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, 2003

OR

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

For the transition period from              to             .

COMMISSION FILE NUMBER: 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 last 90 days.    Yes  x    No  ¨

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

The following units were outstanding at August 1, 2003:

Common Units	5,522,411
Senior Subordinated Units	3,567,626
Junior Subordinated Units	572,542

INERGY, L.P.

INDEX TO FORM 10-Q

	Page
Part I – Financial Information
Item 1 – Financial Statements of Inergy, L.P.:
Consolidated Balance Sheets as of June 30, 2003 (unaudited) and September 30, 2002 (audited)	3
Unaudited Consolidated Statements of Operations for the Three and Nine Months Ended June 30, 2003 and 2002	5
Unaudited Consolidated Statement of Partners’ Capital for the Nine Months Ended June 30, 2003	6
Unaudited Consolidated Statements of Cash Flows for the Nine Months Ended June 30, 2003 and 2002	7
Unaudited Notes to Consolidated Financial Statements	9
Item 2 – Management’s Discussion and Analysis of Financial Condition and Results of Operation	19
Item 3 – Quantitative and Qualitative Disclosures About Market Risk	29
Item 4 – Controls and Procedures	31
Part II – Other Information
Item 1 – Legal Proceedings	32
Item 2 – Changes in Securities and Use of Proceeds	32
Item 3 – Defaults Upon Senior Securities	32
Item 4 – Submission of Matters to a Vote of Security Holders	32
Item 5 – Other Information	32
Item 6 – Exhibits and Reports on Form 8-K	32
Signatures	33

2

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

INERGY, L.P. AND SUBSIDIARY

CONSOLIDATED BALANCE SHEETS

	June 30, 2003			September 30, 2002
	(Unaudited)
	(In Thousands)
Assets
Current assets:
Cash	$	2,066		$	2,088
Accounts receivable, less allowance for doubtful accounts of $1,222,000 and $927,000 at June 30, 2003 and September 30, 2002, respectively		18,957			13,112
Inventories		19,096			41,162
Prepaid expenses and other current assets		2,308			3,929
Assets from price risk management activities		6,265			9,725
Total current assets		48,692			70,016
Property, plant and equipment, at cost		155,407			137,902
Less accumulated depreciation		(20,027	)		(13,352	)
Property, plant and equipment, net		135,380			124,550
Intangible assets		109,221			101,591
Less accumulated amortization		(12,967	)		(8,941	)
Intangible assets, net		96,254			92,650
Other		2,393			1,016
Total assets	$	282,719		$	288,232

3

INERGY, L.P. AND SUBSIDIARY

CONSOLIDATED BALANCE SHEETS (continued)

	June 30, 2003		September 30, 2002
	(Unaudited)
	(In Thousands)
Liabilities and partners’ capital
Current liabilities:
Accounts payable	$	12,144	$	13,364
Accrued expenses		7,941		6,394
Customer deposits		3,386		8,718
Liabilities from price risk management activities		6,442		14,378
Current portion of long-term debt		3,637		19,367
Total current liabilities		33,550		62,221
Long-term debt, less current portion		103,081		105,095
Partners’ capital:
Common unitholders (4,632,505 and 3,828,877 units issued and outstanding as of June 30, 2003 and September 30, 2002, respectively)		100,935		76,762
Senior subordinated unitholders (3,313,367 units issued and outstanding)		41,860		41,292
Junior subordinated unitholders (572,542 units issued and outstanding)		705		607
Non-managing general partner (2% interest with 173,845 and 157,445 equivalent units outstanding as of June 30, 2003 and September 30, 2002, respectively)		2,588		2,255
Total partners’ capital		146,088		120,916
Total liabilities and partners’ capital	$	282,719	$	288,232

See accompanying notes.

4

INERGY, L.P. AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF OPERATIONS

(In Thousands, Except Per Unit Data)

(unaudited)

	Three Months  Ended June 30,						Nine Months  Ended June 30,
	2003			2002			2003			2002
Revenue:
Propane	$	35,331		$	32,937		$	292,823		$	158,082
Other		4,150			3,761			14,998			11,433
		39,481			36,698			307,821			169,515
Cost of product sold		28,344			24,536			227,360			107,079
Gross profit		11,137			12,162			80,461			62,436
Expenses:
Operating and administrative		12,127			11,898			44,159			35,225
Depreciation and amortization		3,362			3,174			10,097			8,319
Operating income (loss)		(4,352	)		(2,910	)		26,205			18,892
Other income (expense):
Interest expense		(2,263	)		(2,318	)		(7,399	)		(5,555	)
Loss on sale of property, plant and equipment		(96	)		(109	)		(86	)		(228	)
Interest expense related to write-off of deferred financing costs		—			(585	)		—			(585	)
Finance charges		147			29			236			114
Other		48			13			99			50
Income (loss) before income taxes		(6,516	)		(5,880	)		19,055			12,688
Provision for income taxes		32			30			102			82
Net income (loss)	$	(6,548	)	$	(5,910	)	$	18,953		$	12,606
Partners’ interest information for the three and nine months ended June 30, 2003 and 2002:
Non-managing general partners’ interest in net income (loss)	$	(131	)	$	(118	)	$	379		$	252
Limited partners’ interest in net income (loss):
Common unit interest	$	(3,489	)	$	(2,374	)	$	9,576		$	4,738
Senior subordinated unit interest		(2,497	)		(2,914	)		7,672			6,494
Junior subordinated unit interest		(431	)		(504	)		1,326			1,122
Total limited partners’ interest in net income (loss)	$	(6,417	)	$	(5,792	)	$	18,574		$	12,354
Net income (loss) per limited partner unit:
Basic	$	(0.75	)	$	(0.88	)	$	2.32		$	1.96
Diluted	$	(0.75	)	$	(0.88	)	$	2.28		$	1.93
Weighted average limited partners’ units outstanding:
Basic		8,516			6,585			8,022			6,303
Diluted		8,516			6,585			8,138			6,402

See accompanying notes.

5

INERGY, L.P. AND SUBSIDIARY

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			Total Partners’ Capital
Balance at September 30, 2002	$	76,762		$	41,292		$	607		$	2,255		$	120,916
Net proceeds from issuance of common units		23,350			—			—			—			23,350
Common units issued in acquisition of retail propane company		100			—			—			—			100
Contribution from non-managing general partner		—			—			—			511			511
Return and cancellation of common units originally issued in the IPC acquisition		(62	)		—			—			(1	)		(63	)
Distributions		(8,794	)		(7,107	)		(1,228	)		(556	)		(17,685	)
Net income		9,576			7,672			1,326			379			18,953
Foreign currency translation		3			3			—			—			6
Balance at June 30, 2003	$	100,935		$	41,860		$	705		$	2,588		$	146,088

See accompanying notes.

6

INERGY, L.P. AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In Thousands)

(unaudited)

	Nine Months Ended June 30,
	2003			2002
Operating activities
Net income	$	18,953		$	12,606
Adjustments to reconcile net income to net cash provided by operating activities:
Provision for doubtful accounts		619			937
Depreciation		7,116			5,882
Amortization		2,981			2,437
Amortization of deferred financing costs		1,045			909
Interest expense related to write-off of deferred financing costs		—			585
Loss on disposal of property, plant and equipment		86			228
Net asset/liabilities from price risk management activities		(4,476	)		1,837
Changes in operating assets and liabilities, net of effects from acquisitions of retail propane companies:
Accounts receivable		(5,651	)		3,715
Inventories		22,391			(11,361	)
Prepaid expenses and other current assets		1,594			(2,008	)
Other assets		(4	)		—
Accounts payable		(2,340	)		9,736
Accrued expenses		984			(2,593	)
Customer deposits		(5,349	)		(4,481	)
Net cash provided by operating activities		37,949			18,429
Investing activities
Acquisition of retail propane companies, net of cash acquired		(19,804	)		(83,531	)
Purchases of property, plant and equipment		(3,902	)		(4,424	)
Deferred financing and acquisition costs incurred		(577	)		(3,696	)
Proceeds from sale of property, plant and equipment		490			209
Other		—			20
Net cash used in investing activities		(23,793	)		(91,422	)

7

INERGY, L.P. AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In Thousands)

(unaudited)

	Nine Months Ended June 30,
	2003			2002
Financing activities
Proceeds from issuance of long-term debt	$	102,995		$	370,101
Principal payments on long-term debt and noncompete obligations		(123,355	)		(319,444	)
Contribution from non-managing general partner		511			880
Net proceeds from issuance of common units		23,350			31,216
Distributions		(17,685	)		(10,865	)
Net cash provided by (used in) financing activities		(14,184	)		71,888
Effect of foreign exchange rate changes on cash		6			—
Net decrease in cash		(22	)		(1,105	)
Cash at beginning of period		2,088			2,171
Cash at end of period	$	2,066		$	1,066
Supplemental disclosure of cash flow information
Cash paid during the period for interest	$	6,531		$	4,322
Supplemental schedule of noncash investing and financing activities
Acquisition of retail propane company through the issuance of common units	$	100		$	19,723
Increase in the fair value of senior secured notes and the related interest rate swap	$	1,373		$	—

See accompanying notes.

8

INERGY, L.P. AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1 – Organization and Basis of Presentation

Organization

The consolidated financial statements of Inergy, L.P. (the “Company”) include the accounts of the Company and its subsidiary Inergy Propane, LLC which, collectively, are referred to as “Inergy.” Inergy Partners, LLC (the “Non-Managing General Partner”), an affiliate of Inergy Holdings, LLC (“Holdings”), owns the Non-Managing General Partner interest representing a 2% unsubordinated general partner’s interest in the Company. Inergy GP, LLC, (the “Managing General Partner”), a wholly owned subsidiary of Holdings, has sole responsibility for conducting our business and managing our 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.

Basis of Presentation

The financial information as of June 30, 2003 and for the three-month and nine-month periods ended June 30, 2003 and 2002 contained herein 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 results of operations for the three-month and nine-month periods ended June 30, 2003 and 2002 are not indicative of the results of operations that may be expected for the entire year.

The accompanying 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/A as filed with the Securities and Exchange Commission for the year ended September 30, 2002.

9

INERGY, L.P. AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 2 – Accounting Policies Update

Financial Instruments and Price Risk Management

Inergy, through its wholesale operations, sells propane to various propane users, retailers, and resellers and offers price risk management services to these customers as part of its marketing and distribution operations. Inergy’s wholesale operations also sell propane to energy marketers and dealers. Derivative financial instruments utilized in connection with these activities are accounted for using the mark-to-market method in accordance with Statement of Financial Accounting Standards (SFAS) No. 133, “Accounting for Derivative Instruments and Hedging Activities,” and Emerging Issues Task Force Issue (“EITF”) No. 02-3, “Issues Involved in Accounting for Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities,” as discussed below and, prior to its October 2002 rescission effective for periods beginning after December 15, 2002, EITF No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities.” Inergy’s overall objective for entering into such derivative financial instruments, including those designated as fair value hedges of Inergy’s inventory positions, is to manage its exposure to fluctuations in commodity prices and changes in the fair market value of inventories.

SFAS No. 133 requires recognition of all derivative instruments in the balance sheets and measures them at fair value. If a derivative does not qualify for hedge accounting, it must be adjusted to fair value through earnings. Beginning in December 2002, certain of Inergy’s commodity derivative financial instruments have been designated as hedges of selected inventory positions, and qualify as fair value hedges, as defined in SFAS No. 133. For derivative instruments designated as hedges, Inergy formally assesses, both at the hedge contract’s inception and on an ongoing basis, whether the hedge contract is highly effective in offsetting changes in fair value of hedged items. Changes in the fair value of derivative instruments designated as fair value hedges are reported in the balance sheet as price risk management assets or liabilities. The ineffective portions of hedging derivatives are recognized immediately in cost of product sold. At June 30, 2003, the fair value of approximately 17.8 million gallons of propane inventory was being hedged by various commodity derivatives with a fair value of $1,019,000 recorded as a liability from price risk management activities in accordance with Inergy’s hedging strategies. Changes in the fair value of derivative instruments that are not designated as hedges are recorded in current period earnings in accordance with SFAS No. 133.

During the three and nine months ended June 30, 2003, the Company recognized net gains of $65,000 and $138,000, respectively, related to the ineffective portion of its hedging instruments and a net gain of $86,000 and a net loss of $212,000, respectively, related to the portion of the hedging instruments the Company excluded from its assessment of hedge effectiveness.

10

INERGY, L.P. AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 2 – Accounting Policies Update (continued)

The June 2002 consensus reached on EITF No. 02-3 codifies and reconciles existing guidance on the recognition and reporting of gains and losses on energy trading contracts and addresses other aspects of the accounting for contracts involved in energy trading and risk management activities. Among other things, the consensus requires that mark-to-market gains and losses on energy trading contracts should be shown net in the income statement, irrespective of whether the contract is physically settled. This presentation was effective for financial statements issued for periods ending after July 15, 2002. As such, Inergy has reclassified all settled transactions that meet the definition of trading activities net in the income statement to conform to the new presentation required under EITF No. 02-3. Inergy previously reported these transactions when settled in the income statement at their gross amounts in revenues and cost of product sold. The reclassified amounts for the three months and nine months ended June 30, 2002 were $21.3 million and $52.5 million, respectively. This required reclassification has no impact on previously reported gross profit, net income or cash provided by operating activities. Inergy physically delivered approximately 29.0 million and 49.6 million gallons related to transactions considered trading activities as defined by EITF No. 02-3 for the three months ended June 30, 2003 and 2002, respectively, and 227.6 million and 133.9 million gallons for the nine months ended June 30, 2003 and 2002, respectively.

In October 2002, the EITF reached a consensus in EITF No. 02-3 to rescind EITF No. 98-10, the basis for mark-to-market accounting used for recording energy trading activities by many companies, including Inergy. The October 2002 EITF consensus requires that all new energy-related contracts entered into subsequent to October 25, 2002 should not be accounted for pursuant to EITF No. 98-10. Instead, those contracts should be accounted for under accrual accounting and would not qualify for mark-to-market accounting unless the contracts meet the requirements stated under SFAS No. 133. The October 2002 EITF consensus also provides that inventory will no longer be accounted for using mark-to-market accounting and must be accounted for at the lower of cost or market. As noted above, Inergy has elected to use the special hedge accounting rules in SFAS No. 133 and hedge the fair value of certain of its inventory positions, whereby the hedged inventory and the related derivative instruments are both marked to market. Inventories purchased under energy contracts subsequent to October 25, 2002, and not otherwise designated as being hedged, as discussed above, are carried at the lower-of-cost or market effective January 1, 2003.

The effective date for the full rescission of EITF No. 98-10 is for fiscal periods beginning after December 15, 2002. The effect of the rescission of EITF No. 98-10 did not have a material impact on Inergy’s financial position or results of operations.

11

INERGY, L.P. AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 2 – Accounting Policies Update (continued)

The consensus reached in EITF No. 02-3 rescinding Issue 98-10 requires all derivatives held for trading purposes to be reported on a net basis in the income statement regardless of whether these derivatives are settled physically. These netting requirements are also effective for fiscal periods beginning after December 15, 2002 and have been adopted, as discussed above.

Revenue Recognition

Sales of propane are recognized at the time product is shipped or delivered to the customer. 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.

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 liquid propane, are stated at the lower of cost, determined using the average-cost method, or market. Inventories for wholesale operations, which consist mainly of liquid propane commodities, are stated at market, except for inventories purchased under energy contracts subsequent to October 25, 2002, which are stated at the lower of cost or market unless hedged, as discussed above.

Inventories consist of (in thousands):

	June 30, 2003		September 30, 2002
Propane gas and other liquids	$	15,711	$	37,934
Appliances, parts and supplies		3,385		3,228
	$	19,096	$	41,162

12

INERGY, L.P. AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 2 – Accounting Policies Update (continued)

Income (loss) Per Unit

Basic net income (loss) per limited partner unit is computed by dividing net income (loss), after considering the Non-Managing General Partner’s interest, by the weighted average number of Common and Subordinated Units outstanding. Diluted net income (loss) per limited partner unit is computed by dividing net income (loss), after considering the Non-Managing General Partner’s interest, by the weighted average number of Common and Subordinated Units outstanding and the dilutive effect of unit options granted under the long-term incentive plan. Unit options were antidilutive for the three month periods ended June 30, 2003 and 2002. As such, for those periods, basic and diluted net loss per limited partner unit are identical. The following table presents the calculation of basic and dilutive income (loss) per limited partner unit (in thousands, except per unit data):

	Three Months Ended June 30,						Nine Months Ended June 30,
	2003			2002			2003		2002
Numerator:
Net income (loss)	$	(6,548	)	$	(5,910	)	$	18,953	$	12,606
Less: Non-Managing General Partners’ interest in net income (loss)		(131	)		(118	)		379		252
Limited partners’ interest in net income (loss) – basic and diluted	$	(6,417	)	$	(5,792	)	$	18,574	$	12,354
Denominator:
Weighted average limited partners’ units outstanding – basic		8,516			6,585			8,022		6,303
Effect of dilutive unit options outstanding		—			—			116		99
Weighted average limited partners’ units outstanding – dilutive		8,516			6,585			8,138		6,402
Net income (loss) per limited partner unit:
Basic	$	(0.75	)	$	(0.88	)	$	2.32	$	1.96
Diluted	$	(0.75	)	$	(0.88	)	$	2.28	$	1.93

13

INERGY, L.P. AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 2 – Accounting Policies Update (continued)

Accounting for Unit-Based Compensation

Inergy has a unit-based employee compensation plan, which is accounted for under the recognition and measurement principles of APB Opinion No. 25, Accounting for Stock Issued to Employees, and related Interpretations. No unit-based employee compensation cost is reflected in net income (loss), as all options granted under the plan had an exercise price equal to the market value of the underlying common units on the date of grant. The following table illustrates the effect on net income (loss) and net income (loss) per limited partner unit if the Company had applied the fair value recognition provisions of SFAS No. 123, Accounting for Stock-Based Compensation, to unit-based employee compensation (in thousands, except per unit data).

	Three Months Ended June 30,						Nine Months Ended June 30,
	2003			2002			2003		2002
Limited partners’ interest in net income (loss), as reported	$	(6,417	)	$	(5,792	)	$	18,574	$	12,354
Deduct: Total Unit-based employee compensation expense determined under fair value based method for all awards1		45			34			111		107
Pro forma limited partners’ interest in net income (loss)	$	(6,462	)	$	(5,826	)	$	18,463	$	12,247
Net income (loss) per limited partner unit:
Basic—as reported	$	(0.75	)	$	(0.88	)	$	2.32	$	1.96
Basic—pro forma	$	(0.76	)	$	(0.88	)	$	2.30	$	1.94
Diluted—as reported	$	(0.75	)	$	(0.88	)	$	2.28	$	1.93
Diluted—pro forma	$	(0.76	)	$	(0.88	)	$	2.27	$	1.91

¹ All awards refer to unit options granted, for which the fair value was required to be measured under SFAS No. 123.

Reclassifications

Certain reclassifications have been made to the consolidated financial statements for the three and nine months ended June 30, 2002 to conform to the three and nine months ended June 30, 2003 presentation.

14

INERGY, L.P. AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 3 – Long-Term Debt

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

	June 30, 2003		September 30, 2002
Credit agreement	$	16,211	$	35,500
Senior secured notes		87,082		85,709
Obligations under noncompetition agreements and notes to former owners of businesses acquired		3,419		3,244
Other		6		9
		106,718		124,462
Less current portion		3,637		19,367
	$	103,081	$	105,095

Inergy’s credit agreement at June 30, 2003 was comprised of a $50.0 million revolving working capital facility and a $75.0 million revolving acquisition facility. Effective July 29, 2003, Inergy executed an Amended and Restated Credit Agreement (the “Amended Facility”) with its existing lenders in addition to others. The Amended Facility consists of a $50 million revolving working capital facility and a $150 million revolving acquisition facility. The Amended Facility expires in July 2006 and carries terms, conditions and covenants substantially similar to the previous credit agreement. The Amended Facility is also guaranteed by Inergy, L.P. and its subsidiary.

At June 30, 2003 and September 30, 2002, the balance outstanding under the credit facility was $16.2 million and $35.5 million, respectively, including $6.6 million and $22.0 million, respectively, under the working capital facility. Inergy is required to reduce the principal outstanding on the revolving working capital line of credit to $4.0 million or less for a minimum of 30 consecutive days during the period commencing March 1 and ending September 30. As such, $4.0 million of the outstanding balance at June 30, 2003 and September 30, 2002, has been classified as a long-term liability in the accompanying consolidated balance sheets.

In October 2002, Inergy entered into three interest rate swap agreements scheduled to mature in June 2007, June 2008 and June 2009, respectively, each designed to hedge $5.0 million in underlying fixed rate senior secured notes, in order to manage interest rate risk exposure in an attempt to reduce overall interest expense. The swap agreements, which expire on the same dates as the maturity dates of the related senior secured notes, require the counterparty to pay an amount based on the stated fixed interest rate on the notes due every three months. In exchange, Inergy is required to make quarterly floating interest rate payments on the same dates to the counterparty based on an annual interest rate equal to the 3 month LIBOR interest rate plus approximately 5.0% applied to the same notional amount of $15.0 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.

15

INERGY, L.P. AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 3 – Long-Term Debt (continued)

The operating company had previously entered into similar swap agreements in fiscal 2002 on a notional amount of $20.0 million of the fixed rate senior secured notes. The Company has recognized the approximate $0.9 million and $1.4 million increase in the fair market value of these related senior secured notes for the three months and nine months ended June 30, 2003, respectively, with a corresponding increase in the fair value of its interest rate swaps, which is recorded in other non-current assets. The total increase in market value of all the interest rate swaps is approximately $2.1 million at June 30, 2003.

Note 4 – Unit Offering

In March 2003, Inergy issued 805,000 common units in a follow-on offering, resulting in proceeds of $23.4 million, net of underwriter’s discount, commission, and offering expenses. Inergy Partners, LLC contributed $0.5 million in cash to Inergy, L.P. in conjunction with the issuance in order to maintain its 2% non-managing general partner interest.

In June 2003, Inergy issued 2,651 common units in conjunction with the acquisition of Phillips Oil and Propane, Inc. Inergy Partners, LLC contributed $2,000 in cash to Inergy, L.P. in conjunction with the issuance in order to maintain its 2% non-managing general partner interest.

Note 5 – Quarterly Distributions of Available Cash

On November 14, 2002, a quarterly distribution of $0.70 per limited partner unit was paid to its unitholders of record on November 7, 2002 with respect to the fourth fiscal quarter of 2002, which totaled $5.5 million. On February 14, 2003, a quarterly distribution of $0.715 per limited partner unit was paid to its unitholders of record on February 7, 2003 with respect to the first fiscal quarter of 2003, which totaled $5.7 million. On May 15, 2003, a quarterly distribution of $0.73 per limited partner unit was paid to its unitholders of record on May 8, 2003, with respect to the second fiscal quarter of 2003, which totaled $6.4 million. Inergy will distribute $0.75 per limited partner unit on August 14, 2003 to unitholders of record on August 7, 2003, for a total distribution of $7.5 million with respect to its third fiscal quarter of 2003.

Note 6 – Commitments and Contingencies

Inergy periodically enters into agreements to purchase fixed quantities of propane at fixed prices with suppliers. At June 30, 2003, the total of these firm purchase commitments was approximately $46.5 million.

At June 30, 2003, Inergy was contingently liable for letters of credit outstanding totaling $4.1 million, which guarantees various transactions.

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INERGY, L.P. AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 6 – Commitments and Contingencies (continued)

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

Note 7 – Segments

Inergy’s financial statements reflect two reportable segments: retail sales operations and wholesale sales operations. Revenues, gross profit and identifiable assets for each of our reportable segments are presented below.

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

The following segment information is presented in thousands of dollars:

	Three Months Ended June 30, 2003
	Retail Sales Operations		Wholesale Sales Operations		Intersegment Eliminations			Total
Revenues	$	21,687	$	25,756	$	(7,962	)	$	39,481
Gross profit		10,764		373		—			11,137
Identifiable assets		14,698		23,355		—			38,053
	Three Months Ended June 30, 2002
	Retail Sales Operations		Wholesale Sales Operations		Intersegment Eliminations			Total
Revenues	$	19,570	$	21,294	$	(4,166	)	$	36,698
Gross profit		11,334		887		(59	)		12,162
Identifiable assets		12,172		29,322		—			41,494

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INERGY, L.P. AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 7 – Segments (continued)

	Nine Months Ended June 30, 2003
	Retail Sales Operations		Wholesale Sales Operations		Intersegment Eliminations			Total
Revenues	$	150,778	$	220,354	$	(63,311	)	$	307,821
Gross profit		73,817		7,638		(994	)		80,461
Identifiable assets		14,698		23,355		—			38,053
	Nine Months Ended June 30, 2002
	Retail Sales Operations		Wholesale Sales Operations		Intersegment Eliminations			Total
Revenues	$	96,799	$	94,456	$	(21,740	)	$	169,515
Gross profit		58,236		4,709		(509	)		62,436
Identifiable assets		12,172		29,322		—			41,494

Note 8 – Subsequent Events

On July 31, 2003, Inergy acquired substantially all of the propane assets of United Propane, Inc. In this acquisition, Inergy issued 889,906 common units and 254,259 senior subordinated units to United Propane.

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

Our “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of Inergy should be read in conjunction with the accompanying condensed 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/A for the fiscal year ended September 30, 2002 of Inergy, L.P.

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 (the Reform Act). Such forward-looking statements include, but are not limited to, statements concerning our expected recovery of goodwill attributable to our acquisitions and the sufficiency of cash received from operations and borrowings to meet our foreseeable liquidity needs. Such forward-looking statements involve risks, uncertainties and other factors which may cause the actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements. Such factors include, but are not limited to, the following: weather in our area of operations; market price of propane; availability of financing; changes in, or failure to comply with, government regulations; the costs, uncertainties and other effects of legal and administrative proceedings and other risks and uncertainties detailed in our Securities and Exchange Commission filings. For those statements, we claim the protection 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. In addition, it is our policy generally not to make any specific projections as to future earnings, and we do not endorse any projections regarding future performance that may be made by third parties.

Acquisitions

In October 2002, we acquired the assets of Hancock Gas Service, Inc. with headquarters in Findlay, Ohio; in December 2002, we acquired the assets of Central Carolina Gas Company, Inc., with headquarters in Hamlet, North Carolina; and Live Oak Gas Company, Inc., with headquarters in Live Oak, Florida. These three companies distributed approximately ten million gallons of propane during the preceding 12 month period ended September 30, 2002, which represents approximately 11% of our retail propane gallons distributed during fiscal 2002.

In April 2003, we acquired the assets of Coleman Gas, Inc. of Hastings, Florida and the assets of Johnson & Johnson Propane, Inc. of Madison, Florida. In June 2003, we acquired the assets of Phillips Propane, Inc. of Leipsic, Ohio. These three companies distributed approximately two million gallons of propane during the preceding 12 month period ended September 30, 2002, which represents approximately 2% of our retail propane gallons distributed during fiscal 2002.

In May 2003, we acquired certain assets of Resource Energy Marketing Ltd., a wholesale propane marketer and transporter based in Calgary, Alberta, Canada. This company distributed approximately 74

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million gallons of propane during the preceding 12 month period ended September 30, 2002, which represents approximately 29% of our wholesale propane gallons distributed during fiscal 2002.

In July 2003, we acquired substantially all of the assets of Nelson Propane in Tallahassee, Florida, and of five locations from a regional marketer in southern Georgia and northern Florida, and of United Propane, Inc. of Millersville, Maryland. These companies distributed approximately 24 million gallons of propane during the preceding 12 month period ended September 30, 2002, which represents approximately 27% of our retail propane gallons distributed during fiscal 2002.

Three Months Ended June 30, 2003 Compared to Three Months Ended June 30, 2002

Volume. During the three months ended June 30, 2003, we sold 13.4 million retail gallons of propane, an increase of 0.3 million gallons, or 2%, from the 13.1 million retail gallons sold during the same three-month period in 2002. The increase in retail sales volume was principally due to the October 2002 acquisition of Hancock Gas Service, Inc. partially offset by fewer gallon sales from existing locations primarily as a result of higher product costs.

Wholesale gallons delivered decreased 19.0 million gallons, or 37%, to 32.6 million gallons during the three months ended June 30, 2003 from 51.6 million gallons during the same three-month period in 2002. This decrease was primarily attributable to fewer fixed gallon sales in the 2003 period compared to 2002 due primarily to higher cost of product.

Revenues. Revenues in the three months ended June 30, 2003 were $39.5 million, an increase of $2.8 million, or 8%, from $36.7 million of revenues in fiscal 2002.

Revenues from retail sales were $20.9 million (after elimination of sales to our wholesale operations) in the three months ended June 30, 2003, an increase of $2.4 million, or 13%, from $18.5 million during the same three-month period in 2002. This increase was primarily attributable to higher selling prices of propane, due to the higher cost of propane, and acquisition-related volume. Revenues from retail sales consist of retail propane sales, transportation revenues, tank rentals, heating oil sales, and appliance sales and service.

Revenues from wholesale sales were $18.6 million (after elimination of sales to our retail operations) in the three months ended June 30, 2003, an increase of $0.4 million or 2%, from $18.2 million during the same three-month period in 2002. This increase was primarily attributable to the higher cost of propane in the three months ended June 30, 2003 as compared to the same period in 2002 partially offset by fewer gallon sales as described above. EITF No. 02-3 requires the reporting of gains and losses on energy trading contracts be reported on a net basis in the income statement. Upon adoption, we reduced both revenue and cost of product sold by $21.3 million for the three months ended June 30, 2002. This reclassification had no impact on gross profit or net income.

Cost of Product Sold. Cost of product sold in the three months ended June 30, 2003 was $28.3 million, an increase of $3.8 million or 16%, from cost of product sold of $24.5 million in the same period in 2002. This increase was primarily attributable to an approximate 60% increase in the average per gallon cost of propane, and an increase in acquisition-related volume partially offset by fewer wholesale gallon sales as described above.

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Gross Profit. Retail gross profit was $10.8 million (after elimination of sales to our wholesale operations) in the three months ended June 30, 2003 compared to $11.3 million during the same three-month period in 2002, a decrease of $0.5 million, or 5%. This decrease was primarily attributable to a decrease in margin per gallon as a result of higher propane costs during the three months ended June 30, 2003 as compared to the same period in 2002. Wholesale gross profit was $0.4 million (after elimination of gross profit attributable to our retail operations) in the three months ended June 30, 2003 compared to $0.8 million in fiscal 2002, a decrease of $0.4 million. This decrease was attributable to decreased wholesale volumes as described above and decreased margins as a result of propane price volatility.

Operating and Administrative Expenses. Operating and administrative expenses increased $0.2 million, or 2%, to $12.1 million in the three months ended June 30, 2003 as compared to $11.9 million in the same three-month period in 2002. This increase was primarily attributable to increased personnel and retail delivery vehicle expenses as a result of retail acquisitions.

Depreciation and Amortization. Depreciation and amortization increased $0.2 million or 6% to $3.4 million in the three months ended June 30, 2003 from $3.2 million in the same three-month period in 2002, primarily as a result of acquisition activity.

Interest Expense. Interest expense remained constant at $2.3 million during the three-months ended June 30, 2003 and 2002.

Interest Expense Related to Write-off of Deferred Financing Costs. A one-time charge of $0.6 million was recorded in 2002 as a result of the write-off of deferred financing costs associated with the IPC term note that was repaid with the proceeds from the private placement of the senior secured notes.

Net Loss. A net loss was recorded in the three months ended June 30, 2003 of $6.5 million, compared to a loss of $5.9 million in the same three-month period in 2002. This increase in net loss was primarily attributable to a decrease in gross profit and an increase in operating and administrative expenses and depreciation and amortization expenses, less the effect of the deferred financing cost write-off in 2002.

EBITDA. For the three months ended June 30, 2003, income (loss) before interest, taxes, depreciation and amortization was $(0.9) million compared to $0.2 million in the same period in 2002. The $1.1 million decrease was primarily attributable to lower wholesale volumes, a decrease in retail and wholesale gross profit per gallon as a result of higher propane costs and an increase in operating and administrative expenses. EBITDA is defined as income before taxes, plus interest expense and depreciation and amortization expense, less interest income. EBITDA should not be considered an alternative to net income, income before income taxes, cash flows from operating activities, or any other measure of financial performance calculated in accordance with generally accepted accounting principles as those items are used to measure operating performance, liquidity or ability to service debt obligations. We believe that EBITDA provides additional information for evaluating our ability to make the minimum quarterly distribution and is presented solely as a supplemental measure. EBITDA, as we define it, may not be comparable to EBITDA or similarly titled measures used by other corporations or partnerships.

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	(Unaudited)
	Three Months Ended June 30,
EBITDA (in thousands)	2003			2002
EBITDA:
Net loss	$	(6,548	)	$	(5,910	)
Interest expense		2,263			2,318
Interest expense related to write-off of deferred financing costs		—			585
Provision for income taxes		32			30
Depreciation and amortization		3,362			3,174
EBITDA	$	(891	)	$	197

Nine Months Ended June 30, 2003 Compared to Nine Months Ended June 30, 2002

Volume. During the nine months ended June 30, 2003, we sold 99.8 million retail gallons of propane, an increase of 26.2 million gallons, or 36%, from the 73.6 million retail gallons sold during the same nine-month period in 2002. The increase in retail sales volume was principally due to colder weather, the December 2001 IPC acquisition and the October 2002 acquisition of Hancock Gas Service, Inc. The weather was approximately 18% colder in the nine months ended June 30, 2003 as compared to the same nine-month period in 2002 in our retail areas of operations and approximately 7% colder than normal.

Wholesale gallons delivered increased 40.5 million gallons, or 20%, to 239.0 million gallons during the nine months ended June 30, 2003 from 198.5 million gallons during the same nine-month period in 2002. This increase was primarily attributable to the growth of our existing wholesale operations and the colder weather in the nine months ended June 30, 2003 as compared to the same nine-month period in 2002 in our wholesale areas of operations.

Revenues. Revenues in the nine months ended June 30, 2003 were $307.8 million, an increase of $138.3 million, or 82%, from $169.5 million of revenues in fiscal 2002.

Revenues from retail sales were $145.2 million (after elimination of sales to our wholesale operations) in the nine months ended June 30, 2003, an increase of $52.4 million, or 57%, from $92.8 million during the same nine-month period in 2002. This increase was primarily attributable to acquisition related volume, higher selling prices of propane due to the higher cost of propane, and volume increases at our existing locations as a result of colder weather in the nine months ended June 30, 2003.

Revenues from wholesale sales were $162.6 million (after elimination of sales to our retail operations) in the nine months ended June 30, 2003, an increase of $85.9 million or 112%, from $76.7 million during the same nine-month period in 2002. This increase was primarily attributable to the higher cost of propane and colder weather in the nine months ended June 30, 2003 as compared to the same period in 2002. Upon adoption of EITF No. 02-3 during the fourth quarter of fiscal 2002, as discussed further above, we reduced both revenue and cost of product sold by $52.5 million for the nine months ended June 30, 2002. This reclassification had no impact on gross profit or net income.

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Cost of Product Sold. Cost of product sold in the nine-month period ended June 30, 2003 was $227.4 million, an increase of $120.3 million or 112%, from cost of product sold of $107.1 million in the same period in 2002. This increase was primarily attributable to an approximate 71% increase in the average per gallon cost of propane, and an increase in wholesale and retail gallons sold, due to colder weather and acquisition-related volume.

Gross Profit. Retail gross profit was $73.8 million (after elimination of sales to our wholesale operations) in the nine months ended June 30, 2003 compared to $58.2 million during the same nine-month period in 2002, an increase of $15.6 million, or 27%. This increase was primarily attributable to an increase in retail gallons sold due to colder weather and acquisition-related volume, partially offset by a decrease in margin per gallon as a result of higher propane costs during the nine months ended June 30, 2003 as compared to the same period in 2002. Wholesale gross profit was $6.6 million (after elimination of gross profit attributable to our retail operations) in the nine months ended June 30, 2003 compared to $4.2 million in fiscal 2002, an increase of $2.4 million. This increase was attributable to increased margins and wholesale volume as a result of propane price volatility and colder weather.

Operating and Administrative Expenses. Operating and administrative expenses increased $9.0 million, or 25%, to $44.2 million in the nine months ended June 30, 2003 as compared to $35.2 million in the same nine-month period in 2002. This increase was primarily attributable to increased personnel and retail delivery vehicle expenses as a result of higher retail propane sales volumes in 2003 as compared to 2002 due to the colder weather, internal growth and retail acquisitions. In addition, greater profitability in 2003 as compared to 2002 resulted in higher personnel costs through incentive compensation.

Depreciation and Amortization. Depreciation and amortization increased $1.8 million, or 21%, to $10.1 million in the nine months ended June 30, 2003 from $8.3 million in the same nine-month period in 2002 primarily as a result of acquisitions.

Interest Expense. Interest expense increased $1.8 million, or 33%, to $7.4 million in the nine-month period ended June 30, 2003 as compared to $5.6 million in the same period of 2002. This increase is primarily the result of a higher overall average interest rate in the nine months ended June 30, 2003 as compared to the same period in the prior year as a result of the higher rate of interest associated with the senior secured notes issued in June 2002, partially offset by lower outstanding borrowings in 2003 as compared to the same period in 2002.

Interest Expense Related to Write-off of Deferred Financing Costs. A charge of $0.6 million was recorded in 2002 as a result of the write-off of deferred financing costs associated with the IPC term note that was repaid with the proceeds from the private placement of the senior secured notes.

Net Income. Net income increased $6.4 million, or 50%, to $19.0 million for the nine months ended June 30, 2003 from $12.6 million in the same period in 2002. This increase in net income was primarily attributable to the increase in gross profit due to greater volumes sold as a result of colder weather and acquisitions, partially offset by higher interest costs and increases in operating and administrative expenses.

EBITDA. For the nine months ended June 30, 2003, income before interest, taxes, depreciation and amortization was $36.6 million compared to $27.1 million in the same period in 2002. The $9.5 million

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increase was primarily attributable to increased retail sales volumes and increased wholesale gross profits partially offset by an increase in operating and administrative expenses, all primarily due to greater sales volume in the nine months ended June 30, 2003 due to colder weather as compared to the same period in 2002 and acquisitions. EBITDA is defined as income before taxes, plus interest expense and depreciation and amortization expense, less interest income. EBITDA should not be considered an alternative to net income, income before income taxes, cash flows from operating activities, or any other measure of financial performance calculated in accordance with generally accepted accounting principles as those items are used to measure operating performance, liquidity or ability to service debt obligations. We believe that EBITDA provides additional information for evaluating our ability to make the minimum quarterly distribution and is presented solely as a supplemental measure. EBITDA, as we define it, may not be comparable to EBITDA or similarly titled measures used by other corporations or partnerships.

	(Unaudited)
	Nine Months Ended June 30,
EBITDA (in thousands)	2003		2002
EBITDA:
Net Income	$	18,953	$	12,606
Interest Expense		7,399		5,555
Interest expense related to write-off of deferred financing costs		—		585
Provision for income taxes		102		82
Depreciation and amortization		10,097		8,319
EBITDA	$	36,551	$	27,147

Liquidity and Sources of Capital

In March 2003, Inergy issued 805,000 common units in a follow-on offering, resulting in proceeds of $23.4 million, net of underwriter’s discount, commission, and offering expenses. Inergy Partners, LLC contributed $0.5 million in cash to Inergy, L.P. in conjunction with the issuance in order to maintain its 2% non-managing general partner interest. These funds were used to repay borrowings under our credit agreement.

In June 2003, Inergy issued 2,651 common units in conjunction with the acquisition of Phillips Oil and Propane, Inc. Inergy Partners, LLC contributed $2,000 in cash to Inergy, L.P. in conjunction with the issuance in order to maintain its 2% non-managing general partner interest.

In July 2003, Inergy issued 889,906 common units and 254,259 senior subordinated units in conjunction with the acquisition of United Propane, Inc. Inergy Partners, LLC contributed cash to Inergy, L.P. in conjunction with the issuance in order to maintain its 2% non-managing general partner interest.

Cash flows provided by operating activities of $38.0 million in the nine months ended June 30, 2003 consisted primarily of: net income of $19.0 million, net non-cash charges of $11.8 million (principally related to depreciation and amortization of $10.1 million), and an increase in cash flows of $7.2 million associated with the changes in operating assets and liabilities, including assets and liabilities from price

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risk management activities. The source of cash associated with the changes in operating assets and liabilities is primarily due to the $22.4 million decrease in propane inventory, partially offset by decreases in accounts payable and customer deposits and an increase in accounts receivable. These changes are attributable to the seasonal nature of our business and our retail and wholesale growth. Cash flows provided by operations of $18.4 million in the same nine-month period of 2002 consisted primarily of net income of $12.6 million, net non-cash charges of $10.7 million (principally related to depreciation and amortization of $8.3 million) offset by a use of cash of $4.9 million associated with the changes in operating assets and liabilities, including net liabilities from price risk management activities. The use of cash associated with the changes in operating assets and liabilities in the 2002 period was due primarily to the $11.4 million increase in inventory and the decrease in customer deposits, resulting from weather seasonality, partially offset by the effects of increased accounts payable related to inventory growth.

Cash used in investing activities was $23.8 million in the nine months ended June 30, 2003 as compared to $91.4 million in the same nine-month period of 2002. Investing activities during the nine months ended June 30, 2003 included a use of cash of $19.8 million for the acquisitions of Hancock Gas Service, Inc.; Central Carolina Gas Company, Inc.; Live Oak Gas Company, Inc.; Coleman Gas, Inc.; Johnson & Johnson Propane, Inc.; Resource Energy Marketing Ltd.; Phillips Propane, Inc.; and five locations from a regional marketer. Investing activities in the 2002 period included a use of cash of $83.5 million for the acquisitions of Independent Propane Company and Pro Gas. Additionally, we expended $3.9 million and $4.4 million during the nine months ended June 30, 2003 and 2002, respectively, for additions to property and equipment primarily to accommodate our growing operations.

Cash used in financing activities was $14.2 million in the nine months ended June 30, 2003, compared to $71.9 million in cash provided by financing activities in the same period of 2002. Cash used in financing activities in 2003 included net payments of $20.4 million compared to net borrowings of $50.7 million in 2002, under long-term debt agreements, including borrowings and repayments of our revolving working capital and acquisition credit facility. The net payments in 2003 were primarily from net proceeds of $23.4 million received from the issuance of common units, while the net borrowings in 2002 resulted primarily from the issuance of debt in connection with the Independent Propane Company and Pro Gas acquisitions. Cash paid as distributions to unitholders was $17.7 million and $10.9 million in the nine months ended 2003 and 2002, respectively.

The following table summarizes our company’s long-term debt and operating lease obligations as of June 30, 2003 in thousands of dollars:

	Total		Less than 1 year		1-3 years		4-5 years		After 5 years
Aggregate amount of principal to be paid on the outstanding long-term debt	$	106,718	$	3,637	$	14,657	$	62,148	$	26,276
Future minimum lease payments under noncancelable operating leases		8,945		2,601		3,845		1,939		560
Standby letters of credit		4,060		4,060		—		—		—

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The following table summarizes the change in the unrealized fair value of our propane contracts related to our risk management activities for the three and nine months ended June 30, 2003 where settlement has not yet occurred (in thousands of dollars):

	Three Months Ended June 30, 2003			Nine Months Ended June 30, 2003
Net unrealized gains and (losses) in fair value of contracts outstanding at beginning of period	$	1,372		$	(4,653	)
Other unrealized gains and (losses) recognized		(156	)		1,838
Less: realized gains and (losses) recognized		(1,393	)		2,638
Net unrealized losses in fair value of contracts outstanding at June 30, 2003	$	(177	)	$	(177	)

Of the outstanding unrealized gain (loss) as of June 30, 2003, contracts with a maturity of less than one year totaled $(0.2) million, and contracts maturing in excess of one year totaled less than $0.1 million.

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

Seasonality

The retail market for propane is seasonal because it is used primarily for heating in residential and commercial buildings. Approximately 75% 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’s credit agreement at June 30, 2003 was comprised of a $50.0 million revolving working capital facility and a $75.0 million revolving acquisition facility. Effective July 29, 2003, Inergy executed an Amended and Restated Credit Agreement (the “Amended Facility”) with its existing lenders in addition to others. The Amended Facility consists of a $50 million revolving working capital facility and a $150 million revolving acquisition facility. The Amended Facility expires in July 2006 and carries terms, conditions and covenants substantially similar to the previous credit agreement. The Amended Facility is also guaranteed by Inergy, L.P. and its subsidiary.

This credit agreement accrues interest at either prime rate or LIBOR plus applicable spreads, resulting in interest rates of 3.52% to 4.00% at June 30, 2003. At June 30, 2003, borrowings outstanding under the credit facility were $16.2 million, including $6.6 million under the revolving working capital facility. Of the outstanding credit facility balance of $16.2 million, $13.6 million is classified as long term in the accompanying 2003 consolidated balance sheet. At August 1, 2003, the borrowings

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outstanding under the credit facility were $21.8 million, including $0.1 million under the revolving working capital facility.

Recent Accounting Pronouncements

In August 2001, the FASB issued SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” which addresses financial accounting and reporting for the impairment or disposal of long-lived assets and supercedes SFAS No. 121, “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of,” and the accounting and reporting provisions of APB Opinion No. 30, “Reporting the Results of Operations—Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions,” for a disposal of a segment of a business. SFAS No. 144 is effective for fiscal years beginning after December 15, 2001, with earlier application encouraged. We adopted the provisions of SFAS No. 144 on October 1, 2002. This adoption did not materially affect our company’s consolidated financial position or results of operations.

The June 2002 consensus reached on EITF No. 02-3 codifies and reconciles existing guidance on the recognition and reporting of gains and losses on energy trading contracts and addresses other aspects of the accounting for contracts involved in energy trading and risk management activities. Among other things, the consensus requires that mark-to-market gains and losses on energy trading contracts should be shown net in the income statement, irrespective of whether the contract is physically settled. This presentation was effective for financial statements issued for periods ending after July 15, 2002. As such, we have reclassified all settled transactions that meet the definition of trading activities in the income statement to conform to the new presentation required under EITF No. 02-3. We have previously reported these transactions when settled in the income statement at their gross amounts in revenues and cost of product sold. The reclassified amounts for the three months and nine months ended June 30, 2002 was $21.3 million and $52.5 million, respectively. This required reclassification has no impact on previously reported gross profit, net income (loss) or cash provided by operating activities. Inergy physically delivered approximately 29.0 million and 49.6 million gallons related to transactions considered trading activities as defined by EITF No. 02-3 for the three months ended June 30, 2003 and 2002, respectively, and 227.6 million and 133.9 million gallons for the nine months ended June 30, 2003 and 2002, respectively.

In October 2002, the EITF reached a consensus in EITF No. 02-3 to rescind EITF No. 98-10, the basis for mark-to-market accounting used for recording energy trading activities by many companies, including Inergy. The October 2002 EITF consensus requires that all new energy-related contracts entered into subsequent to October 25, 2002 should not be accounted for pursuant to EITF No. 98-10. Instead, those contracts should be accounted for under accrual accounting and would not qualify for mark-to-market accounting unless the contracts meet the requirements stated under SFAS No. 133. The October 2002 EITF consensus also provides that inventory will no longer be accounted for using mark-to-market accounting and must be accounted for at the lower of cost or market. We have elected to use the special hedge accounting rules in SFAS No. 133 and hedge the fair value of certain inventory positions, whereby the hedged inventory and the related derivative instruments are both marked to market. Inventories purchased under energy contracts subsequent to October 25, 2002, and not otherwise designated as being hedged, as discussed above, are carried at the lower-of-cost or market effective January 1, 2003.

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The effective date for the full rescission of EITF No. 98-10 is for fiscal periods beginning after December 15, 2002. The effect of the rescission of EITF No. 98-10 did not have a material impact on our financial position or results of operations.

The consensus reached in EITF No. 02-3 rescinding Issue 98-10 requires all derivatives held for trading purposes to be reported on a net basis in the income statement regardless of whether these derivatives are settled physically. These netting requirements are also effective for fiscal periods beginning after December 15, 2002 and have been adopted.

In January 2003, the FASB issued Interpretation No. 46, “Consolidation of Variable Interest Entities,” in an effort to expand upon and strengthen existing accounting guidance that addresses when a company should include in its financial statements the assets, liabilities and activities of another entity. Interpretation 46 requires the primary beneficiary to consolidate a variable interest entity (VIE). A primary beneficiary is an entity that is subject to a majority of the risk of loss from the VIE’s activity or is entitled to receive a majority of the VIE’s residual returns or both. The interpretation also requires disclosure about VIEs that a company is not required to consolidate but in which it has a significant variable interest. The consolidation requirements apply immediately to VIEs created after January 31, 2003. Inergy does not have a variable interest in any VIEs created after January 31, 2003. The consolidation requirements apply to existing VIEs for periods beginning after June 15, 2003. Inergy does not expect the adoption of these provisions to have a material impact on its financial position, results of operations or cash flows.

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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, 2003, we had floating rate obligations totaling approximately $16.2 million for amounts borrowed under our credit agreement and an additional $35.0 million of floating rate obligations as a result of interest rate swap agreements as discussed below. These floating rate obligations expose us to the risk of increased interest expense in the event of increases in short-term interest rates.

Our operating company has five interest rate swap agreements designed to hedge $35.0 million of our fixed rate senior secured notes, in order to manage interest rate risk exposure and attempt to reduce overall interest expense. The swap agreements, which expire on the same dates as the maturity dates of the related senior secured notes, require the counterparties to pay us an amount based on the stated fixed interest rate on the notes due every three months. In exchange, our operating company is required to make quarterly floating interest rate payments on the same dates to the counterparties based on an annual interest rate equal to the 3 month LIBOR interest rate plus an average spread of approximately 5.00% applied to the same notional amount of $35.0 million. The swap agreements have been recognized as fair value hedges. Amounts to be received or paid under the agreements are accrued and recognized over the life of the agreements as an adjustment to interest expense. At June 30, 2003, we have recognized the approximate $2.1 million increase in the fair market value of the related senior secured notes with a corresponding increase in the fair value of its interest rate swaps, which is recorded in other non-current assets. Approximately $0.9 million and $1.4 million of the amount related to the three and nine months ended June 30, 2003, respectively.

If the floating rate were to increase by 100 basis points from June 2003 levels, our interest expense would increase by a total of approximately $0.5 million per year.

Propane Price, Market and Credit Risk

Inherent in our contractual portfolio are certain business risks, including market risk and credit risk. Market risk is the risk that the value of the portfolio will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by suppliers, customers or financial counterparties to a contract. We take an active role in managing and controlling market and credit risk and have established control procedures, which are reviewed on an ongoing basis. We monitor market risk through a variety of techniques, including daily reporting of the portfolio’s position to senior management. We attempt to minimize credit risk exposure through credit policies and periodic monitoring procedures. The counterparties associated with assets from price risk management activities were propane retailers, resellers and consumers and energy marketers and dealers.

The propane industry is a “margin-based” business in which gross profits depend on the excess of sales prices over supply costs. As a result, our profitability will be sensitive to changes in wholesale prices of propane caused by changes in supply or other market conditions. When there are sudden and sharp increases in the wholesale cost of propane, we may not be able to pass on these increases to our customers through retail or wholesale prices. Propane is a commodity and the price we pay for it can fluctuate significantly in response to supply or other market conditions. We have no control over supply

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or market conditions. In addition, the timing of cost pass-throughs can significantly affect margins. Sudden and extended wholesale price increases could reduce our gross profits and could, if continued over an extended period of time, reduce demand by encouraging our retail customers to conserve or convert to alternative energy sources.

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

Notional Amounts and Terms

The notional amounts and terms of these financial instruments as of June 30, 2003 and September 30, 2002 include fixed price payor for 2.4 million and 3.7 million barrels of propane, respectively, and fixed price receiver for 3.0 million and 5.6 million barrels of propane, respectively. 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 derivative financial instruments related to price risk management activities as of June 30, 2003, and September 30, 2002 was assets of $6.3 million and $9.7 million related primarily to propane, respectively, and liabilities of $6.4 million and $14.4 million related primarily to propane, 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.

Sensitivity Analysis

A theoretical change of 10% in the underlying commodity value would result in an approximate $0.1 million change in the market value of the contracts as there were approximately 1.0 million gallons of net unbalanced positions at June 30, 2003.

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Item 4. Controls and Procedures

As of the end of the period covered by this Quarterly Report on Form 10-Q, the Company carried out an evaluation, under the supervision and with the participation of the Company’s management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the Company’s disclosure controls and procedures pursuant to Exchange Act Rule 13a-15. Based upon that evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that the Company’s disclosure controls and procedures are effective in ensuring that information required to be disclosed by the Company in its periodic SEC filings is recorded, processed, summarized, and reported on a timely basis. There have been no changes in the Company’s internal control over financial reporting that occurred during the period covered by this Quarterly Report on Form 10-Q that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

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PART II—OTHER INFORMATION

Item 1. Legal Proceedings

None.

Item 2. Changes in Securities and Use of Proceeds

In June 2003, Inergy issued 2,651 common units in conjunction with the acquisition of Phillips Oil and Propane, Inc. Inergy Partners, LLC contributed $2,000 in cash to Inergy, L.P. in conjunction with the issuance in order to maintain its 2% non-managing general partner interest.

In July 2003, Inergy issued 889,906 common units and 254,259 senior subordinated units in conjunction with the acquisition of United Propane, Inc. Inergy Partners, LLC contributed $0.9 million in cash to Inergy, L.P. in conjunction with the issuance in order to maintain its 2% non-managing general partner interest.

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 and Reports on Form 8-K

(a) 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 Section 906 of the Sarbanes-Oxley Act of 2002.
32.2	Certification of Chief Financial Officer of Inergy, L.P. pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

(b) Inergy filed three reports on Form 8-K pertaining to the three months ended June 30, 2003.

Form 8-K dated May 7, 2003, was filed regarding the issuance of a press release reporting its second quarter 2003 financial results.

Form 8-K dated May 19, 2003, was filed disclosing the appointment of Arthur B. Krause to the Board of Directors of its managing general partner.

Form 8-K dated July 1, 2003, was filed disclosing an agreement to acquire substantially all of the propane assets of United Propane, Inc. of Millersville, Maryland.

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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 13, 2003	By:	/s/ R. Brooks Sherman, Jr.
		R. Brooks Sherman, Jr.
		Senior Vice President and Chief Financial Officer
		(Principal Financial Officer and Principal Accounting Officer)

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