost of product sold.

Gross Profit. Retail propane gross profit was $43.8 million for the three months ended June 30, 2007 compared to $40.3 million in the same three-month period in 2006. This $3.5 million, or 8.7%, increase was attributable to several factors, including $0.4 million of higher volume sales from existing locations and $2.2 million in acquisition-related sales. Also contributing to higher gross profit was the $0.9 million decrease in cost of product sold relating to the change in non-cash charges from derivative contracts associated with retail propane fixed price sales contracts.

Wholesale propane gross profit decreased $0.3 million, or 14.3%, to $1.8 million for the three months ended June 30, 2007 compared to $2.1 million in the same three-month period in 2006. This decrease was attributable to a $0.5 million decline due to lower margins, partially offset by an increase of $0.2 million due to higher volume sales.

Other retail gross profit increased $2.2 million, or 17.2%, to $15.0 million for the three months ended June 30, 2007 compared to $12.8 million in the same three-month period in 2006. The higher gross profit was due primarily to a $1.5 million increase resulting from higher transportation sales and distillate volume sales and a $0.7 million increase in acquisition-related sales.

Fractionation, storage, and other midstream gross profit was $15.2 million for the three months ended June 30, 2007 compared to $10.2 million in the same three-month period in 2006. Of this $5.0 million, or 49% increase, $3.9 million represents an increase due to the acquisition of the Bath Storage Facility, the initial Stagecoach Phase II expansion placed into service in April 2007, and the acquisition of the Stagecoach Lateral. The remaining $1.1 million is attributable to increases in the recurring Stagecoach operations and the West Coast operations.

Operating and Administrative Expenses. Operating and administrative expenses were $63.2 million for the three months ended June 30, 2007 compared to $62.6 million during the same three-month period in 2006. This $0.6 million increase resulted from acquisitions, which contributed a $2.3 million increase, and slightly higher costs from existing businesses of approximately $0.6 million. Additionally in the 2006 period, we accrued a one-time charge of $2.3 million for long-term incentive compensation related to the conversion of subordinated units to common units.

Depreciation and Amortization. Depreciation and amortization increased to $21.4 million for the three months ended June 30, 2007 from $20.6 million during the same three-month period in 2006, with the change primarily a result of acquisitions and the expansion of our midstream segment.

Interest Expense. Interest expense decreased to $12.0 million for the three months ended June 30, 2007 compared to $13.6 million during the same three-month period in 2006. This $1.6 million decline resulted from lower average debt outstanding and more capitalized interest during the three-month period ended June 30, 2007 partially offset by higher overall interest rates. During the three months ended June 30, 2007 and 2006, we capitalized $0.6 million and $0.2 million, respectively, of interest related to certain capital improvement projects at our West Coast NGL and Stagecoach facilities as further described below in “Liquidity and Sources of Capital – Capital Resource Activities.”

Net Income (loss). Net loss was $(20.6) million for the three months ended June 30, 2007 compared to the net loss of $(32.4) million for the same three-month period in 2006. The $11.8 million improvement was primarily attributable to the higher gross profit in the 2007 period exceeding the increase in operating expenses.

EBITDA and Adjusted EBITDA. The following table summarizes EBITDA and Adjusted EBITDA for the three months ended June 30, 2007 and 2006, respectively (in millions):

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 three months ended June 30, 2007 and 2006, EBITDA was $13.0 million and $2.0 million, respectively. This $11.0 million improvement in EBITDA was primarily attributable to higher gross profit in 2007. As indicated in the table, Adjusted EBITDA represents EBITDA excluding the gain or loss on derivative contracts associated with retail fixed price propane sales, the gain or loss on the disposal of assets and long-term incentive and equity compensation expenses (including subordinated unit conversion bonuses). Adjusted EBITDA was $13.4 million for three months ended June 30, 2007 compared to $6.5 million in the same three-month period in 2006. EBITDA and Adjusted EBITDA should not be considered an alternative to net income, income before income taxes, cash flows from operating activities, or any other measure of financial performance calculated in accordance with generally accepted accounting principles as those items are used to measure operating performance, liquidity or the ability to service debt obligations. We believe that EBITDA and Adjusted EBITDA provide additional information for evaluating our ability to make the minimum quarterly distribution and are presented solely as supplemental measures. EBITDA and Adjusted EBITDA, as we define them, may not be comparable to EBITDA and Adjusted EBITDA or similarly titled measures used by other corporations or partnerships.

The following table summarizes the consolidated income statement components for the nine months ended June 30, 2007 and 2006, respectively (in millions):

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

Volume. During the nine months ended June 30, 2007, we sold 313.7 million retail gallons of propane as compared to 310.5 million retail gallons sold during the same nine-month period in 2006. The 3.2 million gallon increase was principally due to 17.5 million gallons of acquisition-related volume and higher volumes due to the colder weather in the 2007 period (approximately 4% colder in the 2007 period as compared to the 2006 period). These increases were partially offset by a decline of 14.3 million gallons due primarily to the sale of certain branches during fiscal 2006 and expected volume losses from recent acquisitions.

Wholesale gallons delivered during the nine months ended June 30, 2007 were 304.9 million gallons compared to 296.0 million gallons during the same nine-month period in 2006. The increase of 8.9 million gallons was primarily attributable to increased sales to new and existing customers and colder weather in the 2007 period. Although the weather was only 4% colder in the 2007 period compared to the 2006 period, we experienced erratic weather during the months of February and April of 2007 (approximately 20% and 40% colder, respectively) compared to the same months in 2006.

The total natural gas liquid gallons sold by our midstream operations increased 0.2 million gallons to 46.3 million gallons during the nine months ended June 30, 2007 from 46.1 million gallons during the same nine-month period in 2006. During the nine months ended June 30, 2007, Stagecoach had 13.25 bcf of working gas storage capacity for the first six months and 17.45 working gas storage capacity for the last three months, compared to 13.25 bcf working gas storage capacity throughout the nine months ended June 30, 2006. The working gas storage capacity was 100% contracted during each of the periods noted above.

Revenues. Revenues for the nine months ended June 30, 2007 were $1,207.2 million, an increase of $64.5 million, or 5.6%, from $1,142.7 million during the same nine-month period in 2006.

Revenues from retail propane sales were $634.6 million for the nine months ended June 30, 2007, an increase of $31.5 million, or 5.2%, from $603.1 million during the same nine-month period in 2006. These higher revenues were primarily the result of $34.8 million in acquisition-related sales and increased sales of $24.4 million due to higher selling prices of propane. Partially offsetting these increases to revenues was a decrease of approximately $27.7 million due to lower retail volume sales at our existing locations.

Revenues from wholesale propane sales for the nine months ended June 30, 2007 were $321.6 million compared to $296.9 million during the same nine-month period in 2006. This $24.7 million, or 8.3%, increase was primarily due to higher selling prices, which contributed approximately $15.7 million of the increase, and higher sales volume, which contributed the remaining $9.0 million.

Revenues from other retail sales, primarily service, appliance, transportation, and distillates, were $138.0 million for the nine months ended June 30, 2007, an increase of $4.1 million or 3.1% from $133.9 million during the same nine-month period in 2006. Approximately $3.4 million of this increase was due to acquisition-related sales with the remaining $0.7 million primarily attributable to higher transportation sales, rental sales and distillate volume sales.

Revenues from storage, fractionation and other midstream activities were $113.0 million for the nine months ended June 30, 2007, an increase of $4.2 million, or 3.9%, from $108.8 million during the same nine-month period in 2006. Of this $4.2 million increase, $9.6 million represents an increase due to the acquisition of the Bath Storage Facility, the initial Stagecoach Phase II expansion placed into service in April 2007, and increased contractual rates on the Stagecoach Storage Facility. Additionally, increased revenues of $2.6 million is attributable to increases in the West Coast operations. Offsetting these increases was an $8.0 million decline in revenues due to changes in the mix of natural gas liquid products sold.

Cost of Product Sold. Retail propane cost of product sold for the nine months ended June 30, 2007 was $357.8 million compared to $361.8 million during the same nine-month period in 2006. This $4.0 million, or 1.1%, decrease resulted from an approximate $20.1 million decrease due to changes in non-cash charges from derivative contracts associated with retail propane fixed price sales contracts. The Company recorded a $0.5 million non-cash gain during the nine months ended June 30, 2007 as compared to a non-cash charge of $19.6 million recorded in the same nine-month period in 2006. Lower retail volume sales at our existing locations also contributed $15.7 million of the decrease. Partially offsetting these decreases to cost of product sold was $20.4 million in acquisition-related sales together with an approximate 4% higher average per gallon cost of propane, which contributed to an increase of $11.4 million.

Wholesale propane cost of product sold for the nine months ended June 30, 2007 was $308.9 million, an increase of $19.8 million or 6.8%, from $289.1 million during the same nine-month period in 2006. Approximately $11.0 million of this increase was attributable to the higher average cost of propane with the remaining $8.8 million increase related to higher volumes sold by our wholesale propane operations.

Other retail cost of product sold was $84.0 million for the nine months ended June 30, 2007, a decrease of $0.7 million or 0.8%, from $84.7 million during the same nine-month period in 2006. This decline was primarily due to lower appliance sales of approximately $1.5 million partially offset by an $0.8 million increase due to acquisition-related sales.

Fractionation, storage, and other midstream cost of product sold was $68.2 million for the nine months ended June 30, 2007, a decrease of $9.8 million, or 12.6%, from $78.0 million during the same nine-month period in 2006. Of this $9.8 million decrease, $9.1 million was related to lower cost of product sold associated with the change in mix of natural gas liquid products sold. Additionally, a $1.4 million decrease was attributable to lower transportation expense associated with the acquisition of the Stagecoach Lateral. This was offset by a $0.7 million increase primarily from increased cost of sales in the West Coast operations.

Our retail cost of product sold consists primarily of tangible products sold including all propane, distillates and other natural gas liquids sold and all propane-related appliances sold. Other costs incurred in conjunction with the distribution of these products are included in operating and administrative expenses and consist primarily of wages to delivery personnel and delivery vehicle costs, including fuel costs, repair and maintenance and lease expense. These costs approximated $51.2 million and $48.7 million for the nine months ended June 30, 2007 and 2006, respectively. In addition, depreciation expense associated with the delivery vehicles is reported within depreciation and amortization expense and amounted to $11.4 million and $11.3 million for the nine months ended June 30, 2007 and 2006, respectively. Since we include these costs in our operating and administrative expenses rather than in cost of product sold, our results may not be comparable to other entities in our lines of business if they include these costs in cost of product sold.

Gross Profit. Retail propane gross profit was $276.8 million for the nine months ended June 30, 2007 compared to $241.3 million in the same nine-month period in 2006. This $35.5 million, or 14.7%, increase was attributable to several factors, including $14.4 million in acquisition-related sales and $13.0 million related to a higher cash margin per gallon. Also contributing to higher gross profit was the $20.1 million decrease in cost of product sold relating to the change in non-cash charges from derivative contracts associated with retail propane fixed price sales contracts. Partially offsetting these increases was a decrease of approximately $12.0 million related to lower volume sales at our existing locations.

Wholesale propane gross profit increased $4.9 million, or 62.8%, to $12.7 million for the nine months ended June 30, 2007 compared to $7.8 million in the same nine-month period in 2006. Approximately $4.7 million of this increase was attributable to higher margins with the remaining $0.2 million due to higher volume sales.

Other retail gross profit increased $4.8 million, or 9.8%, to $54.0 million for the nine months ended June 30, 2007 compared to $49.2 million in the same nine-month period in 2006. The higher gross profit was due to approximately $2.6 million in acquisition-related sales together with a $2.2 million increase primarily attributable to higher transportation sales, rental sales and distillate volume sales.

Fractionation, storage, and other midstream gross profit was $44.8 million for the nine months ended June 30, 2007 compared to $30.8 million in the same nine-month period in 2006. Of this $14.0 million, or 45% increase, $10.9 million represents an increase due to increased contractual rates on the Stagecoach Storage Facility, the acquisition of the Bath Storage Facility, the acquisition of the Stagecoach Lateral, and the initial Stagecoach Phase II expansion placed into service in April 2007. Additionally, $3.1 million relates to increases in transportation and natural gas liquids gross profit at the West Coast operations.

Operating and Administrative Expenses. Operating and administrative expenses were $194.7 million for the nine months ended June 30, 2007 compared to $188.7 million during the same nine-month period in 2006. This $6.0 million increase in operating expenses was primarily the result of higher expenses of approximately $9.3 million arising from acquisitions, partially offset by lower expenses of approximately $1.0 million due to integration efficiencies and lower variable expenses as a result of lesser volumes sold at existing locations. Also partially offsetting the increase was the impact of the one-time long-term incentive compensation charge of $2.3 million accrued during the three months ended June 30, 2006 as discussed above.

Depreciation and Amortization. Depreciation and amortization increased to $60.9 million for the nine months ended June 30, 2007 from $58.7 million during the same nine-month period in 2006, with the change primarily a result of acquisitions and the expansion of our midstream segment.

Interest Expense. Interest expense decreased to $39.1 million for the nine months ended June 30, 2007 compared to $41.1 million during the same nine-month period in 2006. This $2.0 million decline resulted from lower average debt outstanding and more capitalized interest during the nine-month period ended June 30, 2007 partially offset by higher overall interest rates. During the nine months ended June 30, 2007 and 2006, we capitalized $2.0 million and $0.2 million, respectively, of interest related to certain capital improvement projects at our West Coast NGL and Stagecoach facilities as further described below in “Liquidity and Sources of Capital – Capital Resource Activities.”

Net Income. Net income was $95.3 million for the nine months ended June 30, 2007 compared to net income of $40.2 million for the same nine-month period in 2006. The $55.1 million increase in net income was primarily attributable to the higher gross profit in the 2007 partially offset by the increase in operating expenses.

EBITDA and Adjusted EBITDA. The following table summarizes EBITDA and Adjusted EBITDA for the nine months ended June 30, 2007 and 2006, respectively (in millions):

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 nine months ended June 30, 2007 and 2006, EBITDA was $195.8 million and $140.8 million, respectively. This $55.0 million improvement in EBITDA was primarily attributable to higher gross profit in 2007. As indicated in the table, Adjusted EBITDA represents EBITDA excluding the gain or loss on derivative contracts associated with retail fixed price propane sales, the gain or loss on the disposal of assets and long-term

incentive and equity compensation expenses (including subordinated unit conversion bonuses). Adjusted EBITDA was $197.4 million for nine months ended June 30, 2007 compared to $165.3 million in the same nine-month period in 2006. EBITDA and Adjusted EBITDA should not be considered an alternative to net income, income before income taxes, cash flows from operating activities, or any other measure of financial performance calculated in accordance with generally accepted accounting principles as those items are used to measure operating performance, liquidity or the ability to service debt obligations. We believe that EBITDA and Adjusted EBITDA provide additional information for evaluating our ability to make the minimum quarterly distribution and are presented solely as supplemental measures. EBITDA and Adjusted EBITDA, as we define them, may not be comparable to EBITDA and Adjusted EBITDA or similarly titled measures used by other corporations or partnerships.

The retail market for propane is seasonal because it is used primarily for heating in residential and commercial buildings. Approximately three-quarters 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 year.

Recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases,” may be contributing to warming of the Earth’s atmosphere. Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of fuels such as propane and natural gas, are examples of greenhouse gases. In response to such studies, the U.S. Congress is actively considering legislation to reduce emissions of greenhouse gases. In addition, at least nine states in the Northeast and five states in the West have declined to wait on Congress to develop and implement climate control legislation and have already taken legal measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Also, as a result of the U.S. Supreme Court’s decision on April 2, 2007 in Massachusetts, et al. v. EPA, the U.S. Environmental Protection Agency or “EPA” may be required to regulate greenhouse gas emissions from mobile sources (e.g., cars and trucks) even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. The Court’s holding in Massachusetts that greenhouse gases fall under the federal Clean Air Act’s definition of “air pollutant” may also result in future regulation of greenhouse gas emissions from stationary sources under certain Clean Air Act programs. Passage of climate control legislation or other regulatory initiatives by Congress or various states of the U.S. or the adoption of regulations by the EPA or analogous state agencies that restrict emissions of greenhouse gases in areas in which we conduct business could have an adverse affect on our operations and demand for our services.

On December 21, 2006, Central New York Oil and Gas Company LLC (“CNYOG”), the regulated subsidiary and owner of the Stagecoach natural gas storage facility, was granted certificate authority by the Federal Energy Regulatory Commission (“FERC”) to own and operate the Stagecoach Lateral, a 23.7 mile, 30-inch diameter pipeline connecting CNYOG’s Stagecoach natural gas storage field with Tennessee Gas Pipeline Company’s mainline system (300-Line) in Bradford County, Pennsylvania. FERC authorized Tennessee, the former owner of the pipeline, to abandon the lateral by sale to CNYOG, and the acquisition was completed in February 2007. FERC has permitted CNYOG to incorporate the Stagecoach Lateral into its storage operations and to charge market-based storage rates under previously existing storage rate schedules for storage injections and withdrawals made through the newly acquired Stagecoach Lateral. In authorizing acquisition of the Stagecoach Lateral, FERC affirmed CNYOG’s continuing general authority, after the acquisition of the Stagecoach Lateral, to charge and collect market-based rates. However, FERC may review that market-based rate authorization in the event CNYOG expands the facility’s storage capacity, acquires transportation facilities or additional storage capacity, if CNYOG or one of its affiliates provide storage or transportation services in the same market area or acquire an interest in another storage field that can link CNYOG facilities to the market area or if CNYOG or one of its affiliates acquire an interest in or is acquired by an interstate pipeline.

FERC’s Order No. 2004, which sets forth standards of conduct applicable to public utilities and interstate transporters of gas, including interstate storage providers, was vacated and remanded by the United States Court of Appeals for the District of Columbia Circuit on November 17, 2006. Less restrictive interim rules were put in place by FERC on January 9, 2007. FERC has requested comment on the interim rules, and no final rule on remand has yet been issued by FERC. By FERC order, CNYOG was found to be exempt from the Order No. 2004 standards of conduct. The interim rules continue to exempt most natural gas storage providers authorized to charge market-based rates, and there is no reason to believe that CNYOG would not continue to be so exempt from the applicable standards of conduct established under the interim rules.

On June 19, 2006, FERC revised its regulations governing criteria for obtaining market-based rates for interstate natural gas storage services. Order No. 678 adopts new regulations which are intended to make it easier for storage providers to obtain authority to charge market-based rates, and which are intended to facilitate the development of new natural gas storage capacity. Although CNYOG already holds market-based rate authority for storage services performed at its Stagecoach natural gas storage facility, these new rules might facilitate the efforts of other prospective storage providers, including potential competitors with the Stagecoach storage facility, to obtain market-based rate authority.

The Internal Revenue Service (“IRS”) mailed a “Notice of Beginning of Administrative Proceeding” to the Company dated June 26, 2007 (“NBAP”) stating that the IRS is commencing an audit of the Company’s 2004 partnership tax return. A copy of the NBAP is available on our website at www.inergypropane.com. The Company understands this to be a routine audit of various items of partnership income, gain, deductions, losses and credits. The audit is in its preliminary stages so it is not known whether the IRS will propose any adjustments to the Company’s tax returns, whether such adjustments would be material, or how such adjustments would affect unitholders.

The Company, through its Tax Matters Partner, will cooperate with the IRS examiners auditing this return. Unitholders should consult their tax advisers if they have any questions.

In February 2007, we issued 3,450,000 common units in a public offering, which included 450,000 common units issued as a result of the underwriters exercising their over-allotment provision. The issuance of these common units resulted in net proceeds of approximately $104.5 million, after deducting underwriters’ discounts, commissions and other offering expenses. The net proceeds from this offering were used to repay indebtedness under Inergy’s Credit Agreement.

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 $261 million to complete. Through June 30, 2007, we have invested approximately $53.8 million toward completion of these projects. In April 2007, a portion of the Phase II expansion of the Stagecoach natural gas storage was placed in commercial operation, which increased our working gas capacity to 17.45 bcf from 13.25 bcf. The expansion project is expected to be in full commercial operation in September 2007, which will increase our total working gas capacity to 26.25 bcf. The expanded facility is 100% contracted with long term firm storage contracts that commence service upon full commercial operation. Stagecoach is also expected to construct a pipeline to interconnect with the proposed Millennium Pipeline, which will enhance and further diversify our supply sources and provide interruptible wheeling services to the shipper community. The West Coast project consists of the construction of a butane isomerization unit and related ancillary facilities, as well as the expansion of butane storage capacity. The isomerization unit is projected to have a capacity of 10,000 barrels per day and provide isobutane supplies to refiners or wholesale distributors for gasoline blending. This project is subject to regulatory approval by state and county agencies and is expected to be in service by July 2008.

Net operating cash inflows were $143.4 million and $111.6 million for the nine-month periods ending June 30, 2007 and 2006, respectively. The $31.8 million increase in operating cash flows was primarily attributable to higher operating income and net changes in working capital balances.

Net investing cash outflows were $132.1 million and $188.6 million for the nine-month periods ending June 30, 2007 and 2006, respectively. Net cash outflows were primarily impacted by an $89.3 million decrease in cash outlays related to acquisitions and a $29.3 million increase in capital expenditures.

Net financing cash inflows (outflows) were $(16.5) million and $113.6 million for the nine-month periods ending June 30, 2007 and 2006, respectively. Net cash outflows were primarily impacted by a $93.4 million decrease in proceeds related to the issuance of long-term debt, net of payments on long-term debt, a $19.9 million decrease in proceeds from the issuance of common units and unit option exercises and a $21.8 million increase in distributions paid.

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

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

We maintain borrowing capacity under a credit facility (“Credit Agreement”), which consists of a $75 million revolving working capital facility (“Working Capital Facility”) and a $350 million revolving acquisition facility (“Acquisition Facility”). The Credit Agreement accrues interest at either prime rate or LIBOR plus applicable spreads, resulting in an interest rate of 8.25% at June 30, 2007. At June 30, 2007, borrowings outstanding under the Credit Agreement were $1.3 million, all drawn under the Working Capital Facility. On October 1, 2006, Inergy amended the Credit Agreement with existing lenders primarily to increase the effective amount of working capital borrowings available through the utilization of the Acquisition Facility from $75 million to $125 million. Other terms, conditions, and covenants remained materially unchanged. The Credit Agreement is guaranteed by each of Inergy’s domestic subsidiaries.

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

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

We have long-term debt and a revolving line of credit subject to the risk of loss associated with movements in interest rates. At June 30, 2007, we had floating rate obligations totaling approximately $126.3 million including amounts borrowed under our Credit Agreement and interest rate swaps, which convert a portion of our fixed rate senior unsecured notes due 2014 to floating rate debt. 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 June 2007 levels, our interest expense would change by a total of approximately $1.3 million per year.

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

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

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

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

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

The fair value of the derivatives and inventory exchange contracts related to price risk management activities as of June 30, 2007 and September 30, 2006 was assets of $27.2 million and $46.2 million, respectively, and liabilities of $26.5 million and $49.0 million, respectively. All intercompany transactions have been appropriately eliminated.

The following table summarizes the change in the unrealized fair value of energy derivative contracts related to risk management activities for the nine months ended June 30, 2007 and 2006 where settlement has not yet occurred (in millions):

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 fair value as of June 30, 2007, all contracts had a maturity of eighteen months or less.

A theoretical change of 10% in the underlying commodity value would result in a negligible change in the market value of the contracts as there were approximately 0.4 million gallons of net unbalanced positions at June 30, 2007.

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

Part I, Item 1. Financial Statements, Note 7 to the Consolidated Financial Statements, of this Form 10-Q is hereby incorporated herein by reference.

There have been no material changes to the risk factors disclosed in “Item 1A, Risk Factors” in the Company’s Annual Report on Form 10-K for the fiscal year ended September 30, 2006 and in the Company’s Form 10-Q for the quarter ended March 31, 2007.

Reference is made to Part 1, Item 2. Regulatory Matters, with regards to the commencement of an audit of the Company’s 2004 partnership tax return.


3.1		Certificate of Limited Partnership of Inergy, L.P. (incorporated herein by reference to Exhibit 3.1 to Inergy, L.P.’s Registration Statement on Form S-1 (Registration No. 333-56976) filed on March 14, 2001).

3.1A		Certificate of Correction of Certificate of Limited Partnership of Inergy, L.P. (incorporated herein by reference to Exhibit 3.1 to Inergy, L.P.’s Form 10-Q (Registration No. 000-32543) filed on May 12, 2003).

3.2		Second Amended and Restated Agreement of Limited Partnership of Inergy, L.P. (incorporated herein by reference to Exhibit 3.1 to Inergy, L.P.’s Form 10-Q (Registration No. 000-32453) filed on February 13, 2004).

3.2A		Amendment No. 1 to Second Amended and Restated Agreement of Limited Partnership of Inergy L.P. (incorporated herein by reference to Exhibit 3.1 to Inergy, L.P.’s Form 10-Q (Registration No. 000-32453) filed on May 14, 2004).

3.2B		Amendment No. 2 to Second Amended and Restated Agreement of Limited Partnership of Inergy, L.P. (incorporated herein by reference to Exhibit 3.1 to Inergy, L.P.’s Form 8-K filed on January 24, 2005).

3.2C		Amendment No. 3 to Second Amended and Restated Agreement of Limited Partnership of Inergy, L.P. (incorporated herein by reference to Exhibit 3.1 to Inergy, L.P.’s Form 8-K/A filed on August 17, 2005).


3.3		Certificate of Formation as relating to Inergy Propane, LLC, as amended (incorporated herein by reference to Exhibit 3.3 to Inergy, L.P.’s Registration Statement on Form S-1/A (Registration No. 333-56976) filed on May 7, 2001).

3.4		Third Amended and Restated Limited Liability Company Agreement of Inergy Propane, LLC, dated as of July 31, 2001 (incorporated herein by reference to Exhibit 3.4 to Inergy, L.P.’s Registration Statement on Form S-1 (Registration No. 333-89010 filed on May 24, 2002).

3.5		Certificate of Formation of Inergy GP, LLC (incorporated herein by reference to Exhibit 3.5 to Inergy, L.P.’s Registration Statement on Form S-1/A (Registration No. 333-56976) filed on May 7, 2001).

3.6		Limited Liability Company Agreement of Inergy GP, LLC (incorporated herein by reference to Exhibit 3.6 to Inergy, L.P.’s Registration Statement on Form S-1/A (Registration No. 333-56976) filed on May 7, 2001).

3.7		Certificate of Formation as relating to Inergy Partners, LLC, as amended (incorporated herein by reference to Exhibit 3.7 to Inergy, L.P.’s Registration Statement on Form S-1/A (Registration No. 333-56976) filed on May 7, 2001).

3.8		Second Amended and Restated Limited Liability Company Agreement of Inergy Partners, LLC, dated as of July 31, 2001 (incorporated herein by reference to Exhibit 3.8 to Inergy, L.P.’s Registration Statement on Form S-1 (Registration No. 333-89010) filed on May 24, 2002).

31.1		Certification of Chief Executive Officer of Inergy, L.P. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2		Certification of Chief Financial Officer of Inergy, L.P pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1		Certification of Chief Executive Officer of Inergy, L.P. 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 Chief Financial Officer of Inergy, L.P. pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

Pursuant to the requirements 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.


		Page
Part I – Financial Information

Item 1 – Financial Statements of Inergy, L.P.:

Consolidated Balance Sheets as of June 30, 2007 (unaudited) and September 30, 2006		3

Unaudited Consolidated Statements of Operations for the Three and Nine Months Ended June 30, 2007 and 2006		4

Unaudited Consolidated Statement of Partners’ Capital for the Nine Months Ended June 30, 2007		5

Unaudited Consolidated Statements of Cash Flows for the Nine Months Ended June 30, 2007 and 2006		6

Unaudited Notes to Consolidated Financial Statements		8

Item 2 – Management’s Discussion and Analysis of Financial Condition and Results of Operations		19

Item 3 – Quantitative and Qualitative Disclosures About Market Risk		30

Item 4 – Controls and Procedures		32

Part II – Other Information

Item 1 – Legal Proceedings		33

Item 1A – Risk Factors		33

Item 2 – Unregistered Sales of Equity Securities and Use of Proceeds		33

Item 3 – Defaults Upon Senior Securities		33

Item 4 – Submission of Matters to a Vote of Security Holders		33

Item 5 – Other Information		33

Item 6 – Exhibits		33

Signature		35


	June 30, 2007		September 30, 2006
	*(unaudited)*
Assets
Current assets:
Cash	$	6.8	$	12.0
Accounts receivable, less allowance for doubtful accounts of $5.9 million and $2.9 million at June 30, 2007 and September 30, 2006, respectively		87.7		99.5
Inventories		79.1		108.1
Assets from price risk management activities		27.2		46.2
Prepaid expenses and other current assets		15.3		29.8

Total current assets		216.1		295.6

Property, plant and equipment		933.6		847.9
Less: accumulated depreciation		163.8		124.4

Property, plant and equipment, net		769.8		723.5

Intangible assets:
Customer accounts		233.8		226.0
Covenants not to compete		62.9		54.2
Trademarks		32.8		32.8
Deferred financing and other costs		23.2		23.3

		352.7		336.3
Less: accumulated amortization		72.7		52.8

Intangible assets, net		280.0		283.5
Goodwill		365.3		332.4
Other assets		2.1		4.0

Total assets	$	1,633.3	$	1,639.0

Liabilities and partners’ capital
Current liabilities:
Accounts payable	$	66.1	$	81.5
Accrued expenses		51.2		62.9
Customer deposits		41.9		98.0
Liabilities from price risk management activities		26.5		49.0
Current portion of long-term debt		4.1		16.9

Total current liabilities		189.8		308.3

Long-term debt, less current portion		632.2		642.8
Other long-term liabilities		12.0		11.8

Partners’ capital
Common unitholders (49,708,986 and 45,005,153 units issued and outstanding as of June 30, 2007 and September 30, 2006, respectively)		797.0		648.8
Special unitholders (769,941 units issued and outstanding as of September 30, 2006)		—		25.0
Non-managing general partner and affiliate		2.3		2.3

Total partners’ capital		799.3		676.1

Total liabilities and partners’ capital	$	1,633.3	$	1,639.0


	Three Months Ended June 30,						Nine Months Ended June 30,
	2007			2006			2007			2006
Revenue:
Propane	$	168.3		$	143.7		$	956.2		$	900.0
Other		78.5			71.9			251.0			242.7

		246.8			215.6			1,207.2			1,142.7
Cost of product sold (excluding depreciation and amortization as shown below)
Propane		122.7			101.3			666.7			650.9
Other		48.3			48.9			152.2			162.7

		171.0			150.2			818.9			813.6

Gross profit		75.8			65.4			388.3			329.1
Expenses:
Operating and administrative		63.2			62.6			194.7			188.7
Depreciation and amortization		21.4			20.6			60.9			58.7
Loss on disposal of assets		0.7			1.7			1.6			2.4

Operating income (loss)		(9.5	)		(19.5	)		131.1			79.3

Other income (expense):
Interest expense, net		(12.0	)		(13.6	)		(39.1	)		(41.1	)
Finance charge income		0.9			0.7			2.4			2.2
Other income		0.2			0.2			1.4			0.6

Income (loss) before income taxes		(20.4	)		(32.2	)		95.8			41.0
Provision for income taxes		(0.2	)		(0.2	)		(0.5	)		(0.8	)

Net income (loss)	$	(20.6	)	$	(32.4	)	$	95.3		$	40.2

Partners’ interest information:

Non-managing general partner and affiliate:
Interest in net income	$	7.0		$	4.2		$	20.1		$	13.0
Beneficial conversion value of Special Units (Note 6)		10.3			—			10.3			—

	$	17.3		$	4.2		$	30.4		$	13.0

Limited partners’ interest in net income (loss):
Common unit interest	$	(37.9	)	$	(32.0	)	$	64.9		$	23.8
Senior subordinated interest		—			(3.5	)		—			2.6
Junior subordinated interest		—			(1.1	)		—			0.8

Total limited partners’ interest in net income (loss):	$	(37.9	)	$	(36.6	)	$	64.9		$	27.2

Net income (loss) per limited partner unit:
Basic	$	(0.77	)	$	(0.90	)	$	1.38		$	0.67

Diluted	$	(0.77	)	$	(0.90	)	$	1.37		$	0.67

Weighted average common limited partners’ units outstanding (in thousands):
Common units		49,356			35,453			47,041			35,339
Senior subordinated units		—			3,822			—			3,822
Junior subordinated units		—			1,145			—			1,145

Basic		49,356			40,420			47,041			40,306
Dilutive units		—			—			190			479

Diluted		49,356			40,420			47,231			40,785


	Common Unit Capital			Non-Managing General Partner and Affiliate			Special Units Capital			Total Partners’ Capital
Balance at September 30, 2006	$	648.8		$	2.3		$	25.0		$	676.1
Net proceeds from issuance of common units		104.5			—			—			104.5
Net proceeds from common unit options exercised		3.3			—			—			3.3
Contribution from unit based compensation charges		0.5			—			—			0.5
Special units converted to common units		25.0			—			(25.0	)		—
Distributions		(79.2	)		(20.3	)		—			(99.5	)
Comprehensive income:
Net income		75.2			20.1			—			95.3
Unrealized gain on cash flow hedges, net of reclassification of realized losses on cash flow hedges into earnings of $(16.6) million		18.9			0.2			—			19.1

Comprehensive income											114.4

Balance at June 30, 2007	$	797.0		$	2.3		$	—		$	799.3


	Nine Months Ended June 30,
	2007			2006
Operating activities
Net income	$	95.3		$	40.2
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation		42.7			45.2
Amortization		18.2			13.5
Amortization of deferred financing costs		1.7			1.6
Unit-based compensation charges		0.5			0.2
Provision for doubtful accounts		3.5			3.1
Loss on disposal of assets		1.6			2.4
Net assets from price risk management activities		15.5			2.9
Changes in operating assets and liabilities, net of effects from acquisitions:
Accounts receivable		7.8			17.6
Inventories		29.5			62.4
Prepaid expenses and other current assets		14.6			7.2
Other assets (liabilities)		1.9			(0.6	)
Accounts payable		(20.1	)		(51.1	)
Accrued expenses		(13.1	)		0.3
Customer deposits		(56.2	)		(33.3	)

Net cash provided by operating activities		143.4			111.6

Investing activities
Acquisitions, net of cash acquired		(87.7	)		(177.0	)
Purchases of property, plant and equipment		(48.8	)		(19.5	)
Deferred acquisition costs incurred		(0.4	)		(0.5	)
Proceeds from sale of assets		4.8			8.4

Net cash used in investing activities		(132.1	)		(188.6	)

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


	June 30, 2007		September 30, 2006
Propane gas and other liquids	$	66.5	$	96.1
Appliances, parts and supplies		12.6		12.0

	$	79.1	$	108.1


	June 30, 2007		September 30, 2006
Credit agreement	$	1.3	$	22.7
Senior unsecured notes		619.3		621.4
Obligations under noncompetition agreements and notes to former owners of businesses acquired		15.7		15.6

		636.3		659.7
Less: current portion		4.1		16.9

	$	632.2	$	642.8


Nine Months Ended June 30, 2007
Record Date	Payment Date	Per Unit Rate		Distribution Amount *(in millions)*
November 7, 2006	November 14, 2006	$	0.555	$	31.2
February 7, 2007	February 14, 2007	$	0.565		32.1
May 8, 2007	May 15, 2007	$	0.575		36.2

				$	99.5
Nine Months Ended June 30, 2006
Record Date	Payment Date	Per Unit Rate		Distribution Amount *(in millions)*
November 7, 2005	November 14, 2005	$	0.52	$	25.1
February 7, 2006	February 14, 2006	$	0.53		25.9
May 8, 2006	May 15, 2006	$	0.54		26.7

				$	77.7


	Range of Exercise Prices		Weighted-Average Exercise Price		Number of Units
Outstanding at September 30, 2006	$	8.19 - $31.32	$	16.37	711,964
Granted		—		—	—
Exercised	$	8.19 - $27.14	$	11.53	(290,464	)
Canceled		$15.11	$	15.11	(4,000	)

Outstanding at June 30, 2007	$	13.75 - $31.32	$	19.75	417,500

Exercisable at June 30, 2007		—		—	—


Weighted-average fair value of options granted	$	1.02
Expected volatility		0.229
Distribution yield		6.4	%
Expected life of option in years		5
Risk-free interest rate		4.9	%


	Three Months Ended June 30, 2007
	Propane Operations		Midstream Operations		Intersegment Eliminations		Total
Retail propane revenues	$	102.5	$	—	$	—	$	102.5
Wholesale propane revenues		61.8		4.0		—		65.8
Storage, fractionation and other midstream revenues		—		43.4		—		43.4
Transportation revenues		3.9		—		—		3.9
Propane-related appliance sales revenues		4.9		—		—		4.9
Retail service revenues		3.6		—		—		3.6
Rental service and other revenues		5.4		—		—		5.4
Distillate revenues		17.3		—		—		17.3
Gross profit		60.7		15.1		—		75.8
Identifiable assets		145.4		21.4		—		166.8
Goodwill		260.0		105.3		—		365.3


	Three Months Ended June 30, 2006
	Propane Operations		Midstream Operations		Intersegment Eliminations		Total
Retail propane revenues	$	91.2	$	—	$	—	$	91.2
Wholesale propane revenues		47.4		5.1		—		52.5
Storage, fractionation and other midstream revenues		—		38.7		—		38.7
Transportation revenues		2.8		—		—		2.8
Propane-related appliance sales revenues		5.2		—		—		5.2
Retail service revenues		3.6		—		—		3.6
Rental service and other revenues		5.0		—		—		5.0
Distillate revenues		16.6		—		—		16.6
Gross profit		55.3		10.1		—		65.4
Identifiable assets		147.7		13.4		—		161.1
Goodwill		265.8		23.2		—		289.0


	Three Months Ended June 30,						Change
	2007			2006			In Dollars			Percentage
Revenue	$	246.8		$	215.6		$	31.2		14.5	%
Cost of product sold		171.0			150.2			20.8		13.8

Gross profit		75.8			65.4			10.4		15.9
Operating and administrative expenses		63.2			62.6			0.6		1.0
Depreciation and amortization		21.4			20.6			0.8		3.9
Loss on disposal of assets		0.7			1.7			(1.0	)	(58.8	)

Operating loss		(9.5	)		(19.5	)		10.0		51.3
Interest expense, net		(12.0	)		(13.6	)		1.6		11.8
Finance charge income		0.9			0.7			0.2		28.6
Other income		0.2			0.2			—		—

Loss before income taxes		(20.4	)		(32.2	)		11.8		36.6
Provision for income taxes		(0.2	)		(0.2	)		—		—

Net loss	$	(20.6	)	$	(32.4	)	$	11.8		36.4	%


	Revenues								Gallons
	Three Months Ended June 30,				Change				Three Months Ended June 30,		Change
	2007		2006		In Dollars		Percent		2007	2006	In Units	Percent
Retail propane	$	102.5	$	91.2	$	11.3	12.4	%	50.0	46.6	3.4	7.3	%
Wholesale propane		65.8		52.5		13.3	25.3		58.6	53.8	4.8	8.9
Other retail		35.1		33.2		1.9	5.7		—	—	—	—
Storage, fractionation and midstream		43.4		38.7		4.7	12.1		—	—	—	—

Total	$	246.8	$	215.6	$	31.2	14.5	%	108.6	100.4	8.2	8.2	%


	Three Months Ended June 30,
	2007			2006
EBITDA:
Net loss	$	(20.6	)	$	(32.4	)
Interest expense, net		12.0			13.6
Provision for income taxes		0.2			0.2
Depreciation and amortization		21.4			20.6

EBITDA	$	13.0		$	2.0

Non-cash (gain) loss on derivative contracts		(0.5	)		0.4
Long-term incentive and equity compensation expense		0.2			2.4
Loss on disposal of assets		0.7			1.7

Adjusted EBITDA	$	13.4		$	6.5


	Total		Less than 1 year		1-3 years		4-5 years		After 5 years
Aggregate amount of principal and interest to be paid on the outstanding long-term debt ^(a)	$	1,011.4	$	51.7	$	99.3	$	98.2	$	762.2
Amount of principal and interest to be paid on other long-term obligations		9.5		3.0		6.5		—		—
Future minimum lease payments under noncancelable operating leases		18.4		6.2		7.2		2.6		2.4
Fixed price purchase commitments		183.6		182.3		1.3		—		—
Standby letters of credit		26.5		25.8		0.3		0.4		—
Purchase commitments of identified growth projects ^(b)		37.8		37.8		—		—		—


	June 30, 2007		September 30, 2006
	Fixed Price Payor	Fixed Price Receiver	Fixed Price Payor	Fixed Price Receiver
Propane, crude and heating oil (barrels)	3.8	3.8	8.0	7.5
Natural gas (MMBTU’s)	1.4	1.4	5.5	5.4


	INERGY, L.P.

	By:	INERGY GP, LLC
		(its managing general partner)

Date: August 8, 2007	By:	/s/ R. Brooks Sherman, Jr.
		R. Brooks Sherman, Jr.
		Senior Vice President and Chief Financial Officer
		(Duly Authorized Officer and Principal Financial Officer and Principal Accounting Officer)