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Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2006

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

For the transition period from to .

COMMISSION FILE NUMBER: 0-32453

Inergy, L.P.

(Exact name of registrant as specified in its charter)


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

Two Brush Creek Blvd., Suite 200 Kansas City, Missouri		64112
(Address of principal executive offices)		(Zip code)

(816) 842-8181

(Registrant’s telephone number, including area code)

(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.


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

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

The following units were outstanding at August 1, 2006:


Common Units		39,682,585
Senior Subordinated Units		3,821,884
Junior Subordinated Units		1,145,084
Special Units		769,941

INERGY, L.P.

INDEX TO FORM 10-Q


		Page
Part I – Financial Information		3

Item 1 – Financial Statements of Inergy, L.P.:		3
Consolidated Balance Sheets as of June 30, 2006 (unaudited) and September 30, 2005		3
Unaudited Consolidated Statements of Operations for the Three and Nine Months Ended June 30, 2006 and 2005		5
Unaudited Consolidated Statement of Partners’ Capital for the Nine Months Ended June 30, 2006		6
Unaudited Consolidated Statements of Cash Flows for the Nine Months Ended June 30, 2006 and 2005		7
Unaudited Notes to Consolidated Financial Statements		9

Item 2 – Management’s Discussion and Analysis of Financial Condition and Results of Operations		24

Item 3 – Quantitative and Qualitative Disclosures About Market Risk		36

Item 4 – Controls and Procedures		38

Part II – Other Information		39

Item 1 – Legal Proceedings		39

Item 2 – Unregistered Sales of Equity Securities and Use of Proceeds		39

Item 3 – Defaults Upon Senior Securities		39

Item 4 – Submission of Matters to a Vote of Security Holders		39

Item 5 – Other Information		39

Item 6 – Exhibits		39

Signature		40

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements of Inergy L.P.

INERGY L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands, except unit information)


	June 30, 2006			September 30, 2005
	*(unaudited)*
Assets

Current assets:
Cash	$	46,065		$	9,500
Accounts receivable, less allowance for doubtful accounts of $4,889 and $2,356 at June 30, 2006 and September 30, 2005, respectively		87,134			94,876
Inventories		74,026			117,812
Assets from price risk management activities		31,175			58,356
Prepaid expenses and other current assets		16,248			22,674

Total current assets		254,648			303,218

Property, plant and equipment
Tanks and plant equipment		653,211			552,548
Land and buildings		170,740			155,335
Vehicles		84,102			66,223
Office furniture and equipment		19,296			17,055
Construction in process		12,305			13,613

		939,654			804,774
Less accumulated depreciation		(116,485	)		(72,756	)

Property, plant and equipment, net		823,169			732,018

Intangible assets:
Customer accounts		170,134			161,000
Covenants not to compete		37,601			30,606
Trademarks		32,845			32,845
Deferred financing costs		22,972			20,444
Deferred acquisition costs		746			725

		264,298			245,620
Less accumulated amortization		(43,641	)		(30,972	)

Intangible assets, net		220,657			214,648

Goodwill		289,033			249,173

Other assets		4,826			3,187

Total assets	$	1,592,333		$	1,502,244

INERGY, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (continued)

(in thousands, except unit information)


	June 30, 2006			September 30, 2005
	*(unaudited)*
Liabilities and partners’ capital

Current liabilities:
Accounts payable	$	72,496		$	104,148
Accrued expenses		47,490			44,366
Customer deposits		45,758			68,567
Liabilities from price risk management activities		22,759			49,572
Current portion of long-term debt		3,811			17,931

Total current liabilities		192,314			284,584

Long-term debt, less current portion		627,300			541,800

Other long-term liabilities		15,916			11,966

Partners’ capital
Common unitholders (39,647,585 and 34,411,329 units issued and outstanding as of June 30, 2006 and September 30, 2005, respectively)		721,771			623,861
Senior subordinated unitholders (3,821,884 units issued and outstanding as of June 30, 2006 and September 30, 2005)		10,803			14,276
Junior subordinated unitholders (1,145,084 units issued and outstanding as of June 30, 2006 and September 30, 2005)		(4,143	)		(3,163	)
Special unitholders (769,941 units issued and outstanding as of June 30, 2006 and September 30, 2005)		25,000			25,000
Non-managing general partner and affiliate		3,372			3,920

Total partners’ capital		756,803			663,894

Total liabilities and partners’ capital	$	1,592,333		$	1,502,244

See accompanying notes to the consolidated financial statements.

INERGY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per unit data)

(unaudited)


	Three Months Ended June 30,						Nine Months Ended June 30,
	2006			2005			2006			2005
Revenue:
Propane	$	143,699		$	127,493		$	888,027		$	708,201
Other		71,919			46,109			242,658			137,294

		215,618			173,602			1,130,685			845,495

Cost of product sold (excluding depreciation and amortization as shown below)
Propane		101,300			86,178			638,952			502,223
Other		48,941			36,820			162,645			91,467

		150,241			122,998			801,597			593,690

Gross profit		65,377			50,604			329,088			251,805
Expenses:
Operating and administrative		62,578			52,078			188,688			146,055
Depreciation and amortization		20,611			13,865			58,673			35,094

Operating income (loss)		(17,812	)		(15,339	)		81,727			70,656

Other income (expense):
Interest expense, net		(13,639	)		(9,144	)		(41,063	)		(23,018	)
Write-off of deferred financing costs		—			—			—			(6,990	)
Loss on sale of property, plant and equipment		(1,712	)		(270	)		(2,432	)		(170	)
Finance charges		741			576			2,176			1,488
Other		222			82			635			234

Income (loss) before income taxes		(32,200	)		(24,095	)		41,043			42,200
Provision for income taxes		165			24			875			358

Net income (loss)	$	(32,365	)	$	(24,119	)	$	40,168		$	41,842


Partners’ interest information:
Non-managing general partners’ and affiliate’s interest in net income (loss):	$	4,190		$	(339	)	$	13,014		$	5,390


Limited partners’ interest in net income (loss):
Common unit interest	$	(32,039	)	$	(18,989	)	$	23,807		$	28,489
Senior subordinated interest		(3,475	)		(3,963	)		2,575			6,586
Junior subordinated interest		(1,041	)		(828	)		772			1,377

Total limited partners’ interest in net income (loss):	$	(36,555	)	$	(23,780	)	$	27,154		$	36,452


Net income (loss) per limited partner unit:
Basic	$	(0.90	)	$	(0.72	)	$	0.67		$	1.20

Diluted	$	(0.90	)	$	(0.72	)	$	0.67		$	1.18

Weighted average common limited partners’ units outstanding:
Basic
Common units		35,453			26,254			35,339			23,697

Senior subordinated units		3,822			5,479			3,822			5,479

Junior subordinated units		1,145			1,145			1,145			1,145

Diluted		40,420			32,878			40,785			30,930

See accompanying notes to the consolidated financial statements

INERGY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL

(in thousands)

(unaudited)


	Common Unit Capital			Senior Subordinated Unit Capital			Junior Subordinated Unit Capital			Non-Managing General Partner and Affiliate			Special Units Capital		Total Partners’ Capital
Balance at September 30, 2005	$	623,861		$	14,276		$	(3,163	)	$	3,920		$	25,000	$	663,894
Net proceeds from issuance of common units		127,693			—			—			—			—		127,693
Contribution from employee unit plans		195			—			—			—			—		195
Distributions		(55,951	)		(6,283	)		(1,821	)		(13,591	)		—		(77,646	)
Comprehensive income:
Net income		23,807			2,575			772			13,014			—		40,168
Unrealized gain on derivative instruments, net of reclassification adjustments of $(5,403)		2,165			235			69			29			—		2,498
Foreign currency translation		1			—			—			—			—		1

Comprehensive income																42,667

Balance at June 30, 2006	$	721,771		$	10,803		$	(4,143	)	$	3,372		$	25,000	$	756,803

See accompanying notes to the consolidated financial statements.

INERGY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

(unaudited)


	Nine Months Ended June 30,
	2006			2005
Operating activities
Net income	$	40,168		$	41,842
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation		45,159			25,238
Amortization		13,514			9,856
Amortization of deferred financing costs		1,644			1,328
Unit based compensation charges		195			—
Write-off of deferred financing costs		—			6,990
Provision for doubtful accounts		3,058			1,944
Loss on disposal of property, plant and equipment		2,432			170
Net assets/(liabilities) from price risk management activities		2,868			(7,832	)
Changes in operating assets and liabilities, net of effects from acquisitions:
Accounts receivable		17,634			17,837
Inventories		62,400			24,863
Prepaid expenses and other current assets		7,220			7,349
Other assets (liabilities)		(622	)		(2,488	)
Accounts payable		(50,705	)		(24,116	)
Accrued expenses		259			3,368
Customer deposits		(33,258	)		(26,387	)

Net cash provided by operating activities		111,966			79,962

Investing activities
Acquisitions, net of cash acquired		(177,039	)		(588,863	)
Purchases of property, plant and equipment		(19,844	)		(25,049	)
Deferred acquisition costs incurred		(444	)		(411	)
Proceeds from the sale of property, plant and equipment		8,359			2,721

Net cash used in investing activities		(188,968	)		(611,602	)

INERGY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (continued)

(in thousands)

(unaudited)


	Nine Months Ended June 30,
	2006			2005
Financing activities
Proceeds from the issuance of long-term debt	$	666,500		$	1,345,879
Principal payments on long-term debt		(597,963	)		(954,847	)
Distributions		(77,646	)		(47,917	)
Payments for deferred financing costs		(5,018	)		(22,809	)
Net proceeds from the issuance of common units		127,693			230,122

Net cash provided by financing activities		113,566			550,428

Effect of foreign exchange rate changes on cash		1			15


Net increase in cash		36,565			18,803
Cash at beginning of period		9,500			2,256

Cash at end of period	$	46,065		$	21,059

Supplemental disclosure of cash flow information
Cash paid during the period for interest	$	42,544		$	20,655

Supplemental schedule of noncash investing and financing activities
Additions to covenants not to compete through the issuance of noncompete obligations	$	6,793		$	7,881


Decrease in the fair value of long-term debt and related increase in the interest rate swap liability	$	5,495		$	801


Acquisitions of retail propane companies, net of cash acquired:
Current assets	$	32,357		$	72,081
Property, plant and equipment		127,259			329,028
Intangible assets		15,706			141,387
Goodwill		39,860			129,085
Other assets		732			1,359
Current liabilities		(32,082	)		(76,196	)
Non-compete liabilities		(6,793	)		(7,881	)

	$	177,039		$	588,863

See accompanying notes to the consolidated financial statements.

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Note 1 – Organization and Basis of Presentation

Organization

The consolidated financial statements of Inergy, L.P. (“Inergy” or the “Company”) include the accounts of Inergy and its subsidiaries, including Inergy Propane, LLC (“Inergy Propane”) and its subsidiary Inergy Sales and Service Inc. (“Services”), Inergy Acquisition Company, LLC (collectively, the “Operating Companies”) and Inergy Finance Corp.

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

Pursuant to 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 $0.6 million and $0.7 million for the three months ended June 30, 2006 and 2005, respectively, and $4.2 million and $1.8 million for the nine month periods ended June 30, 2006 and 2005, respectively, include compensation and benefits paid to officers and employees of Inergy GP and its affiliates.

As of June 30, 2006, Holdings owns an aggregate 9.4% interest in Inergy, inclusive of ownership of the Non-Managing General Partner and Managing General Partner. This ownership is comprised of an approximate 1.0% general partnership interest and an 8.4% limited partnership interest.

Nature of Operations

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

Basis of Presentation

The financial information contained herein as of June 30, 2006 and for the three-month and nine-month periods ended June 30, 2006 and 2005 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, 2006 are not indicative of the results of operations that may be expected for the entire year.

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

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 amended, as filed with the Securities and Exchange Commission for the year ended September 30, 2005.

Reclassifications

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

Note 2 – Accounting Policies

Financial Instruments and Price Risk Management

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

Inergy is party to certain commodity derivative financial instruments that are designated as hedges of selected inventory positions, and qualify as fair value hedges, as defined in SFAS 133. Inergy’s overall objective for entering into fair value hedges is to manage its exposure to fluctuations in commodity prices and changes in the fair market value of its inventories as well as to ensure an adequate physical supply will be available. These derivatives are recorded at fair value on the balance sheets as price risk management assets or liabilities and the related change in fair value is recorded to earnings in the current period as cost of product sold. Any ineffective portion of the gain or loss is recognized as cost of product sold in the current period. During the three and nine months ended June 30, 2006, Inergy recognized a net loss of $0.1 million and a net gain of $0.1 million, respectively, related to the ineffective portion of its fair value hedging instruments and a net loss of $0.7 million and a net gain of $0.2 million, respectively, related to the portion of its fair value hedging instruments 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 $7.9 million and $5.4 million at June 30, 2006 and September 30, 2005, respectively.

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

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

Revenue Recognition

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

Expense Classification

Cost of product sold consists of tangible products sold including all propane and other natural gas liquids sold and all propane related appliances sold. Operating and administrative expenses consist of all expenses incurred by Inergy other than those described above in cost of product sold and depreciation and amortization. Certain of Inergy’s operating and administrative expenses and depreciation and amortization are incurred in the distribution of the product sales but are not included in cost of product sold. These amounts were $18.6 million and $15.4 million for the three months ended June 30, 2006 and 2005, respectively, and $60.0 million and $39.7 million, for the nine months ended June 30, 2006 and 2005, respectively.

Use of Estimates

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

Inventories

Inventories for retail operations, which mainly consist of propane gas and other liquids, are stated at the lower of cost or market and are computed using the average cost method. Wholesale propane inventories are stated at the lower of cost or market determined by using the average cost method unless designated as being hedged by forward sales contracts. Wholesale propane inventories being hedged and carried at market value at June 30, 2006 and September 30, 2005 amount to $37.8 million and $85.8 million, respectively. Inventories for facility and midstream operations are stated at the lower of cost or market determined using the first-in-first-out method.

Inventories consist of (in thousands):


	June 30, 2006		September 30, 2005
Propane gas and other liquids	$	61,817	$	110,085
Appliances, parts and supplies		12,209		7,727

	$	74,026	$	117,812

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Shipping and Handling Costs

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

Identifiable Intangible Assets

The Company has recorded certain identifiable intangible assets, including covenants not to compete, customer accounts, trademarks, deferred financing costs and deferred acquisition costs. Covenants not to compete, customer accounts and trademarks have arisen from the various acquisitions by Inergy. Deferred financing costs represent financing costs incurred in obtaining financing and are being amortized over the term of the related debt. Deferred acquisition costs represent costs incurred on acquisitions that Inergy is actively pursuing.

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


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

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

Income Per Unit

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

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

The following table presents the calculation of basic and diluted net income per limited partner unit (in thousands, except per unit data):


	Three Months Ended June 30,						Nine Months Ended June 30,
	2006			2005			2006		2005
Numerator:
Net income (loss)	$	(32,365	)	$	(24,119	)	$	40,168	$	41,842
Less: Non-Managing General Partner’s interest in net income (loss)		4,190			(339	)		13,014		5,390

Limited partners’ interest in net income (loss) – diluted	$	(36,555	)	$	(23,780	)	$	27,154	$	36,452
Less: Senior subordinated interest in net income (loss)		(3,475	)		(3,963	)		2,575		6,586
Less: Junior subordinated interest in net income (loss)		(1,041	)		(828	)		772		1,377

Common unit interest in net income (loss) – basic	$	(32,039	)	$	(18,989	)	$	23,807	$	28,489

Denominator:

Weighted average common units outstanding – basic		35,453			26,254			35,339		23,697
Effect of converting senior subordinated units		3,822			5,479			3,822		5,479
Effect of converting junior subordinated units		1,145			1,145			1,145		1,145
Effect of dilutive units		—			—			479		609

Weighted average limited partners’ units outstanding – dilutive		40,420			32,878			40,785		30,930

Net income (loss) per limited partner unit:
Basic	$	(0.90	)	$	(0.72	)	$	0.67	$	1.20
Diluted	$	(0.90	)	$	(0.72	)	$	0.67	$	1.18

Net income per limited partner unit for the senior subordinated units and the junior subordinated units was the same as net income per common limited partner unit for all periods presented.

As the effects of including incremental units associated with options were antidilutive for the three months ended June 30, 2006 and 2005 due to the net loss reported for those periods, no unit options or other dilutive units were reflected in the applicable dilutive earning per unit computations. As a result, both basic earnings per unit and diluted earnings per unit reflect the same calculation for the periods ended June 30, 2006 and 2005, respectively. Weighted average antidilutive unit options outstanding totaled 463,783 and 622,708 for the three months ended June 30, 2006 and 2005, respectively.

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Accounting for Unit-Based Compensation

Inergy has a unit-based employee compensation plan, which is accounted for under the provisions of Statement of Financial Accounting Standards (“SFAS”) No. 123 (revised 2004), “Share-Based Payment” (“SFAS 123R”), which is a revision of SFAS No. 123, “Accounting for Stock-Based Compensation”. SFAS 123(R) supersedes APB Opinion No. 25, “Accounting for Stock Issued to Employees” (“APB 25”), and amends SFAS No. 95, “Statement of Cash Flows.” SFAS No. 123(R) requires all share-based payments to employees, including grants of employee stock options, to be recognized in the income statement based on their fair values.

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

The Company adopted SFAS No. 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 No. 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, 2006 was approximately $0.2 million and its implementation did not significantly impact earnings per share or cash flows from operations for the periods presented.

The following table illustrates the effect on net income and net income per limited partner unit as if Inergy had applied the fair value recognition provision of SFAS No. 123(R) to unit-based employee compensation for the three and nine months ended June 30, 2005. For purposes of pro forma disclosures, the estimated fair value of an option is amortized to expense over the option’s vesting period (in thousands, except per unit data).

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)


	Three Months Ended June 30, 2005			Nine Months Ended June 30, 2005
Net income (loss) as reported	$	(24,119	)	$	41,842
Deduct: Total unit-based employee compensation expense determined under fair value method of all awards		58			185

Pro forma net income (loss)	$	(24,177	)	$	41,657

Deduct: Non-managing general partners’ interest in net income (loss)	$	(339	)	$	5,390

Pro forma limited partners’ interest in net income (loss) for the three and nine months ended June 30, 2005	$	(23,838	)	$	36,267

Net income (loss) per limited partner unit:
Basic – as reported	$	(0.72	)	$	1.20

Basic – pro forma	$	(0.73	)	$	1.20

Diluted – as reported	$	(0.72	)	$	1.18

Diluted – pro forma	$	(0.73	)	$	1.17

Unit Options

Unit options issued under the long-term incentive plan have an exercise price equal to the fair market value of the units on the date of the grant. In general, unit options will expire after 10 years and are subject to the vesting provisions of the Subordination Period. In addition, most unit option grants made under the plan provide that the unit options will become exercisable upon a change of control of the managing general partner or Inergy. None of the outstanding unit options were exercisable at June 30, 2006. With the payment of the distribution on August 14, 2006 with respect to the quarter ended June 30, 2006, the Partnership will have met the necessary financial tests for the senior subordinated units and the junior subordinated units to convert to common units. Therefore, the remaining 3,821,884 senior subordinated units and 1,145,084 junior subordinated units are expected to convert to common units on a one-for-one basis on August 14, 2006.

The weighted-average remaining contract life for options outstanding at June 30, 2006 is approximately seven years. The fair value of each option grant was estimated as of the grant date using the Black-Scholes option pricing model. Expected volatility was based on a combination of historical and implied volatilities of the Company’s stock over a period at least as long as the options’ expected term. The expected life represents the period of time that the options granted are expected to be outstanding. The risk-free rate is based on the applicable U.S. Treasury yield curve in effect at the time of the grant of the share options.


Expected volatility	.167
Distribution yield	8.17	%
Expected life of option in years	5
Risk-free interest rate	4.6	%

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

A summary of Inergy’s unit option activity for the nine months ended June 30, 2006 is as follows:


	Number of Units		Weighted- Average Exercise Price			Weighted- Average Remaining Contractual Term
Outstanding at September 30, 2005	1,112,564		$	14.87
Granted	6,500			26.27
Exercised	—			—
Forfeited	(45,000	)		(18.58	)

Outstanding at June 30, 2006	1,074,064		$	14.78		6.8

Exercisable at June 30, 2006	—			—

The weighted average grant-date fair value of options granted through June 30, 2006 was $1.56. The aggregate intrinsic value of options outstanding at June 30, 2006 was $12.1 million. There were no options exercisable at June 30, 2006. Aggregate intrinsic value represents the positive difference between the Company’s closing stock price on the last trading day of the fiscal period, which was $25.76 on June 30, 2006, and the exercise price multiplied by the number of options outstanding.

Restricted Units

A restricted unit is a common unit that vests over a period of time and that during such time is subject to forfeiture. The compensation committee may make grants of restricted units to employees, directors and consultants containing such terms as the compensation committee determines. The compensation committee will determine the period over which restricted units granted to participants will vest. The compensation committee, in its discretion, may base its determination upon the achievement of specified financial objectives or other events. In addition, the restricted units will vest upon a change in control of the managing general partner of Inergy. If a grantee’s employment, consulting arrangement or membership on the board of directors terminates for any reason, the grantee’s restricted units will be automatically forfeited unless, and to the extent, the compensation committee or the terms of the award agreement provide otherwise.

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

On March 20, 2006, the compensation committee granted 20,000 restricted units. These restricted units vest over a three year period beginning three years from the grant date, subject to the achievement of certain specified performance objectives. Failure to meet the performance objectives will result in forfeiture and cancellation of the restricted units. The Company recognizes expense on these shares each quarter using an estimate of the shares expected to vest multiplied by the closing price of the Company’s common stock of $27.09 on the date of grant.

On April 3, 2006, the compensation committee granted 3,756 restricted units. These restricted units vest over a three year period beginning one year from the grant date. The Company recognizes expense on these shares each quarter using an estimate of the shares expected to vest multiplied by the closing price of the Company’s common stock of $26.62 on the date of grant.

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

The compensation expense recorded by the Company related to these restricted stock awards was not significant for the three and nine month periods ended June 30, 2006.

As of June 30, 2006, there was $0.9 million of total unrecognized compensation cost related to unvested share-based compensation awards granted to employees under the restricted stock and unit option plans. That cost is expected to be recognized over a period of 5 years.

Segment Information

SFAS No. 131, “Disclosures about Segments of an Enterprise and Related Information” (“SFAS 131”) establishes standards for reporting information about operating segments, as well as related disclosures about products and services, geographic areas, and major customers. Further, SFAS 131 defines operating segments as components of an enterprise for which separate financial information is available that is evaluated regularly by the chief operating decision maker in deciding how to allocate resources and assessing performance. In determining reportable segments under the provisions of SFAS 131, Inergy examined the way it organizes its business internally for making operating decisions and assessing business performance. See Note 7 for disclosures related to Inergy’s propane and midstream segments.

Recently Issued Accounting Pronouncements

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

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

EITF 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty” addresses the accounting for an entity’s sale of inventory to another entity from which it also purchases inventory to be sold in the same line of business. EITF 04-13 concludes that two or more inventory transactions with the same counterparty should be accounted for as a single non-monetary transaction at fair value or recorded amounts based on inventory classifications. EITF 04-13 is effective for new arrangements entered into, and modifications or renewal of existing arrangements, beginning in the first

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

interim or annual reporting period beginning after March 15, 2006. The Company has evaluated the impact of EITF 04-13 and determined that it does not have a material effect on its financial position, results of operations and cash flows.

Note 3 – Long-Term Debt

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


	June 30, 2006		September 30, 2005
Credit agreement	$	—	$	126,800
Senior unsecured notes		617,857		423,352
Obligations under noncompetition agreements and notes to former owners of businesses acquired		13,254		9,579

		631,111		559,731
Less current portion		3,811		17,931

		627,300	$	541,800

The Company’s credit agreement (“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”). There was no balance outstanding under this agreement at June 30, 2006. At September 30, 2005, the balance outstanding under the Credit Agreement included $20 million under the Working Capital Facility. The prime rate and LIBOR plus the applicable spreads were between 6.61% and 8.50% at June 30, 2006, and between 6.19% and 7.75% at September 30, 2005, for all outstanding debt under the Credit Agreement. Unused borrowings under the Credit Agreement amounted to $399.7 million and $276.2 million at June 30, 2006 and September 30, 2005, respectively. Outstanding standby letters of credit under the Credit Agreement amounted to $25.3 million and $22.0 million, respectively.

On January 11, 2006, Inergy and its wholly owned subsidiary, Inergy Finance Corporation, issued $200 million aggregate principal amount of 8.25% senior unsecured notes due 2016 in a private placement to eligible purchasers. The senior unsecured notes contain covenants similar to the existing senior unsecured notes due 2014. Inergy used the net proceeds of the offering to repay outstanding indebtedness under the revolving acquisition credit facility. The notes represent senior unsecured obligations of Inergy and rank pari passu in right of payment with all other present and future senior indebtedness of Inergy. The senior unsecured notes are jointly and severally guaranteed by all of Inergy’s current domestic subsidiaries. The notes have certain call features which allow Inergy to redeem the notes at specified prices based on date redeemed. On May 18, 2006, Inergy completed an offer to exchange its existing 8.25% Senior Unsecured Notes due 2016 for $200 million of 8.25% senior notes due 2016 (the “2016 Exchange Notes”) that are registered and do not carry transfer restrictions, registration rights and provisions for additional interest. The 2016 Exchange Notes did not provide Inergy with any additional proceeds and satisfied Inergy’s obligations under the registration rights agreement.

During the three months ended March 31, 2005, the Company entered into four interest rate swap agreements scheduled to mature in December 2014, each designed to hedge $25 million in underlying fixed rate senior unsecured notes. These swap agreements, which expire on the same date as the maturity date of the related senior unsecured notes 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

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

interest rate on the notes due every six months. In exchange, Inergy is required to make semi-annual floating interest rate payments on the same dates to the counterparty based on an annual interest rate equal to the 6 month LIBOR interest rate plus spreads between 1.95% and 2.20% applied to the same notional amount of $100 million. The swap agreements have been recognized as fair value hedges. Amounts to be received or paid under the agreements are accrued and recognized over the life of the agreements as an adjustment to interest expense. During the nine months ended June 30, 2006, the Company recognized an approximate $5.5 million decrease 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 liabilities. The fair value of the interest rate swaps was $7.1 million at June 30, 2006.

At June 30, 2006, the Company was in compliance with all of its debt covenants.

Note 4 – Business Acquisitions

During the first week of October 2005, Inergy finalized three acquisitions including Atlas Gas Products, Inc., Dowdle Gas, and Graeber Brothers Inc. In January 2006, Inergy acquired Propane Gas Service, Inc. located in South Windsor, CT. Additionally, on March 31, 2006 and April 17, 2006, the Company acquired Delta Gas Company and Homestead Gas Company, respectively, both of which are located in Southern Florida. These six acquisitions increased Inergy’s market share and the aggregate purchase price, net of cash acquired was $175.7 million. The purchase price allocation for these acquisitions has been prepared on a preliminary basis and changes may occur when additional information becomes available.

The operating results for these acquisitions are included in the consolidated results of operations from the dates of acquisition through June 30, 2006.

The purchase price allocation of Stagecoach has been prepared on a preliminary basis, pending the final asset appraisal, and changes may occur when additional information becomes available.

Note 5 – Partner’s Capital

In October 2005, the underwriters of a September 2005 6,500,000 common unit offering exercised a portion of their over-allotment provision and Inergy issued an additional 900,000 common units in a follow-on offering, resulting in proceeds of $24.7 million, net of underwriters’ discounts, commissions, and offering expenses. These funds were used to repay borrowings under the Credit Agreement.

On March 23, 2006, the Company’s shelf registration statement (File No. 333-132287) was declared effective by the Securities and Exchange Commission for the periodic sale of up to $1.0 billion of common units, partnership securities and debt securities, or any combination thereof. Pursuant to the shelf registration statement, Inergy is permitted to issue these securities from time to time for general business purposes, including debt repayment, future acquisitions, capital expenditures and working capital, or for other potential uses identified in a prospectus supplement.

In June 2006, Inergy issued 4,312,500 common units, under the shelf registration statement, in a public offering, which included 562,500 common units issued as result of the underwriters exercising their over-allotment provision. The issuance of these common units resulted in net proceeds of approximately $103 million, after deducting underwriters’ discounts, commissions and other offering expenses. These proceeds were partially used to repay indebtedness under Inergy’s Credit Agreement with the remainder to be used to fund capital expenditures made in connection with internal growth projects related to Inergy’s midstream assets.

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

As of June 30, 2006, the Special Units were convertible into 841,335 common units, contingent upon the commercial operation of “Phase II” of the Company’s Stagecoach storage facility.

Quarterly Distributions of Available Cash

On November 14, 2005, a quarterly distribution of $0.52 per limited partner unit was paid to unitholders of record on November 7, 2005 with respect to the fourth fiscal quarter of 2005, which totaled $25.1 million. On February 14, 2006, a quarterly distribution of $0.53 per limited partner unit was paid to unitholders of record on February 7, 2006 with respect to the first fiscal quarter of 2006, which totaled $25.9 million. On May 15, 2006, a quarterly distribution of $0.54 per limited partner unit was paid to unitholders of record on May 8, 2006 with respect to the second fiscal quarter of 2006, which totaled $26.7 million. On July 25, 2006, Inergy declared a distribution of $0.545 per limited partner unit to be paid on August 14, 2006 to unitholders of record on August 7, 2006 for a total distribution of $29.9 million with respect to its third fiscal quarter of 2006.

On February 14, 2005, a quarterly distribution of $0.475 per limited partner unit was paid to its unitholders of record on February 7, 2005 with respect to the first fiscal quarter of 2005, which totaled $17.6 million. On May 13, 2005, a quarterly distribution of $0.50 per limited partner unit was paid to unitholders of record on May 6, 2005, for a total distribution of $19.2 million with respect to second fiscal quarter of 2005. On August 12, 2005, a quarterly distribution of $0.51 per limited partner unit was paid to unitholders of record on August 5, 2005 with respect to the third fiscal quarter of 2005, for a total distribution of $19.9 million.

Note 6 – Commitments and Contingencies

Inergy periodically enters into agreements with suppliers to purchase fixed quantities of propane, distillates, natural gas and liquids at fixed prices. At June 30, 2006, the total of these firm purchase commitments was approximately $223.3 million. The Company also enters into agreements with suppliers to purchase quantities of propane, distillates, natural gas and liquids at variable prices at future dates at the then prevailing market prices.

At June 30, 2006, Inergy was contingently liable for letters of credit outstanding totaling $25.3 million, which guarantee various transactions.

Inergy is periodically involved in litigation proceedings. The results of litigation proceedings cannot be predicted with certainty; however, management believes that Inergy does not have material potential liability in connections 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 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 when using certain assumptions followed in the insurance industry and based on past experience.

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

To the extent they have not already been paid, certain employees are entitled to receive up to $2.3 million in aggregate of bonus payments at the end of the subordination periods of the subordinated units. This amount has been accrued at June 30, 2006 since the financial tests have been met as of June 30, 2006 and the payments will be made on or around the distribution payment in August 2006.

Note 7 – Segments

Inergy’s financial statements reflect two operating and reportable segments: propane operations and midstream operations. Inergy’s propane operations include propane sales to end users, the sale of propane-related appliances and service work for propane-related equipment, the sale of distillate products and wholesale distribution of propane and marketing and price risk management services to other users, retailers and resellers of propane. Inergy’s midstream operations include storage of natural gas for third parties, fractionation of natural gas liquids, processing of natural gas, and the distribution of natural gas liquids. Results of operations for acquisitions that occurred during the three and nine months ended June 30, 2006 are included in the propane segment.

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

Revenues, gross profit, identifiable assets and goodwill for each of Inergy’s reportable segments are presented below (in thousands of dollars). The June 30, 2005 segment disclosures have been restated to conform to the current period presentation.

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)


	Three Months Ended June 30, 2006
	Propane Operations		Midstream Operations		Intersegment Eliminations			Total
Retail propane revenues	$	91,239	$	—	$	—		$	91,239
Wholesale propane revenues		47,370		5,090		—			52,460
Storage, fractionation and other midstream revenues		—		38,753		(18	)		38,735
Transportation revenues		2,775		—		—			2,775
Propane-related appliance sales revenues		5,218		—		—			5,218
Retail service revenues		3,598		—		—			3,598
Rental service and other revenues		4,919		—		—			4,919
Distillate revenues		16,674		—		—			16,674
Gross profit		55,295		10,082		—			65,377
Identifiable assets		147,724		13,408		—			161,132
Goodwill		265,808		23,225		—			289,033

	Three Months Ended June 30, 2005
	Propane Operations		Midstream Operations		Intersegment Eliminations			Total
Retail propane revenues	$	79,301	$	—	$	—		$	79,301
Wholesale propane revenues		46,791		1,401		—			48,192
Storage, fractionation and other midstream revenues		—		19,448		—			19,448
Transportation revenues		2,956		—		—			2,956
Propane-related appliance sales revenues		2,948		—		—			2,948
Retail service revenues		3,373		—		—			3,373
Rental service and other revenues		3,317		—		—			3,317
Distillate revenues		14,067		—		—			14,067
Gross profit		47,729		2,875		—			50,604
Identifiable assets		106,746		8,873		—			115,619
Goodwill		207,212		—		—			207,212

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)


	Nine Months Ended June 30, 2006
	Propane Operations		Midstream Operations		Intersegment Eliminations			Total
Retail propane revenues	$	603,087	$	—	$	—		$	603,087
Wholesale propane revenues		269,646		15,294		—			284,940
Storage, fractionation and other midstream revenues		—		109,086		(329	)		108,757
Transportation revenues		7,611		—		—			7,611
Propane-related appliance sales revenues		18,572		—		—			18,572
Retail service revenues		13,144		—		—			13,144
Rental service and other revenues		14,953		—		—			14,953
Distillate revenues		79,621		—		—			79,621
Gross profit		297,938		31,150		—			329,088
Identifiable assets		147,724		13,408		—			161,132
Goodwill		265,808		23,225		—			289,033

	Nine Months Ended June 30, 2005
	Propane Operations		Midstream Operations		Intersegment Eliminations			Total
Retail propane revenues	$	443,689	$	—	$	—		$	443,689
Wholesale propane revenues		248,441		16,071		—			264,512
Storage, fractionation and other midstream revenues		—		41,725		—			41,725
Transportation revenues		8,229		—		—			8,229
Propane-related appliance sales revenues		7,309		—		—			7,309
Retail service revenues		11,629		—		—			11,629
Rental service and other revenues		9,474		—		—			9,474
Distillate revenues		58,928		—		—			58,928
Gross profit		241,050		10,755		—			251,805
Identifiable assets		106,746		8,873		—			115,619
Goodwill		207,212		—		—			207,212

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

“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, as amended, of Inergy, L.P. for the fiscal year ended September 30, 2005.

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 involves 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.

Overview

We are a rapidly growing retail and wholesale propane, supply, marketing and distribution business. We also own and operate a growing midstream operation, including a high performance, multicycle natural gas storage facility (“Stagecoach”) 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 Inergy’s predecessor in 1996 through June 30, 2006, Inergy has acquired 56 companies, 54 propane companies and 2 midstream businesses. Inergy further intends to pursue its growth objectives through, among other things, future acquisitions, maintaining a high percentage of retail sales to residential customers, operating in attractive markets and focusing its operations under established, and locally recognized trade names.

In October 2005, we acquired Atlas Gas Products, Dowdle Gas, Inc., and Graeber Brothers Inc. and in January 2006, we purchased Propane Gas Service, Inc. Additionally, on March 31, 2006 and April 17, 2006, we acquired Delta Gas Company and Homestead Gas Company, respectively, both of which are located in Southern Florida. Acquisitions for the nine months ended June 30, 2006 had a total purchase price of $175.7 million, net of cash acquired. The operating results for these entities are included in our consolidated results of operations from the respective dates of acquisition.

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. As a result, operating income is highest during the period of October through March. 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. 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.

Three Months Ended June 30, 2006 Compared to Three Months Ended June 30, 2005

The following table summarizes the consolidated income statement components for the three months ending June 30, 2006 and 2005, respectively (dollars in thousands):


	Three Months Ended June 30,						Change
	2006			2005			In Dollars			Percentage
Revenue	$	215,618		$	173,602		$	42,016		24.2	%
Cost of product sold		150,241			122,998			27,243		22.1	%

Gross profit		65,377			50,604			14,773		29.2	%
Operating and administrative expenses		62,578			52,078			10,500		20.2	%
Depreciation and amortization		20,611			13,865			6,746		48.7	%

Operating loss		(17,812	)		(15,339	)		(2,473	)	(16.1	)%
Interest expense, net		(13,639	)		(9,144	)		(4,495	)	(49.2	)%
Loss on sale of property, plant and equipment		(1,712	)		(270	)		(1,442	)	(534.1	)%
Finance charges		741			576			165		28.6	%
Other		222			82			140		170.7	%

Loss before income taxes		(32,200	)		(24,095	)		(8,105	)	(33.6	)%
Provision for income taxes		165			24			141		587.5	%

Net loss	$	(32,365	)	$	(24,119	)	$	(8,246	)	(34.2	)%

The following table summarizes revenues, including associated volume of gallons sold, for the three months ending June 30, 2006 and 2005, respectively (dollars in millions):


	Revenues								Gallons
	Three Months Ended June 30,				Change				Three Months Ended June 30,		Change
	2006		2005		In Dollars		Percentage		2006	2005	In Units		Percentage
Retail propane	$	91.2	$	79.3	$	11.9	15.0	%	46.6	48.6	(2.0	)	(4.1	)%
Wholesale propane		52.5		48.2		4.3	8.9	%	53.8	57.3	(3.5	)	(6.1	)%
Other retail		33.2		26.7		6.5	24.3	%	—	—	—		—
Storage, fractionation, and midstream		38.7		19.4		19.3	99.5	%	—	—	—		—

Total		215.6		173.6		42.0	24.2	%	100.4	105.9	(5.5	)	(5.2	)%

Volume. During the three months ended June 30, 2006, we sold 46.6 million retail gallons of propane, a decrease of 2.0 million gallons or 4.1% from the 48.6 million retail gallons sold during the same three-month period in 2005. The decrease was principally due to customer conservation as a result of higher propane cost and the warmer weather experienced in the 2006 period. Weather was approximately 16% warmer in our comparable areas of operation in the three months ended June 30, 2006 as compared to the same period in 2005 and approximately 16% warmer than normal. The average cost of propane increased approximately 20.1% in the 2006 quarterly period over the same 2005 period. Offsetting the decrease in retail gallons sold was acquisition-related volume, which resulted in an increase of 6.9 million gallons quarter to quarter. Wholesale gallons delivered during the three months ended June 30, 2006 were 53.8 million gallons compared to 57.3 million gallons during the same three-month period in 2005.

Revenues. Revenues for the three months ended June 30, 2006 were $215.6 million, an increase of $42.0 million, or 24.2%, from $173.6 million during the same three-month period in 2005.

Revenues from retail propane sales were $91.2 million for the three months ended June 30, 2006, an increase of $11.9 million, or 15.0%, from $79.3 million from the same three-month period in 2005. This quarter over quarter increase was primarily the result of $12.5 million of acquisition-related sales together with an increase of approximately $15.9 million due to higher selling prices of propane, which was driven by the higher cost per gallon of propane. These revenue increases were partially offset by a $16.5 million decline in revenues as a result of lower retail volume sales at our existing locations as discussed above.

Revenues from wholesale propane sales were $52.5 million for the three months ended June 30, 2006, an increase of $4.3 million or 8.9%, from $48.2 million from the same three-month period in 2005. This increase was primarily the result of higher wholesale selling prices driven by the higher cost of propane. This increase was partially offset by a $4.1 million decline in revenues as a result of the lesser sales volume.

Revenues from other retail sales, primarily service, appliance, transportation, and distillates, were $33.2 million for the three months ended June 30, 2006, an increase of $6.5 million or 24.3% from $26.7 million during the same three-month period in 2005. This increase was primarily due to the recent acquisitions, which contributed approximately $4.4 million of this increase, and the balance of $2.1 million resulted from the higher selling price of distillates, partially offset by lesser volumes due primarily to customer conservation and warmer weather.

Revenues from storage, fractionation and other midstream activities were $38.7 million for the three months ended June 30, 2006, an increase of $19.3 million or 99.5% from $19.4 million during the same three-month period in 2005. Approximately $10.4 million of this increase was due to the acquisition of the Stagecoach natural gas storage facility, while the remaining $8.9 million of this increase was due to higher volumes and sales prices of natural gas, butane, and isobutane.

Cost of Product Sold. Retail propane cost of product sold for the three months ended June 30, 2006 was $50.9 million compared to $39.8 million during the same three-month period in 2005. This $11.1 million, or 27.9%, increase resulted from an approximate $7.4 million increase in acquisition-related volume, an approximate $13.0 million increase attributable to the higher average cost of propane, and an approximate $0.4 million increase due to non-cash charges from derivative contracts associated with retail propane fixed price sales contracts (as discussed below). These factors contributing to higher cost of product sold were partially offset by an approximate $9.7 million decline in cost of product sold resulting from lower retail volume sales at our existing locations as discussed above. The $0.4 million non-cash charge results primarily from the delivery of propane under contract to the retail customers and the decrease in the market price of propane in the three months ended June 30, 2006, since recognizing an approximate $19.4 million non-cash gain in the quarter ended September 30, 2005 on these derivative contracts.

Wholesale propane cost of product sold for the three months ended June 30, 2006 was $50.4 million, an increase of $4.0 million or 8.6%, from $46.4 million during the same three-month period in 2005. Contributing to these higher costs was an approximate $0.7 million increase due to acquisition-related volume and an approximate $7.2 million increase attributable to the higher average cost of propane, partially offset by an approximate $3.9 million decline as a result of lower volumes experienced in our wholesale propane operations (as discussed above).

Other retail cost of product sold was $20.4 million for the three months ended June 30, 2006, a decrease of $0.2 million from $20.6 million during the same three-month period in 2005.

Fractionation, storage, and other midstream cost of product sold was $28.5 million for the three months ended June 30, 2006, an increase of $12.3 million, or 75.9%, from $16.2 million during the same three-month period in 2005. Approximately $8.3 million of this increase was due to higher volumes and the higher cost of natural gas, butane, and isobutene at the West Coast NGL operations, and the remaining $4.0 million increase was primarily due to the acquisition of the Stagecoach natural gas storage facility.

Our cost of product sold consists primarily of tangible products sold including all propane, distillates and other natural gas liquids sold and all propane-related appliances sold. Other costs incurred in conjunction with the distribution of these products are included in operating and administrative expenses and consist primarily of wages to delivery personnel and delivery vehicle costs, including fuel costs, repair and maintenance and lease expense. These costs approximated $14.8 million and $12.4 million for the three months ended June 30, 2006 and 2005, respectively. In addition, depreciation expense associated with the delivery vehicles is reported within depreciation and amortization expense and amounted to $3.8 million and $3.0 million for the three months ended June 30, 2006 and 2005, respectively. Since we include these costs in our operating and administrative expenses rather than in cost of product sold, our results may not be comparable to other entities in our lines of business if they include these costs in cost of product sold.

Gross Profit. Retail propane gross profit was $40.3 million for the three months ended June 30, 2006 compared to $39.5 million in the same three-month period in 2005. This $0.8 million, or 2.0%, increase was attributable to higher retail gallons sold resulting from acquisitions, which accounted for an approximate $5.0 million increase in gross profit, as well as an increase in margin per gallon, which resulted in an additional $3.0 million increase. Margin per gallon increased primarily as a result of our ability to raise selling prices in certain markets in excess of our increased cost of propane. These factors contributing to a higher quarter over quarter gross profit were partially offset by an approximate $6.8 million reduction in retail propane gross profit at our existing locations as a result of lower volume sales discussed above. Additionally, the increase was reduced by the $0.4 million non-cash charge from derivative contracts as described above.

Wholesale propane gross profit was $2.1 million and $1.8 million for the three months ended June 30, 2006 and June 30, 2005, respectively. This slight increase was attributable to higher margins in the 2006 period partially offset by the lower volume sales.

Other retail gross profit increased $6.7 million, or 109.8%, to $12.8 million for the three months ended June 30, 2006 compared to $6.1 million in the same three-month period in 2005. This quarter over quarter increase was due primarily to higher distillate gross profit per gallon as well as appliance and service gross profit from acquisitions, partially offset by lesser distillate volume sales as described above.

Fractionation, storage, and other midstream gross profit was $10.2 million for the three months ended June 30, 2006 compared to $3.2 million in the same three-month period in 2005. This $7.0 million, or 218.8%, increase was due primarily to $6.3 million of acquisition-related volume as well as $0.7 million due to higher volumes and sales prices of natural gas, butane, and isobutane at the West Coast NGL operations.

Operating and Administrative Expenses. Operating and administrative expenses increased to $62.6 million for the three months ended June 30, 2006 compared to $52.1 million in the same three-month period in 2005. This $10.5 million increase was primarily attributable to higher personnel expenses, vehicle expenses and other facility costs of $5.7 million, $1.4 million and $3.8 million, respectively, partially offset by decreases in general operating expenses of $0.4 million arising from lower costs for insurance and professional services. Included in the personnel costs in the three months ended June 30, 2006 is $2.3 million of one-time bonuses related to the conversion of the subordinated units to common units. The additional net increase in operating expenses is partially the result of higher expenses arising from our fiscal 2006 acquisitions exceeding the savings realized from lesser volumes sold.

Depreciation and Amortization. Depreciation and amortization increased to $20.6 million for the three months ended June 30, 2006 from $13.9 million during the same three-month period in 2005, primarily as a result of a higher asset base due to retail propane acquisitions.

Interest Expense. Interest expense increased to $13.6 million for the three months ended June 30, 2006 compared to $9.1 million during the same three-month period in 2005, primarily due to an increase in the average debt outstanding associated with acquisitions and capital improvement projects, as well as higher average interest rates. During the three months ended June 30, 2006, the company capitalized $0.2 million of interest related to certain capital improvement projects mentioned above.

Net Income (loss). Net loss was $(32.4) million for the three months ended June 30, 2006 compared to the net loss of $(24.1) for the same three-month period in 2005. The increased net loss was attributable to higher operating and administrative expenses, depreciation and amortization, and interest expense, partially offset by the higher gross profit in the 2006 period. The increases in these expense related items were primarily attributable to acquisitions.

EBITDA and Adjusted EBITDA. EBITDA is defined as income before taxes, plus net interest expense (inclusive of write-off of deferred financing costs) and depreciation and amortization expense. For the three months ended June 30, 2006, EBITDA was $2.1 million compared to $(1.1) million during the same three-month period in 2005. This $3.2 million improvement in EBITDA was primarily attributable to net higher gross profit, which more than offset the increase in operating expenses in the 2006 period. As indicated in the table below, Adjusted EBITDA represents EBITDA excluding the $0.4 million non-cash charge on derivative contracts discussed above, the gain or loss on the sale of fixed assets and long-term incentive and equity compensation expenses. Adjusted EBITDA was $6.5 million for the three months ended June 30, 2006 compared to $(0.8) million for the three months ended June 30, 2005. EBITDA and Adjusted EBITDA should not be considered an alternative to net income, income before income taxes, cash flows from operating

activities, or any other measure of financial performance calculated in accordance with generally accepted accounting principles as those items are used to measure operating performance, liquidity or the ability to service debt obligations. We believe that EBITDA and Adjusted EBITDA provide additional information for evaluating our ability to make the minimum quarterly distribution and are presented solely as supplemental measures. EBITDA and Adjusted EBITDA, as we define them, may not be comparable to EBITDA and Adjusted EBITDA or similarly titled measures used by other corporations or partnerships.


	Three Months Ended June 30,
	2006			2005
	*(in thousands)*
EBITDA:
Net income (loss)	$	(32,365	)	$	(24,119	)
Interest expense, net		13,639			9,144
Provision for income taxes		165			24
Depreciation and amortization		20,611			13,865

EBITDA	$	2,050		$	(1,086	)

Non-cash charge on derivative contracts		434			—
Long-term incentive and equity compensation expense		2,334			—
Loss on sale of property, plant and equipment		1,712			270

Adjusted EBITDA	$	6,530		$	(816	)

Nine Months Ended June 30, 2006 Compared to Nine Months Ended June 30, 2005

The following table summarizes the consolidated income statement components for the nine months ending June 30, 2006 and 2005, respectively (dollars in thousands):


	Nine Months Ended June 30,						Change
	2006			2005			In Dollars			Percentage
Revenue	$	1,130,685		$	845,495		$	285,190		33.7	%
Cost of product sold		801,597			593,690			207,907		35.0	%

Gross profit		329,088			251,805			77,283		30.7	%
Operating and administrative expenses		188,688			146,055			42,633		29.2	%
Depreciation and amortization		58,673			35,094			23,579		67.2	%

Operating income		81,727			70,656			11,071		15.7	%
Interest expense, net		(41,063	)		(23,018	)		(18,045	)	(78.4	)%
Write-off of deferred financing costs		—			(6,990	)		6,990		100.0	%
Loss on sale of property, plant and equipment		(2,432	)		(170	)		(2,262	)	(1330.6	)%
Finance charges		2,176			1,488			688		46.2	%
Other		635			234			401		171.4	%

Income before income taxes		41,043			42,200			(1,157	)	(2.7	)%
Provision for income taxes		875			358			517		144.4	%

Net income	$	40,168		$	41,842		$	(1,674	)	(4.0	)%

The following table summarizes revenues, including associated volume of gallons sold, for the nine months ending June 30, 2006 and 2005, respectively (dollars in millions):


	Revenues								Gallons
	Nine Months Ended June 30,				Change				Nine Months Ended June 30,		Change
	2006		2005		In Dollars		Percentage		2006	2005	In Units		Percentage
Retail propane	$	603.1	$	443.7	$	159.4	35.9	%	310.5	269.7	40.8		15.1	%
Wholesale propane		284.9		264.5		20.4	7.7	%	296.0	325.9	(29.9	)	(9.2	)%
Other retail		133.9		95.6		38.3	40.1	%	—	—	—		—
Storage, fractionation, and midstream		108.8		41.7		67.1	160.9	%	—	—	—		—

Total	$	1,130.7	$	845.5	$	285.2	33.7	%	606.5	595.6	10.9		1.8	%

Volume. During the nine months ended June 30, 2006, we sold 310.5 million retail gallons of propane, an increase of 40.8 million gallons or 15.1% over the 269.7 million retail gallons sold during the same nine-month period in 2005. This period over period increase was principally due to acquisition-related volume, which resulted in higher gallons sales of approximately 90.2 million, including volume related to the acquisitions of Star Gas Propane, L.P. and Dowdle Gas, Inc., as well as the impact from the ten other retail propane companies for which results are only included in the 2005 and 2006 periods subsequent to the date of acquisition. Partially offsetting the increase from acquisition-related volume was a $49.4 million decline in gallons sold predominantly related to lower volume sales at existing locations due to warmer weather in the 2006 period and customer conservation as a result of higher propane cost. Weather was approximately 7% warmer in our comparable areas of operations in the nine months ended June 30, 2006 compared to the same nine-month period in 2005 and the average cost of propane was approximately 29.6% higher in the 2006 period.

Wholesale gallons delivered during the nine months ended June 30, 2006 were 296.0 million gallons compared to 325.9 million gallons during the same nine-month period in 2005, a decline of 29.9 million gallons arising primarily due to warmer weather during the nine months ended June 30, 2006 versus the comparable prior year period.

Revenues. Revenues for the nine months ended June 30, 2006 were $1,130.7 million, an increase of $285.2 million, or 33.7%, from $845.5 million during the same nine-month period in 2005.

Revenues from retail propane sales were $603.1 million for the nine months ended June 30, 2006, an increase of $159.4 million, or 35.9%, from $443.7 million during the same nine-month period in 2005. This period over period increase was primarily the result of $171.0 million of acquisition-related sales together with an increase of approximately $80.1 million due to higher selling prices of propane, which was driven by higher cost per gallon of propane. These factors contributing to higher retail propane revenues were partially offset by a $91.7 million decline in revenues as a result of lower retail volume sales at our existing locations as discussed above.

Revenues from wholesale propane sales were $284.9 million for the nine months ended June 30, 2006, an increase of $20.4 million or 7.7%, from $264.5 million during the same nine-month period in 2005. Approximately $49.2 million of this increase was attributable to the higher selling price resulting from the higher cost of propane, and approximately $5.2 million was attributable to acquisition-related volume. Offsetting these increases was a $34.0 decline in volume sales in our existing operations as discussed above.

Revenues from other retail sales, primarily service, appliance, transportation, and distillates, were $133.9 million for the nine months ended June 30, 2006, an increase of $38.3 million or 40.1% from $95.6 million during the same nine-month period in 2005. This increase was primarily due to acquisition-related volume, which contributed approximately $34.2 million of this increase, with the balance of $4.1 million predominantly related to the higher selling price of distillates.

Revenues from storage, fractionation and other midstream activities were $108.8 million for the nine months ended June 30, 2006, an increase of $67.1 million or 160.9% from $41.7 million during the same nine-month period in 2005. Approximately $35.0 million of this increase was due to higher volumes and sales prices of natural gas, butane, and isobutane with the remainder of the $32.1 million increase predominantly resulting from the acquisition of the Stagecoach natural gas storage facility.

Cost of Product Sold. Retail propane cost of product sold for the nine months ended June 30, 2006 was $361.8 million, an increase of $119.4 million or 49.3%, from $242.4 million during the same nine-month period in 2005. This increase resulted from several factors, including an approximate $99.4 million increase due to higher volume from acquisitions, an approximate $54.8 million increase attributable to the higher average cost of propane, and an approximate $19.6 million increase due to non-cash charges from derivative contracts associated with retail propane fixed price sales contracts. These factors contributing to a higher cost of product sold were partially offset by an approximate $54.4 million decline in cost of product sold as a result of lower retail volume sales at our existing locations as discussed above. The $19.6 million non-cash charge results primarily from the delivery of propane under contract to the retail customers and a decrease in the market price of propane in the nine months ended June 30, 2006, since recognizing an approximate $19.4 million non-cash gain in the quarter ended September 30, 2005 on these derivative contracts.

Wholesale propane cost of product sold for the nine months ended June 30, 2006 was $277.1 million, an increase of $17.3 million or 6.7%, from $259.8 million during the same nine-month period in 2005. Contributing to these higher costs was an approximate $45.3 million increase due to a higher average cost of product and an approximate $5.3 million increase from acquisition-related volume, partially offset by an approximate $33.3 million decline in cost of product sold as a result of lower volume sales as discussed above.

Other retail cost of product sold was $84.7 million for the nine months ended June 30, 2006, an increase of $25.0 million from $59.7 million during the same nine-month period in 2005. This increase was primarily due to acquisition-related volume.

Fractionation, storage, and other midstream cost of product sold was $78.0 million for the nine months ended June 30, 2006, an increase of $46.2 million, or 145.3%, from $31.8 million during the same nine-month period in 2005. Approximately $34.3 million of this increase was due to higher volumes and cost of natural gas, butane, and isobutane at the West Coast NGL operations with the remaining increase of $11.9 million predominantly due to acquisition-related volume from the Stagecoach natural gas storage facility.

Our cost of product sold consists primarily of tangible products sold including all propane, distillates and other natural gas liquids sold and all propane-related appliances sold. Other costs incurred in conjunction with the distribution of these products are included in operating and administrative expenses and consist primarily of wages to delivery personnel and delivery vehicle costs, including fuel costs, repair and maintenance and lease expense. These costs approximated $48.7 million and $32.1 million for the nine months ended June 30, 2006 and 2005, respectively. In addition, depreciation expense associated with the delivery vehicles is reported within depreciation and amortization expense and amounted to $11.3 million and $7.6 million for the nine months ended June 30, 2006 and 2005, respectively. Since we include these costs in our operating and administrative expenses rather than in cost of product sold, our results may not be comparable to other entities in our lines of business if they include these costs in cost of product sold.

Gross Profit. Retail propane gross profit was $241.3 million for the nine months ended June 30, 2006 compared to $201.3 million in the same nine-month period in 2005. This $40.0 million, or 19.8%, increase was primarily attributable to higher retail gallons sold resulting from acquisitions, which accounted for

approximately $71.6 million of the increase. Also contributing $25.3 million to the increase was a higher margin per gallon, which resulted primarily from our ability to increase selling prices in certain markets in excess of our increased cost of propane. These factors contributing to a higher period over period gross profit were partially offset by an approximate $37.3 million reduction in retail propane gross profit at our existing locations as a result of lower volume sales discussed above, as well as by the $19.6 million non-cash charge from derivative contracts as described above.

Wholesale propane gross profit was $7.8 million for the nine months ended June 30, 2006 compared to $4.7 million in the same nine-month period in 2005, an increase of $3.1 million or 66.0%. Approximately $3.9 million of this increase resulted from increased margin per gallon from our existing business. This increase was partially offset by an approximate $0.8 million reduction in wholesale propane gross profit at our existing locations as a result of lower volume sales discussed above.

Other retail gross profit was $49.2 million for the nine months ended June 30, 2006 compared to $35.9 million in the same nine-month period in 2005, an increase of $13.3 million or 37.0%. This period over period increase was primarily acquisition-related and included service, appliance and distillate gross profits as well as the higher selling price of distillates.

Fractionation, storage, and other midstream gross profit was $30.8 million for the nine months ended June 30, 2006 compared to $9.9 million in the same nine-month period in 2005, an increase of $20.9 million, or 211.1%. Approximately $20.2 million of this increase was acquisition-related with the balance due to volume and margin increases in our existing business.

Operating and Administrative Expenses. Operating and administrative expenses increased to $188.7 million for the nine months ended June 30, 2006 compared to $146.1 million in the same nine-month period in 2005. The higher operating and administrative expenses was primarily attributable to an increase in personnel expenses of $24.6 million, higher general operating expenses of $10.9 million, including insurance, professional services and facility costs, and increased vehicle costs of $7.1 million. Included in the personnel costs for the nine months ended June 30, 2006 is $2.3 million of one-time bonuses related to the conversion of the subordinated units to common units. These higher costs were driven primarily from acquisitions and were partially offset by integration efficiencies and lesser variable expenses as a result of lesser volumes at existing locations.

Depreciation and Amortization. Depreciation and amortization increased to $58.7 million for the nine months ended June 30, 2006 from $35.1 million during the same nine-month period in 2005, primarily as a result of retail propane acquisitions.

Interest Expense. Interest expense increased to $41.1 million for the nine months ended June 30, 2006 from $23.0 million during the same nine-month period in 2005, primarily due to an increase in the average debt outstanding, including the additional financing related to acquisitions and capital improvement projects, as well as higher average interest rates. During the nine months ended June 30, 2006, the company capitalized $0.2 million of interest related to certain capital improvement projects mentioned above.

Write-off of Deferred Financing Costs. A charge of $7.0 million was recorded during the nine-month period ended June 30, 2005 as a result of the write-off of the deferred financing costs associated with the repayment of the previously existing credit agreement and the 364-day facility. No such charge was recorded during the nine months ended June 30, 2006.

Net Income. Net income was $40.2 million for the nine months ended June 30, 2006 compared to net income of $41.8 for the same nine-month period in 2005. The decrease in net income was attributable to higher operating and administrative expenses, depreciation and amortization, and interest expense partially offset by the higher gross profit in the 2006 period. The increases in these expense related items were primarily attributable to acquisitions.

EBITDA and Adjusted EBITDA. For the nine months ended June 30, 2006, EBITDA was $140.8 million compared to $107.3 million during the same nine-month period in 2005. The $33.5 million increase in EBITDA was primarily attributable to higher gross profit from net increased retail sales volumes due to acquisitions and higher gross profit per gallon, partially offset by the $19.6 million non-cash charge from derivative contracts discussed above and increases in operating and administrative expenses. As indicated in the table below, Adjusted EBITDA represents EBITDA excluding the $19.6 million non-cash charge on derivative contracts, long-term incentive and equity compensation expense and the gain or loss on the sale of fixed assets. Adjusted EBITDA was $165.3 million for the nine months ended June 30, 2006 compared to $107.5 million for the nine months ended June 30, 2005, an increase of $57.8 million. 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.


	Nine Months Ended June 30,
	2006		2005
	*(in thousands)*
EBITDA:
Net income	$	40,168	$	41,842
Interest expense, net		41,063		23,018
Write off of deferred financing costs		—		6,990
Provision for income taxes		875		358
Depreciation and amortization		58,673		35,094

EBITDA	$	140,779	$	107,302

Non-cash charge on derivative contracts		19,643		—
Loss on sale of property, plant and equipment		2,432		170
Long-term incentive and equity compensation expense		2,445		—

Adjusted EBITDA	$	165,299	$	107,472

Liquidity and Sources of Capital

Net operating cash inflows were $112.0 million and $80.0 million for the nine-month periods ending June 30, 2006 and 2005, respectively. The $32.0 million increase in operating cash flows was primarily attributable to the increase in net non-cash charges and net changes in working capital balances.

Net investing cash outflows were $189.0 million and $611.6 million for the nine-month periods ending June 30, 2006 and 2005, respectively. Net cash outflows were primarily impacted by a $411.8 million decrease in cash outlays related to acquisitions, a $5.2 million period to period decrease in capital expenditures and a $5.6 increase in proceeds received from the sale of property, plant and equipment.

Net financing cash inflows were $113.6 million and $550.4 million for the nine-month periods ending June 30, 2006 and 2005, respectively. Net cash inflows were primarily impacted by a $322.5 million period to period decrease in proceeds from the issuance of long-term debt, net of payments on long-term debt, and a $102.4 million decrease in proceeds from the issuance of common units.

In October 2005, the underwriters of a September 2005 6,500,000 common unit offering exercised a portion of their over-allotment provision and Inergy issued an additional 900,000 common units in a follow-on offering, resulting in proceeds of approximately $24.7 million, net of underwriters’ discounts, commissions, and offering expenses. These funds were used to repay borrowings under the credit agreement.

On January 11, 2006, Inergy and its wholly owned subsidiary Inergy Finance Corporation issued $200 million aggregate principal amount of 8.25% senior unsecured notes due 2016 in a private placement to eligible purchasers. The senior unsecured notes contain covenants similar to our existing senior unsecured notes due 2014. Inergy used the net proceeds of the offering to repay outstanding indebtedness under its revolving acquisition credit facility. The notes represent senior unsecured obligations of Inergy and rank pari passu in right of payment with all other present and future senior indebtedness of Inergy. The senior unsecured notes are jointly and severally guaranteed by all of Inergy’s current domestic subsidiaries. The notes have certain call features which allow Inergy to redeem the notes at specified prices based on date redeemed. On May 18, 2006, Inergy completed an offer to exchange its existing 8.25% Senior Unsecured Notes due 2016 for $200 million of 8.25% senior notes due 2016 (the “2016 Exchange Notes”) that are registered and do not carry transfer restrictions, registration rights and provisions for additional interest. The 2016 Exchange Notes did not provide Inergy with any additional proceeds and satisfied Inergy’s obligations under the registration rights agreement.

On March 23, 2006, our shelf registration statement (File No. 333-132287) was declared effective by the Securities and Exchange Commission for the periodic sale by us of up to $1.0 billion of common units, partnership securities and debt securities, or any combination thereof. Pursuant to the shelf registration statement, we are permitted to issue these securities from time to time for general business purposes, including debt repayment, future acquisitions, capital expenditures and working capital, or for other potential uses identified in a prospectus supplement.

In June 2006, Inergy issued 4,312,500 common units, under the shelf registration statement, in a public offering, which included 562,500 common units issued as result of the underwriters exercising their over-allotment provision. The issuance of these common units resulted in net proceeds of $103 million, after deducting underwriters’ discounts, commissions and other offering expenses. These proceeds were partially used to repay indebtedness under Inergy’s Credit Agreement with the remainder to be used to fund capital expenditures made in connection with internal growth projects related to Inergy’s midstream assets discussed below.

We have identified internal growth projects related to our Stagecoach and West Coast NGL midstream assets that are expected to require a capital investment of approximately $225 million to complete. These projects include expansion of our Stagecoach natural gas storage facility, which is expected to increase our working storage capacity of natural gas to approximately 26.6 Bcf through the addition of approximately 13 Bcf of storage to our existing 13.6 Bcf working storage capacity. This expansion is expected to be in service by the fall of 2007, subject to the approval by the Federal Energy Regulatory Commission (FERC). Stagecoach is also expected to construct pipelines that will connect us to certain strategic existing or proposed pipelines, which we believe will enhance and further diversify our supply sources. The West Coast project consists of the construction of a butane isomerization unit and related ancillary facilities, as well as the expansion of butane storage capacity. The isomerization unit is projected to have a capacity of 10,000 barrels per day and provide isobutane supplies to refiners or wholesale distributors for gasoline blending. This project is subject to regulatory approval by state and county agencies and is expected to be in service by January 2008.

The following table summarizes the aggregate amounts to be paid on our long-term debt and operating lease obligations during the next five years ending June 30 and thereafter (in thousands):


	2007		2008		2009		2010		2011		Thereafter		Total
Aggregate amount of principal and interest to be paid on the outstanding long-term debt (a)	$	51,036	$	50,214	$	48,625	$	47,770	$	47,332	$	806,659	$	1,051,636
Future minimum lease payments under noncancelable operating leases	$	6,664	$	5,620	$	4,203	$	2,664	$	1,453	$	3,301	$	23,905
Standby letters of credit	$	20,928	$	3,671	$	500	$	—	$	190	$	—	$	25,289
Fixed price purchase commitments	$	223,282	$	—	$	—	$	—	$	—	$	—	$	223,282

(a)	$100 million of our long-term debt is variable interest rate debt at prime rate or LIBOR plus an applicable spread. These rates plus their applicable spreads were between 6.61% and 8.50% at June 30, 2006. These rates have been applied for each period presented in the table.

We believe that anticipated cash from operations and borrowings under existing credit agreements will be sufficient to meet our liquidity needs for the foreseeable future. If our plans or assumptions change or are inaccurate, or we make any acquisitions, we may need to raise additional capital. We may not be able to raise additional funds or may not be able to raise such funds on favorable terms.

Seasonality

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.

Description of Credit Facility

Inergy maintains 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 interest rates between 6.61% and 8.50% at June 30, 2006. At June 30, 2006, there were no borrowings outstanding under the Credit Agreement for either the Working Capital Facility or the Acquisition Facility. In January 2006, we issued $200 million aggregate principal amount of 8.25% senior unsecured notes due 2016 in a private placement to eligible purchasers and used the net proceeds to repay outstanding indebtedness under the Acquisition Facility.

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

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

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Interest Rate Risk

We have long-term debt and a revolving line of credit subject to the risk of loss associated with movements in interest rates. At June 30, 2006, we had floating rate obligations totaling $100 million as a result of interest rate swap agreements as discussed below.

To manage interest rate risk exposure, during the quarter ending March 2005 we entered into four interest rate swap agreements scheduled to mature in December 2014, each designed to hedge $25 million in underlying fixed rate senior unsecured notes. These swap agreements, which expire on the same date as the maturity date of the related senior unsecured notes and contain call provisions consistent with the underlying senior unsecured notes, require the counterparty to pay us an amount based on the stated fixed interest rate on the notes due every six months. In exchange, we are required to make semi-annual floating interest rate payments on the same dates to the counterparty based on an annual interest rate equal to the 6 month LIBOR interest rate plus spreads between 1.95% and 2.20% applied to the same notional amount of $100 million. The swap agreements have been recognized as fair value hedges. Amounts to be received or paid under the agreements are accrued and recognized over the life of the agreements as an adjustment to interest expense. During the nine months ended June 30, 2006, the Company recognized an approximate $5.5 million decrease 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 liabilities. The fair value of the interest rate swaps was $7.1 million at June 30, 2006.

If the floating rate were to fluctuate by 100 basis points from June 2006 levels, our interest expense would change by a total of approximately $1.0 million per year.

Commodity Price, Market and Credit Risk

Inherent in our contractual portfolio are certain business risks, including market risk and credit risk. Market risk is the risk that the value of the portfolio will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by suppliers, customers or financial counterparties to a contract. We take an active role in managing and controlling market and credit risk and have established control procedures, which are reviewed on an ongoing basis. We monitor market risk through a variety of techniques, including daily reporting of the portfolio’s position to senior management. Inergy provides for such risks at the time derivative financial instruments are adjusted to fair value and when specific risks become known. We attempt to minimize credit risk exposure through credit policies and periodic monitoring procedures as well as through customer deposits and letters of credit, as deemed appropriate. The counterparties associated with assets from price risk management activities as of June 30, 2006 and 2005 were propane retailers, resellers, energy marketers and dealers.

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

We engage in hedging transactions, including various types of forward contracts, options, swaps and futures contracts, to reduce the effect of price volatility on our product costs, protect the value of our inventory

positions, and to help ensure the availability of propane during periods of short supply. We attempt to balance our contractual portfolio by purchasing volumes only when we have a matching purchase commitment from our wholesale customers. However, we may experience net unbalanced positions from time to time which we believe to be immaterial in amount. In addition to our ongoing policy to maintain a balanced position, for accounting purposes we are required, on an ongoing basis, to track and report the market value of our purchase obligations and our sales commitments.

Notional Amounts and Terms

The notional amounts and terms of these financial instruments as of June 30, 2006 include fixed price payor for 5.4 million barrels of propane and heating oil and 1.7 million MMBTUs of natural gas, and fixed price receiver for 4.2 million barrels of propane and heating oil and 1.7 million MMBTUs of natural gas. The notional amounts and terms as of September 30, 2005 include fixed price payor for 11.0 million barrels of propane and heating oil and 1.9 millions MMBTUs of natural gas, and fixed price receiver for 12.7 million barrels of propane and heating oil and 1.9 million MMBTUs of natural gas. Notional amounts reflect the volume of transactions, but do not represent the amounts exchanged by the parties to the financial instruments. Accordingly, notional amounts do not accurately measure our exposure to market or credit risks.

Fair Value

The fair value of the derivatives and inventory exchange contracts related to price risk management activities as of June 30, 2006 and September 30, 2005 was assets of $31.2 million and $58.4 million, respectively, and liabilities of $22.8 million and $49.6 million, respectively. All intercompany transactions have been appropriately eliminated. The market prices used to value these transactions reflect management’s best estimate considering various factors including closing exchange and over-the-counter quotations, recent transactions, time value and volatility factors underlying the commitments.

The following table summarizes the change in the unrealized fair value of energy contracts related to our risk management activities for the nine months ended June 30, 2006 and the same nine-month period in 2005 where settlement has not yet occurred (in thousands):


	Nine Months Ended June 30,
	2006			2005
Net fair value gain (loss) of contracts outstanding at beginning of period	$	8,784		$	(6,626	)
Net unrealized gain acquired through acquisition during the period		—			1,881
Net change in physical exchange contracts		2,454			(4,904	)
Change in fair value of contracts attributable to market movement during the year		2,080			14,531
Realized (gains)		(4,903	)		(2,655	)

Net fair value of contracts outstanding at end of period	$	8,415		$	2,227

Of the outstanding fair value as of June 30, 2006, nearly all contracts had a maturity of one year or less.

Sensitivity Analysis

A theoretical change of 10% in the underlying commodity value would result in a change of approximately $0.1 million in the market value of the contracts as there were approximately 0.9 million gallons of net unbalanced positions at June 30, 2006.

Item 4. Controls and Procedures

We maintain controls and procedures designed to ensure that information required to be disclosed in our reports that are filed or submitted under the Securities Exchange Act of 1934 is 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 the Company’s 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 the Company’s disclosure controls and procedures were adequate and effective as of June 30, 2006. There have been no changes in the Company’s internal controls over financial reporting (as defined in Rule 13(e)-15 or Rule 15d-15(f) of the Exchange Act) or in other factors during the fiscal quarter covered by this report that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II – OTHER INFORMATION

Item 1. Legal Proceedings

Part I, Item 1. Financial Statements, Note 6 to the Consolidated Financial Statements of this Form 10Q is hereby incorporated herein by reference.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

None.

Item 3. Defaults Upon Senior Securities

None.

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

None.

Item 5. Other Information

None.

Item 6. Exhibits


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.

SIGNATURE

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.


	INERGY, L.P.

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

Date: August 9, 2006	By:	/s/ R. Brooks Sherman, Jr.
		R. Brooks Sherman, Jr.
		Senior Vice President and Chief Financial Officer
		(Principal Financial Officer and Principal Accounting Officer)

Section 302 CEO Certification

Exhibit 31.1

CERTIFICATIONS

I, John J. Sherman, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Inergy, L.P. (the “registrant”);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over the financial reporting (as defined in Exchange Act Rules 13a-15(f)) for the registrant and have:

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared:

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

Evaluated the effectiveness of the registrant’s disclosure controls and procedures and present in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: August 9, 2006

/s/ John J. Sherman

John J. Sherman

President and Chief Executive Officer

Section 302 CFO Certification

Exhibit 31.2

CERTIFICATIONS

I, R. Brooks Sherman, Jr., certify that:

1. I have reviewed this quarterly report on Form 10-Q of Inergy, L.P. (the “registrant”);

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: August 9, 2006

/s/ R. Brooks Sherman, Jr.

R. Brooks Sherman, Jr.

Senior Vice President and Chief Financial Officer

Section 906 CEO Certification

Exhibit 32.1

Certification of the Chief Executive Officer

Pursuant to 18 U.S.C. Section 1350

As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the Quarterly Report of Inergy, L.P. (the “Company”) on Form 10-Q for the period ended June 30, 2006 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, John J. Sherman, Chief Executive Officer of Inergy, L.P., certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1)

The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)

The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ John J. Sherman

John J. Sherman

Chief Executive Officer

August 9, 2006

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

Section 906 CFO Certification

Exhibit 32.2

Certification of the Chief Executive Officer

Pursuant to 18 U.S.C. Section 1350

As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the Quarterly Report of Inergy, L.P. (the “Company”) on Form 10-Q for the period ended June 30, 2006 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, R. Brooks Sherman, Jr., Chief Financial Officer of Inergy, L.P., certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1)

The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)

The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ R. Brooks Sherman, Jr.

R. Brooks Sherman, Jr.

Chief Financial Officer

August 9, 2006

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