Crestwood Equity Partners (CEQP) 10-Q 2011 Q3 Quarterly report

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, 2011

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	(IRS Employer
incorporation or organization)	Identification No.)
Two Brush Creek Blvd., Suite 200 Kansas City, Missouri (Address of principal executive offices)	64112 (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 has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that registrant was required to submit and post such files).    Yes  x    No  ¨

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

Large accelerated filer	x	Accelerated filer	¨
Non-accelerated filer	¨  (Do not check if a smaller reporting company)	Smaller reporting company	¨

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

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, 2011 (unaudited) and September 30, 2010		3
Unaudited Consolidated Statements of Operations for the Three and Nine Months Ended June  30, 2011 and 2010		4
Unaudited Consolidated Statement of Partners’ Capital for the Nine Months Ended June 30, 2011		5
Unaudited Consolidated Statements of Cash Flows for the Nine Months Ended June 30, 2011 and 2010		6
Unaudited Notes to Consolidated Financial Statements		8
Item  2 – Management’s Discussion and Analysis of Financial Condition and Results of Operations		29
Item 3 – Quantitative and Qualitative Disclosures About Market Risk		44
Item 4 – Controls and Procedures		45
Part II – Other Information
Item 1 – Legal Proceedings		47
Item 1A – Risk Factors		47
Item 2 – Unregistered Sales of Equity Securities and Use of Proceeds		47
Item 3 – Defaults Upon Senior Securities		47
Item 4 – Reserved		47
Item 5 – Other Information		47
Item 6 – Exhibits		47
Signature		49

2

PART I. FINANCIAL INFORMATION

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

INERGY, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in millions, except unit information)

	June  30, 2011		September  30, 2010
	(unaudited)
Assets
Current assets:
Cash and cash equivalents	$	158.6	$	144.4
Restricted cash		—		588.0
Accounts receivable, less allowance for doubtful accounts of $3.7 million and $3.2 million at June 30, 2011 and September 30, 2010, respectively		140.5		108.0
Inventories (Note 3)		145.8		137.1
Assets from price risk management activities		13.6		22.5
Prepaid expenses and other current assets		23.1		15.5
Total current assets		481.6		1,015.5
Property, plant and equipment (Note 3)		2,504.7		1,695.2
Less: accumulated depreciation		552.6		445.1
Property, plant and equipment, net		1,952.1		1,250.1
Intangible assets (Note 3):
Customer accounts		413.6		408.0
Other intangible assets		160.0		160.5
		573.6		568.5
Less: accumulated amortization		184.6		162.1
Intangible assets, net		389.0		406.4
Goodwill		496.6		444.3
Other assets		6.6		1.5
Total assets	$	3,325.9	$	3,117.8
Liabilities and partners’ capital
Current liabilities:
Accounts payable	$	110.7	$	88.4
Accrued expenses		72.1		62.5
Customer deposits		19.9		56.8
Liabilities from price risk management activities		16.5		24.3
Current portion of long-term debt (Note 7)		4.5		29.6
Total current liabilities		223.7		261.6
Long-term debt, less current portion (Note 7)		1,781.7		1,661.1
Other long-term liabilities		16.3		14.3
Deferred income taxes		20.5		20.7
Partners’ capital (Note 8):
Limited partner unitholders (119,087,258 and 36,303,699 common units issued and outstanding as of June 30, 2011 and September 30, 2010, respectively, and 11,963,173 and 11,568,560 Class B units issued and outstanding at June 30, 2011 and September 30, 2010, respectively)		1,283.7		53.3
Total Inergy, L.P. partners’ capital		1,283.7		53.3
Interest of non-controlling partners in subsidiaries		—		1,106.8
Total partners’ capital		1,283.7		1,160.1
Total liabilities and partners’ capital	$	3,325.9	$	3,117.8

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

3

INERGY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in millions, except unit and per unit data)

(unaudited)

	Three Months Ended June 30,						Nine Months Ended June 30,
	2011			2010			2011			2010
Revenue:
Propane	$	220.4		$	167.8		$	1,187.9		$	1,091.6
Other		168.3			123.8			517.3			392.8
		388.7			291.6			1,705.2			1,484.4
Cost of product sold (excluding depreciation and amortization as shown below):
Propane		164.0			113.3			819.1			733.8
Other		107.7			73.8			321.4			231.2
		271.7			187.1			1,140.5			965.0
Gross profit		117.0			104.5			564.7			519.4
Expenses:
Operating and administrative		77.4			75.3			243.6			231.2
Depreciation and amortization		48.0			40.5			141.8			117.7
Loss on disposal of assets		0.5			2.1			3.1			5.8
Operating income (loss)		(8.9	)		(13.4	)		176.2			164.7
Other income (expense):
Interest expense, net		(27.2	)		(23.1	)		(87.5	)		(67.4	)
Early extinguishment of debt (Note 7)		(0.2	)		—			(49.6	)		—
Other income		1.1			0.8			1.2			0.9
Income (loss) before income taxes		(35.2	)		(35.7	)		40.3			98.2
Benefit (provision) for income taxes		(0.3	)		0.6			(0.7	)		(0.3	)
Net income (loss)		(35.5	)		(35.1	)		39.6			97.9
Net (income) loss attributable to non-controlling partners		—			47.5			28.2			(47.7	)
Net income (loss) attributable to partners	$	(35.5	)	$	12.4		$	67.8		$	50.2
Total limited partners’ interest in net income (loss)	$	(35.5	)	$	12.4		$	67.8		$	50.2
Net income (loss) per limited partner unit:
Basic	$	(0.32	)	$	0.34		$	0.67		$	1.41
Diluted	$	(0.32	)	$	0.26		$	0.60		$	1.05
Weighted-average limited partners’ units outstanding (in thousands):
Basic		112,538			35,837			101,215			35,597
Dilutive units		—			12,371			11,862			12,305
Diluted		112,538			48,208			113,077			47,902

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

4

INERGY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL

(in millions)

(unaudited)

	Common Unit Capital			Non- Controlling Partners			Total Partners’ Capital
Balance at September 30, 2010	$	53.3		$	1,106.8		$	1,160.1
Net proceeds from issuance of common units		311.4			—			311.4
Net proceeds from common unit options exercised		2.1			3.0			5.1
Unit-based compensation charges		3.0			1.4			4.4
Costs associated with the simplification of capital structure		(0.7	)		(0.4	)		(1.1	)
Retirement of common units		(1.6	)		—			(1.6	)
Distributions		(176.1	)		(51.5	)		(227.6	)
Acquisition of non-controlling interest		1,032.9			(1,032.9	)		—
Other		—			(0.2	)		(0.2	)
Comprehensive income:
Net income (loss)		67.8			(28.2	)		39.6
Change in unrealized fair value on cash flow hedges		(8.4	)		2.0			(6.4	)
Comprehensive income								33.2
Balance at June 30, 2011	$	1,283.7		$	—		$	1,283.7

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

5

INERGY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

(unaudited)

	Nine Months Ended June 30,
	2011			2010
Operating activities
Net income	$	39.6		$	97.9
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and depletion		112.3			94.5
Amortization		29.5			23.2
Amortization of deferred financing costs, swap premium and net bond discount		5.7			5.4
Unit-based compensation charges		4.4			3.6
Provision for doubtful accounts		2.6			2.1
Loss on disposal of assets		3.1			5.8
Deferred income tax		(0.2	)		—
Early extinguishment of debt		11.2			—
Changes in operating assets and liabilities, net of effects from acquisitions:
Accounts receivable		(31.6	)		4.9
Inventories		(8.3	)		14.7
Prepaid expenses and other current assets		(6.7	)		4.6
Other liabilities		(0.2	)		(1.5	)
Accounts payable and accrued expenses		9.6			(47.8	)
Customer deposits		(36.9	)		(33.1	)
Net liabilities from price risk management activities		(3.6	)		(33.9	)
Net cash provided by operating activities		130.5			140.4
Investing activities
Acquisitions, net of cash acquired		(757.4	)		(252.9	)
Purchases of property, plant and equipment		(126.2	)		(71.2	)
Proceeds from sale of assets		20.2			4.8
Proceeds from redemption of bond offering escrow		588.0			—
Net cash used in investing activities		(275.4	)		(319.3	)

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

6

INERGY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (continued)

(in millions)

(unaudited)

	Nine Months Ended June 30,
	2011			2010
Financing activities
Proceeds from the issuance of long-term debt	$	1,837.0		$	788.3
Principal payments on long-term debt		(1,748.6	)		(621.9	)
Distributions		(176.1	)		(56.5	)
Distributions paid to non-controlling partners		(51.5	)		(122.2	)
Acquisition of minority interest		—			(14.2	)
Payments for deferred financing costs		(17.0	)		(10.4	)
Costs associated with the simplification of capital structure		(1.1	)		—
Net proceeds from issuance of common units		311.4			199.8
Net proceeds from common unit options exercised		5.1			4.7
Proceeds from swap settlement		—			5.2
Other		(0.1	)		—
Net cash provided by financing activities		159.1			172.8
Net increase (decrease) in cash		14.2			(6.1	)
Cash at beginning of period		144.4			11.7
Cash at end of period	$	158.6		$	5.6
Supplemental schedule of noncash investing and financing activities
Additions to intangible assets through the issuance of noncompetition agreements and notes to former owners of businesses acquired	$	4.1		$	6.4
Net change to property, plant and equipment through accounts payable and accrued expenses	$	8.7		$	(7.5	)
Change in the fair value of interest rate swap liability and related long-term debt	$	4.8		$	0.9
Acquisitions, net of cash acquired:
Current assets	$	5.0		$	26.1
Property, plant and equipment		436.2			115.2
Contractual rights		266.9			—
Intangible assets, net		8.9			74.5
Goodwill		51.9			89.3
Other assets		1.0			0.1
Current liabilities		(12.5	)		(52.3	)
Total acquisitions, net of cash acquired	$	757.4		$	252.9

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

7

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Note 1 – Partnership Organization and Basis of Presentation

Organization

On August 7, 2010, Inergy, L.P. (“Inergy”) and Inergy Holdings, L.P. (“Holdings”) entered into an Agreement and Plan of Merger, which was amended and restated by the First Amended and Restated Agreement and Plan of Merger, dated as of September 3, 2010, as part of a plan to simplify the capital structures of Inergy and Holdings (the “Merger Agreement”). Pursuant to the steps contemplated by the Merger Agreement (the “Simplification Transaction”), Holdings merged into a wholly owned subsidiary of its general partner (the “Merger”) and the outstanding common units in Holdings were cancelled. The Merger closed on November 5, 2010, resulting in Holdings unitholders receiving 0.77 Inergy units for each Holdings unit. Cash was paid to Holdings unitholders in lieu of any fractional units that resulted from the exchange. As a result of the closing, Holdings common units discontinued trading on the New York Stock Exchange as of the close of business on November 5, 2010. Holdings continues to own the managing general partner of Inergy subsequent to the Merger.

The Simplification Transaction was accounted for in accordance with Accounting Standards Codification (“ASC”) 810. Under ASC 810, the exchange of Holdings units for Inergy units was accounted for as a Holdings equity issuance and Holdings was the surviving entity. Although Holdings was the surviving entity for accounting purposes, Inergy was the surviving entity for legal purposes as provided for by the Merger Agreement; consequently, the name on these financial statements was changed from “Inergy Holdings, L.P.” to “Inergy, L.P.”

Historically, Holdings ownership of Inergy’s general partner, Inergy GP, LLC (“Inergy GP”), provided Holdings with an approximate 0.6% general partner interest in Inergy. Holdings also owned an approximate 6.0% limited partner interest in Inergy at September 30, 2010.

Because of the changes the Simplification Transaction has had on these financial statements and Inergy’s organizational structure, and because the nature of the pre-simplification and post-simplification Inergy entities are significantly different, these notes to consolidated financial statements refer to specific Inergy entities, with Inergy, L.P. prior to the simplification referred to as “Holdings” and after the simplification as “Inergy”, and the controlled operating subsidiary of Inergy, L.P. prior to the Merger is referred to as “Inergy”. References to “the Company” or “Inergy” in the footnotes related to the policies and procedures of Inergy, L.P. refer to Inergy, L.P. subsequent to the simplification. Other references to “the Company” or “we”, “our” and “us” throughout the document refer to the controlled subsidiary of Inergy, L.P. prior to the simplification if the timing of the statement is prior to November 5, 2010, and to Inergy, L.P. subsequent to the simplification if the timing of the statement is subsequent to November 5, 2010. The operating activities of the Inergy, L.P. controlled subsidiary prior to the Merger and Inergy, L.P. subsequent to the Merger are identical.

Nature of Operations

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 and natural gas liquids for third parties, fractionation of natural gas liquids, processing of natural gas, distribution of natural gas liquids and the production and sale of salt.

Basis of Presentation

The financial information contained herein as of June 30, 2011, and for the three-month and nine-month periods ended June 30, 2011 and 2010, 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 propane 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, 2011, are not indicative of the results of operations that may be expected for the entire fiscal year.

8

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

The accompanying consolidated financial statements include the accounts of Inergy, L.P., its wholly owned subsidiaries, Inergy Propane, LLC (“Inergy Propane”), Inergy Midstream, LLC (“Inergy Midstream”, and together with Inergy Propane, the “Operating Companies”), Inergy Partners, LLC (“Partners”), IPCH Acquisition Corp. (“IPCHA”) and Inergy Finance Corp. All significant intercompany transactions, including distribution income, and balances have been eliminated in consolidation.

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 8-K (dated November 29, 2010) as filed with the Securities and Exchange Commission for the fiscal year ended September 30, 2010.

Note 2 – Summary of Significant Accounting Policies

Financial Instruments and Price Risk Management

Inergy utilizes certain derivative financial instruments to (i) manage its exposure to commodity price risk, specifically, the related change in the fair value of inventories, as well as the variability of cash flows related to forecasted transactions; (ii) ensure adequate physical supply of commodity will be available; and (iii) manage its exposure to interest rate risk associated with fixed rate borrowings. Inergy records all derivative instruments on the balance sheet as either assets or liabilities measured at fair value. Changes in the fair value of these derivative financial instruments are recorded either through current earnings or as other comprehensive income, depending on the type of transaction.

Inergy is party to certain commodity derivative financial instruments that are designated as hedges of selected inventory positions, and qualify as fair value hedges. Inergy is also periodically party to certain interest rate swap agreements designed to manage interest rate risk exposure. 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 and fixed rate borrowings. The commodity 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. The interest rate derivatives are recorded at fair value on the balance sheets in other assets or liabilities and the related change in fair value is recorded to earnings in the current period as interest expense.

Any ineffective portion of the fair value hedges is recognized as cost of product sold in the current period. Inergy recognized a net gain of $0.3 million and $0.1 million in the three months ended June 30, 2011 and 2010, respectively, and a net gain of $0.3 million and $0.4 million in the nine months ended June 30, 2011 and 2010, respectively, related to the ineffective portion of its fair value hedging instruments. In addition, Inergy recognized no gain and a net loss of $0.8 million for the three months ended June 30, 2011 and 2010, respectively, and no gain and a net loss of $0.4 million for the nine months ended June 30, 2011 and 2010, respectively, related to the portion of fair value hedging instruments that it excluded from its assessment of hedge effectiveness.

Inergy also enters into derivative financial instruments that qualify as cash flow hedges, which hedge the exposure of variability in expected future cash flows predominantly attributable to forecasted purchases to supply fixed price sale contracts. These derivatives are recorded on the balance sheet at fair value as price risk management assets or liabilities. The effective portion of the gain or loss on these cash flow hedges is recorded in other comprehensive income in partner’s capital and reclassified into earnings as a component of cost of product sold in the same period in which the hedged transaction affects earnings. In certain situations under the rules, the ineffective portion of the gain or loss is recognized as cost of product sold in the current period. Accumulated other comprehensive income (loss) was $(2.1) million and $4.4 million at June 30, 2011 and September 30, 2010, respectively. Approximately $0.4 million is expected to be reclassified to earnings from other comprehensive income over the next twelve months. Inergy’s comprehensive income (loss) was $(38.3) million and $(39.5) million for the three months ended June 30, 2011 and 2010, respectively, and $33.2 million and $82.2 million for the nine months ended June 30, 2011 and 2010, respectively.

Inergy’s policy is to offset fair value amounts of derivative instruments and cash collateral paid or received with the same counterparty under a master netting arrangement.

9

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 statements of cash flows.

Revenue Recognition

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

Expense Classification

Cost of product sold consists of tangible products sold including all propane and other natural gas liquids, salt and all propane related appliances, as well as certain direct costs incurred in providing storage services. Operating and administrative expenses consist of all expenses incurred other than those described above in cost of product sold and depreciation and amortization. Certain operating and administrative expenses and depreciation and amortization are incurred in the distribution of product and storage sales but are not included in cost of product sold. These amounts were $51.7 million and $44.3 million for the three months ended June 30, 2011 and 2010, respectively, and $157.2 million and $133.6 million for the nine months ended June 30, 2011 and 2010, 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 propane operations, which mainly consist of propane gas and other liquids, are stated at the lower of cost or market and are computed using the average cost method. Wholesale propane and other liquids inventories are designated under a fair value hedge program and are consequently marked to market. Propane and other liquids inventories being hedged and carried at market value at June 30, 2011 and September 30, 2010, amount to $94.1 million and $82.6 million, respectively. Inventories for midstream operations are stated at the lower of cost or market and are computed predominantly using the average cost method.

Shipping and Handling Costs

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

Property, Plant and Equipment

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

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

Salt deposits are depleted on a unit of production method.

10

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Identifiable Intangible Assets

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

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

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

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

Goodwill

Goodwill is recognized for various acquisitions as the excess of the cost of the acquisitions over the fair value of the related net assets at the date of acquisition. Goodwill is subject to at least an annual assessment for impairment by applying a fair-value-based test.

In connection with the goodwill impairment evaluation, the Company identified five reporting units. The carrying value of each reporting unit is determined by assigning the assets and liabilities, including the existing goodwill and intangible assets, to those reporting units as of the date of the evaluation on a specific identification basis. To the extent a reporting unit’s carrying value exceeds its fair value, an indication exists that the reporting unit’s goodwill may be impaired and the second step of the impairment test must be performed. In the second step, the implied fair value of the goodwill is determined by allocating the fair value to all of its assets (recognized and unrecognized) and liabilities to its carrying amount.

Inergy completed its annual impairment test for each of its reporting units and determined that no impairment existed as of September 30, 2010. No indicators of impairment were identified requiring an interim impairment test during the nine-month period ended June 30, 2011.

Income Taxes

Inergy is a publicly-traded master limited partnership. Partnerships are generally not subject to federal income tax, although publicly-traded partnerships are treated as corporations for federal income tax purposes and therefore are subject to federal income tax, unless the partnership generates at least 90% of its gross income from qualifying sources. If the qualifying income requirement is satisfied, the publicly-traded partnership will be treated as a partnership for federal income tax purposes. Inergy Sales and Service, Inc. (“Services”), a subsidiary of Inergy, does not generate at least 90% of its gross income from qualifying sources, and as such, federal and state income taxes are provided on the taxable income of Services. The earnings of the Company and its limited liability subsidiaries are included in the Federal and state income tax returns of the individual members or partners. However, legislation in certain states allows for taxation of partnerships, and as such, certain state taxes for Inergy have been included in the accompanying financial statements as income taxes due to the nature of the tax in those particular states. In addition, Federal and state income taxes are provided on the earnings of the subsidiaries incorporated as taxable entities (IPCHA and Services). The Company is required to recognize deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements or tax returns. Under this method, deferred tax assets and liabilities are determined based on the differences between the financial reporting and tax basis of assets and liabilities using expected rates in effect for the year in which differences are expected to reverse.

11

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Net earnings for financial statement purposes may differ significantly from taxable income reportable to unitholders as a result of differences between the tax basis and the financial reporting basis of assets and liabilities and the taxable income allocation requirements under the partnership agreement.

Sales Tax

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

Income Per Unit

Inergy calculates basic net income per limited partner unit by dividing net income applicable to partners’ common interest by the weighted-average number of units outstanding. Diluted net income per limited partner unit is computed by dividing net income by the weighted-average number of units outstanding and the effect of dilutive units granted under the Long Term Incentive Plan and the Class B units.

As the effect of including incremental units associated with options were anti-dilutive for the three months ended June 30, 2011 due to the net loss reported for that period, no unit options or other dilutive units were reflected in the applicable dilutive earnings per unit computation. As a result, both basic earnings per unit and dilutive earnings per unit reflect the same calculation for the three-month period ended June 30, 2011. Anti-dilutive unit options and Class B units outstanding totaled 12,041,942 for the three months ended June 30, 2011.

Accounting for Unit-Based Compensation

Inergy has a unit-based employee compensation plan and all share-based payments to employees, including grants of employee stock options, are recognized in the consolidated statements of operations based on their fair values.

The amount of compensation expense recorded by the Company was $1.5 million and $1.4 million during the three months ended June 30, 2011 and 2010, respectively, and $4.4 million and $3.6 million during the nine months ended June 30, 2011 and 2010, respectively.

Segment Information

There are certain accounting requirements that establish standards for reporting information about operating segments, as well as related disclosures about products and services, geographic areas and major customers. Further, they define 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 its reportable segments, Inergy examined the way it organizes its business internally for making operating decisions and assessing business performance. See Note 10 for disclosures related to Inergy’s propane and midstream segments.

Fair Value

Cash and cash equivalents, accounts receivable (net of allowance for doubtful accounts) and payables are carried at cost, which approximates fair value due to their liquid and short-term nature. As of June 30, 2011, the estimated fair value of the fixed-rate Senior Notes, based on available trading information, totaled $1,488.3 million compared with the aggregate principal amount at maturity of $1,466.1 million. At June 30, 2011, the Company’s credit agreement (“Credit Agreement”) provided a $75 million revolving working capital facility (“Working Capital Facility”), a $450 million revolving general partnership facility (“General Partnership Facility”) and a $300 million term loan facility (“Term Loan Facility”). The carrying value at June 30, 2011, of amounts outstanding under the Credit Agreement of $300.0 million approximate fair value due primarily to the floating interest rate associated with the Credit Agreement.

12

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Recently Issued Accounting Pronouncements

In June 2011 the FASB issued Accounting Standards Update No. 2011-05, “Presentation of Comprehensive Income” (“ASU 2011-05”). Under ASU 2011-05, an entity has the option to present the total of comprehensive income, the components of net income, and the components of other comprehensive income either in a single continuous statement of comprehensive income or in two separate but consecutive statements. Under both options, an entity will be required to present each component of net income along with total net income, each component of other comprehensive income along with a total for other comprehensive income, and a total amount for comprehensive income. Furthermore, regardless of the presentation methodology elected, the entity will be required to present on the face of the financial statements reclassification adjustments for items that are reclassified from other comprehensive income to net income. The amendments contained in ASU 2011-05 do not change the items that must be reported in other comprehensive income or when an item of other comprehensive income must be reclassified to net income. The amendments also do not affect how earnings per share is calculated or presented. ASU 2011-05 is effective for the Company on October 1, 2012. The Company does not currently anticipate the adoption of ASU 2011-05 will impact comprehensive income, however it will require the Company to change its historical practice of showing these items within the Consolidated Statement of Partners’ Capital.

In January 2010, the FASB issued Accounting Standards Update No. 2010-06, “Improving Disclosures about Fair Value Measurements” (“ASU 2010-06”), which is included in the ASC Topic 820 (Fair Value Measurements and Disclosures). ASU 2010-06 requires new disclosures on the amount and reason for transfers in and out of Level 1 and Level 2 fair value measurements. ASU 2010-06 also requires disclosure of activities, including purchases, sales, issuances and settlements within the Level 3 fair value measurements and clarifies existing disclosure requirements on levels of disaggregation and disclosures about inputs and valuation techniques. The Company has previously adopted the new disclosures on the reason for transfers in and out of Level 1 and Level 2. The new disclosures for Level 3 are effective for fiscal years beginning after December 15, 2010. The Company does not currently anticipate that the adoption of the Level 3 disclosure requirements of ASU 2010-06 will result in a material change to the financial statements.

Note 3 – Certain Balance Sheet Information

Inventories consisted of the following at June 30, 2011 and September 30, 2010, respectively (in millions):

	June 30, 2011		September 30, 2010
Propane gas and other liquids	$	128.3	$	121.0
Appliances, parts, supplies and other		17.5		16.1
Total inventory	$	145.8	$	137.1

13

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Property, plant and equipment consisted of the following at June 30, 2011 and September 30, 2010, respectively (in millions):

	June 30, 2011		September 30, 2010
Tanks and plant equipment	$	1,067.7	$	937.9
Land and buildings		847.5		385.9
Vehicles		125.0		122.5
Construction in process		254.1		104.4
Reserve gas		134.3		69.8
Salt deposits		41.6		41.6
Office furniture and equipment		34.5		33.1
		2,504.7		1,695.2
Less: accumulated depreciation		552.6		445.1
Total property, plant and equipment, net	$	1,952.1	$	1,250.1

The tanks and plant equipment balances above include tanks owned by the Company that reside at customer locations. The leases associated with these tanks are accounted for as operating leases. These tanks had a value of $460.9 million with an associated accumulated depreciation balance of $117.0 million at June 30, 2011.

Intangible assets consisted of the following at June 30, 2011 and September 30, 2010, respectively (in millions):

	June 30, 2011		September 30, 2010
Customer accounts	$	413.6	$	408.0
Covenants not to compete		83.4		79.4
Deferred financing and other costs		45.7		50.2
Trademarks		30.9		30.9
		573.6		568.5
Less: accumulated amortization		184.6		162.1
Total intangible assets, net	$	389.0	$	406.4

Note 4 – Business Acquisitions

On October 14, 2010, Inergy completed the acquisition of Tres Palacios Gas Storage LLC (“Tres Palacios”), which owns and operates a natural gas storage facility located in Matagorda County, Texas. Tres Palacios is a high deliverability, salt dome natural gas storage facility with approximately 38.4 bcf of Federal Energy Regulatory Commission (“FERC”) certificated working gas capacity (Caverns 1-3). The facility is expandable by an additional 9.5 bcf of working gas capacity, which Inergy expects to place in service by or before 2014 (Cavern 4).

14

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

The Company is in the process of finalizing its valuations of certain property, plant and equipment as well as identifiable intangible assets; thus the provisional measurements of property, plant and equipment, intangible assets and goodwill are subject to material change. The following table summarizes the estimated fair values of the assets acquired and liabilities assumed at the acquisition date (in millions):

	October 14, 2010
Accounts receivable	$	6.3
Prepaid expenses and other current assets		0.8
Property, plant and equipment		414.4
Contractual rights		266.9
Other		1.2
Total identifiable assets acquired		689.6
Current liabilities		11.9
Total liabilities assumed		11.9
Net identifiable assets acquired		677.7
Goodwill		44.8
Net assets acquired	$	722.5

The $44.8 million of goodwill will be assigned to the midstream operations segment.

Tres Palacios leases the surface and subsurface rights necessary to operate and expand the storage facility under an operating lease that expires on December 31, 2037, which is subject to automatic renewal for two 20-year extension periods unless Tres Palacios elects not to extend the term of the lease. The lease payments vary based on the FERC-certificated working gas capacity of the caverns which are in service as well as an incremental payment for physical volumes of gas injected and / or withdrawn from the caverns in service. Based on its current estimates, which assumes Cavern 4 will be in service during the second fiscal quarter of 2014, Tres Palacios anticipates that the contractual obligation as of June 30, 2011, to be the following (in millions, excluding the above mentioned incremental payments as future volumes are currently unknown):

Total	Less than 1 year		1-3 years		4-5 years		After 5 years
$        406.7	$	11.4	$	24.5	$	31.3	$	339.5

The following represents the pro-forma consolidated statements of operations as if Tres Palacios had been included in the consolidated results of the Company for the three-month and nine-month periods ended June 30, 2010 (in millions):

	Pro-Forma Consolidated Statements of Operations
	Three Months Ended June 30, 2010			Nine Months Ended June 30, 2010
Revenue	$	302.9		$	1,527.9
Net income	$	(41.3	)	$	91.4

These amounts have been calculated after applying the Company’s accounting policies and adjusting the results of Tres Palacios to reflect the depreciation that would have been charged assuming the preliminary fair value adjustments to property, plant and equipment and intangible assets had been made at the beginning of the respective period. The net income attributable to partners was further adjusted to give effect to the impact of the interest expense associated with the September 2010 bond offering that was utilized to finance a portion of the Tres Palacios acquisition.

Revenue and net loss (including an allocation of intercompany interest expense) generated by Tres Palacios subsequent to the Company’s acquisition on October 14, 2010, amounted to $34.9 million and $13.4 million, respectively.

15

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

On June 2, 2011, Tres Palacios entered into a binding term sheet to amend and supplement various terms and conditions of its operating lease. Among other things, Tres Palacios obtained the contractual right to store natural gas liquids in certain caverns located on the leased premises, as well as a right of first refusal over caverns developed in the future for the storage of natural gas liquids.

On October 19, 2010, Inergy completed the acquisition of the propane assets of Schenck Gas Services, LLC (“Schenck”), located in East Hampton, New York.

On November 15, 2010, Inergy completed the acquisition of the propane assets of Pennington Energy Corporation (“Pennington”), headquartered in Morenci, Michigan.

The purchase price allocations for these acquisitions have been prepared on a preliminary basis pending final asset valuation and asset rationalization, and changes are expected when additional information becomes available.Changes to reflect final asset valuation of prior fiscal year acquisitions have been included in the Company’s consolidated financial statements but are not material.

Note 5 – Risk Management

The Company is exposed to certain market risks related to its ongoing business operations. These risks include exposure to changing commodity prices as well as fluctuations in interest rates. The Company utilizes derivative instruments to manage its exposure to fluctuations in commodity prices, which is discussed more fully below. The Company also periodically utilizes derivative instruments to manage its exposure to fluctuations in interest rates, which is discussed more fully in Note 7. Additional information related to derivatives is provided in Note 2 and Note 6.

Commodity Derivative Instruments and Price Risk Management

Risk Management Activities

Inergy sells propane and other commodities to energy related businesses and may use a variety of financial and other instruments including forward contracts involving physical delivery of propane. Inergy will enter into offsetting positions to hedge against the exposure its customer contracts create. Inergy does not designate these instruments as hedging instruments. These instruments are marked to market with the changes in the market value reflected in cost of product sold. Inergy attempts to balance its contractual portfolio in terms of notional amounts and timing of performance and delivery obligations. This balance in the contractual portfolio significantly reduces the volatility in cost of product sold related to these instruments. However, immaterial net unbalanced positions can exist or are established based on assessment of anticipated short-term needs or market conditions.

Cash Flow Hedging Activity

Inergy sells propane and heating oil to retail customers at fixed prices. Inergy will enter into derivative instruments to hedge a significant portion of its exposure to fluctuations in commodity prices as a result of selling the fixed price contracts. These instruments are identified and qualify to be treated as cash flow hedges. This accounting treatment requires the effective portion of the gain or loss on the derivative to be reported as a component of other comprehensive income and reclassified into earnings in the same period or periods during which the hedged transaction affects earnings. Gains and losses on the derivative representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in current earnings.

Fair Value Hedging Activity

Inergy will enter into derivative instruments to hedge its exposure to fluctuating commodity prices that results from maintaining its wholesale inventory. The instruments hedging wholesale inventory qualify to be treated as fair value hedges. This accounting treatment requires the fair value changes in both the derivative instruments and the hedged inventory to be recorded in cost of product sold.

16

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

A significant amount of inventory held in bulk storage facilities is hedged as it is not expected to be sold in the immediate future and is therefore exposed to fluctuations in commodity prices. Commodity inventory held at retail locations is not hedged as this inventory is expected to be sold in the immediate future and is therefore not exposed to fluctuations in commodity prices over an extended period of time.

Commodity Price and Credit Risk

Notional Amounts and Terms

The notional amounts and terms of the Company’s derivative financial instruments include the following at June 30, 2011 and September 30, 2010, respectively (in millions):

	June 30, 2011				September 30, 2010
	Fixed Price Payor		Fixed Price Receiver		Fixed Price Payor		Fixed Price Receiver
Propane, crude and heating oil (barrels)		3.5		3.8		6.2		5.8
Natural gas (MMBTU’s)		0.1		0.1		—		—

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 reflect the Company’s monetary exposure to market or credit risks.

Fair Value of Derivative Instruments

The following tables detail the amount and location on the Company’s consolidated balance sheets and consolidated statements of operations related to all of its commodity derivatives (in millions):

	Amount of Gain (Loss) Recognized in Net Income from Derivatives
	Three Months Ended June  30,				Nine Months Ended June  30,
	2011		2010		2011		2010
Derivatives in fair value hedging relationships:
Commodity(a)	$	0.2	$	3.2	$	9.5	$	9.2
Debt (b)		6.8		2.1		4.8		1.5
Total	$	7.0	$	5.3	$	14.3	$	10.7

	Amount of Gain (Loss) Recognized in Net Income on Item Being Hedged
	Three Months Ended June  30,						Nine Months Ended June  30,
	2011			2010			2011			2010
Derivatives in fair value hedging relationships:
Commodity(a)	$	0.1		$	(3.1	)	$	(9.2	)	$	(8.8	)
Debt (b)		(6.8	)		(2.1	)		(4.8	)		(1.5	)
Total	$	(6.7	)	$	(5.2	)	$	(14.0	)	$	(10.3	)

17

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

	Amount of Gain (Loss) Recognized in OCI on Effective Portion of Derivatives
	Three Months Ended June  30,						Nine Months Ended June  30,
	2011			2010			2011			2010
Derivatives in cash flow hedging relationships:
Commodity(c)	$	0.1		$	(3.8	)	$	0.5		$	(3.9	)
Debt(e)		(2.0	)		—			(2.0	)		—
Total	$	(1.9	)	$	(3.8	)	$	(1.5	)	$	(3.9	)

	Amount of Gain (Loss) Reclassified from OCI to Net Income
	Three Months Ended June 30,				Nine Months Ended June 30,
	2011		2010		2011		2010
Derivatives in cash flow hedging relationships:
Commodity(c)	$	1.0	$	0.5	$	4.9	$	11.8

	Amount of Gain (Loss) Recognized in Net Income on Ineffective Portion of Derivatives and Amount Excluded from Testing
	Three Months Ended June 30,				Nine Months Ended June 30,
	2011		2010		2011		2010
Derivatives in cash flow hedging relationships:
Commodity(c)	$	—	$	—	$	—	$	—

	Amount of Gain (Loss) Recognized in Net Income from Derivatives
	Three Months Ended June 30,				Nine Months Ended June 30,
	2011		2010		2011		2010
Derivatives not designated as hedging instruments:
Commodity (d)	$	5.5	$	3.8	$	11.2	$	10.4

(a) The gain (loss) on both the derivative and the item being hedged are located in cost of product sold in the consolidated statements of operations.

(b) The gain (loss) on both the derivative and the item being hedged are located in interest expense in the consolidated statements of operations.

(c) The gain (loss) on the amount reclassified from OCI into income, the ineffective portion and the amount excluded from effectiveness testing are included in cost of product sold.

(d) The gain (loss) is recognized in cost of product sold.

(e) The gain (loss) on the amount reclassified from OCI into income, the ineffective portion and the amount excluded from effectiveness testing are included in interest expense.

Credit Risk

Inherent in the Company’s contractual portfolio are certain credit risks. Credit risk is the risk of loss from nonperformance by suppliers, customers or financial counterparties to a contract. Inergy takes an active role in managing credit risk and has established control procedures, which are reviewed on an ongoing basis. The Company attempts to minimize credit risk exposure through credit policies and periodic monitoring procedures as well as through customer deposits, letters of credit and entering into netting agreements that allow for offsetting counterparty receivable and payable balances for certain financial transactions, as deemed appropriate. The counterparties associated with assets from price risk management activities as of June 30, 2011 and September 30, 2010, were energy marketers and propane retailers, resellers and dealers.

18

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Certain of the Company’s derivative instruments have credit limits that require the Company to post collateral. The amount of collateral required to be posted is a function of the net liability position of the derivative as well as the Company’s established credit limit with the respective counterparty. If the Company’s credit rating were to change, the counterparties could require the Company to post additional collateral. The amount of additional collateral that would be required to be posted would vary depending on the extent of change in the Company’s credit rating as well as the requirements of the individual counterparty. The aggregate fair value of all commodity derivative instruments with credit-risk-related contingent features that are in a liability position on June 30, 2011, is $7.5 million for which the Company has posted no collateral in the normal course of business. The Company has received collateral of $3.8 million in the normal course of business. All collateral amounts have been netted against the asset or liability with the respective counterparty.

Note 6 – Fair Value Measurements

FASB Accounting Standards Codification Subtopic 820-10 (“820-10”) establishes a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1 measurement) and the lowest priority to unobservable inputs (level 3 measurement). The three levels of the fair value hierarchy are as follows:

• Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 primarily consists of financial instruments such as exchange-traded derivatives, listed equities and US government treasury securities.

• Level 2 – Pricing inputs are other than quoted prices in active markets included in level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange-traded derivatives such as over the counter (“OTC”) forwards, options and physical exchanges.

• Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value.

As of June 30, 2011, the Company held certain assets and liabilities that are required to be measured at fair value on a recurring basis. These included the Company’s derivative instruments related to propane, heating oil, crude oil, natural gas liquids and interest rates as well as the portion of inventory that is hedged in a qualifying fair value hedge. The Company’s derivative instruments consist of forwards, swaps, futures, physical exchanges and options.

Certain of the Company’s derivative instruments are traded on the NYMEX. These instruments have been categorized as level 1.

The Company’s derivative instruments also include OTC contracts, which are not traded on a public exchange. The fair values of these derivative instruments are determined based on inputs that are readily available in public markets or can be derived from information available in publicly quoted markets. These instruments have been categorized as level 2.

The Company’s inventory that is the hedged item in a qualifying fair value hedge is valued based on prices quoted from observable sources and verified with broker quotes. This inventory has been categorized as level 2.

The Company’s OTC options are valued based on an internal option model. The inputs utilized in the model are based on publicly available information as well as broker quotes. These options have been categorized as level 3.

19

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

The assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. The following table sets forth by level within the fair value hierarchy the Company’s assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2011 and September 30, 2010 (in millions):

	June 30, 2011
	Fair Value of Derivatives
	Level 1		Level 2		Level 3		Total		Designated as Hedges		Not Designated as Hedges		Netting Agreements(a)			Total
Assets
Assets from price risk management	$	0.2	$	18.9	$	3.9	$	23.0	$	5.5	$	17.5	$	(9.4	)	$	13.6
Inventory		—		94.1		—		94.1		—		—		—			94.1
Interest rate swaps		—		4.8		—		4.8		4.8		—		—			4.8
Total assets at fair value	$	0.2	$	117.8	$	3.9	$	121.9	$	10.3	$	17.5	$	(9.4	)	$	112.5
Liabilities
Liabilities from price risk management	$	0.2	$	11.6	$	3.6	$	15.4	$	3.2	$	12.2	$	1.1		$	16.5
Interest rate swap		—		2.0		—		2.0		2.0		—		—			2.0
Total liabilities at fair value	$	0.2	$	13.6	$	3.6	$	17.4	$	5.2	$	12.2	$	1.1		$	18.5

	September 30, 2010
	Fair Value of Derivatives
	Level 1		Level 2		Level 3		Total		Designated as Hedges		Not Designated as Hedges		Netting Agreements(a)			Total
Assets
Assets from price risk management	$	0.6	$	26.6	$	1.5	$	28.7	$	6.6	$	22.1	$	(6.2	)	$	22.5
Inventory		—		82.6		—		82.6		—		—		—			82.6
Total assets at fair value	$	0.6	$	109.2	$	1.5	$	111.3	$	6.6	$	22.1	$	(6.2	)	$	105.1
Liabilities
Liabilities from price risk management	$	0.7	$	16.7	$	1.9	$	19.3	$	6.9	$	12.4	$	5.0		$	24.3

^(a)  Amounts represent the impact of legally enforceable master netting agreements that allow the Company to settle positive and negative positions as well as cash collateral held or placed with the same counterparties.

20

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

For assets and liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3) during the period, 820-10 requires a reconciliation of the beginning and ending balances, separated for each major category of assets. The reconciliation is as follows (in millions):

	Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
	Nine Months Ended June 30, 2011
Beginning balance	$	(0.4	)
Beginning balance recognized during the period		0.5
Change in value of contracts executed during the period		0.2
Ending balance	$	0.3

Note 7 – Long-Term Debt

Long-term debt consisted of the following at June 30, 2011 and September 30, 2010, respectively (in millions):

	June 30, 2011			September 30, 2010
Credit agreement:
Term loan facility	$	300.0		$	—
Senior unsecured notes		1,466.1			1,650.0
Bond/swap premium		2.6			10.4
Fair value hedge adjustment on senior unsecured notes		4.8			—
Bond discount		(6.9	)		(16.0	)
Obligations under noncompetition agreements and notes to former owners of businesses acquired		19.6			21.8
Holdings term loan		—			24.5
Total debt		1,786.2			1,690.7
Less: current portion		4.5			29.6
Total long-term debt	$	1,781.7		$	1,661.1

On November 24, 2009, Inergy entered into a secured credit facility (“Credit Agreement”) which provides borrowing capacity of up to $525 million in the form of a $450 million revolving general partnership credit facility (“General Partnership Facility”) and a $75 million working capital credit facility (“Working Capital Facility”). This facility will mature on November 22, 2013. Borrowings under these secured facilities are available for working capital needs, future acquisitions, capital expenditures and other general partnership purposes, including the refinancing of existing indebtedness under the former credit facility.

On February 2, 2011, Inergy amended and restated the Credit Agreement to add a $300 million term loan facility (the “Term Loan Facility”). The term loan matures on February 2, 2015, and bears interest, at Inergy’s option, subject to certain limitations, at a rate equal to the following:

• the Alternate Base Rate, which is defined as the higher of i) the federal funds rate plus 0.50%; ii) JP Morgan’s prime rate; or iii) the Adjusted LIBO Rate plus 1%; plus a margin varying from 1.00% to 2.25%; or

• the Adjusted LIBO Rate, which is defined as the LIBO Rate plus a margin varying from 2.00% to 3.25%.

21

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

The Credit Agreement contains various affirmative and negative covenants and default provisions, as well as requirements with respect to the maintenance of specified financial ratios and limitations on making investments, permitting liens and entering into other debt obligations. All borrowings under the General Partnership Facility and Working Capital Facility bear interest, at Inergy’s option, subject to certain limitations, at a rate equal to the following:

• the Alternate Base Rate, which is defined as the higher of i) the federal funds rate plus 0.50%; ii) JP Morgan’s prime rate; or iii) the Adjusted LIBO Rate plus 1%; plus a margin varying from 1.50% to 2.75%; or

• the Adjusted LIBO Rate, which is defined as the LIBO Rate plus a margin varying from 2.50% to 3.75%.

On January 19, 2011, Inergy announced the pricing of $750 million in aggregate principal amount of senior unsecured notes (the “Notes Offering”). The 6.875% notes mature on August 1, 2021, and were issued at par. The Notes Offering closed on February 2, 2011.

Inergy used the net proceeds from the Notes Offering and the Term Loan Facility to: (1) fund its partial redemption of its 8.75% Senior Notes due 2015 (the “2015 Notes”); (2) fund its tender offers for portions of the (a) 6.875% Senior Notes due 2014 (the “2014 Notes”), (b) 2015 Notes outstanding upon completion of the partial redemption of the 2015 Notes, and (c) 8.25% Senior Notes due 2016 (the “2016 Notes”); and (3) redeem all 2014 Notes and 2016 Notes not acquired in the tender offers related to such notes. The remaining net proceeds were used to repay outstanding borrowings under the General Partnership Facility and the Working Capital Facility and to provide additional working capital for general partnership purposes. The charges to net income associated with the tender offer and redemption were $49.6 million.

At June 30, 2011, the balance outstanding under the Credit Agreement was $300.0 million, all of which was borrowed under the Term Loan Facility. At September 30, 2010, there was no balance outstanding under the Credit Agreement. The interest rate on the Term Loan Facility is based on LIBOR plus the applicable spread, resulting in an interest rate that was 3.44% at June 30, 2011. Availability under the Credit Agreement amounted to $481.5 million and $505.3 million at June 30, 2011 and September 30, 2010, respectively. Outstanding standby letters of credit under the Credit Agreement amounted to $43.5 million and $19.7 million at June 30, 2011 and September 30, 2010, respectively.

During each fiscal year beginning October 1, the outstanding balance of the Working Capital Facility must be reduced to $10.0 million or less for a minimum of 30 consecutive days during the period commencing March 1 and ending September 30 of each calendar year. This requirement was met in April 2011.

During fiscal year 2011, Inergy entered into eleven interest rate swaps, one of which is scheduled to mature in 2015 and the remaining ten are scheduled to mature in 2018. 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 Inergy an amount based on the stated fixed interest rate due every six months. In exchange, Inergy is required to make semi-annual floating interest rate payments on the same dates to the counterparty based on an annual interest rate equal to the six-month LIBOR interest rate plus a spread of 6.705% on the swap maturing in 2015 and 3.25% to 3.46% on the swaps maturing in 2018 applied to the same aggregate notional amount of $275 million. These swap agreements have been accounted for 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.

In addition, during fiscal year 2011, Inergy entered into three interest rate swap agreements scheduled to mature in 2015. These swap agreements, which expire on the same date as the maturity date of the related Term Loan Facility require Inergy to pay the counterparty an amount based on fixed rates from 2.136% to 2.43% due quarterly. In exchange, the counterparty is required to make quarterly floating interest rate payments on the same date to Inergy based on the three-month LIBOR applied to the same aggregate notional amount of $100 million. These swap agreements have been accounted for as cash flow hedges.

22

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Prior to the completion of the Simplification Transaction, Holdings had a balance of $24.5 million on its term loan facility and no balance on its revolving bank facility. In conjunction with the Simplification Transaction, the above described debt balances were paid off in full and these facilities were terminated.

At June 30, 2011, the Company was in compliance with all debt covenants.

Note 8 – Partners’ Capital

Common Unit Offering

On June 6, 2011, Inergy issued 9,000,000 common units in a public offering. Inergy used the net proceeds from this offering to repay borrowings under its revolving general partnership and working capital credit facilities, to fund ongoing expansion projects in its midstream business and for general partnership purposes.

Merger Conversion of Units

All unit and per unit amounts have been revised to reflect the conversion of Holdings common units to 0.77 Inergy common units as a result of the Merger (discussed in Note 1), which closed on November 5, 2010.

Class B Units

The Class B units have similar rights and obligations of Inergy common units except that the units will pay distributions in kind rather than in cash for a certain period of time. During the three-month period ended March 31, 2011, Inergy distributed 195,652 Class B units. During the three-month period ended June 30, 2011, Inergy distributed 198,961 Class B units. For a complete description of the Class B units, please see the Third Amended and Restated Agreement of Limited Partnership of Inergy, filed on Form 8-K on November 5, 2010.

Quarterly Distributions of Available Cash

A summary of Holdings limited partner quarterly distributions for the three months ended December 31, 2010 and 2009, is presented below:

	Three Months Ended December 31,
	2010		2009
Record date		October 22, 2010		November 6, 2009
Payment date		October 29, 2010		November 13, 2009
Per unit rate	$	0.442	$	0.368
Distribution amount (in millions)	$	21.1	$	17.2

A summary of Inergy’s limited partner quarterly distributions for the three months ended December 31, 2010 and 2009, is presented below:

	Three Months Ended December 31,
	2010		2009
Record date		October 22, 2010		November 6, 2009
Payment date		October 29, 2010		November 13, 2009
Per unit rate	$	0.705	$	0.675
Distribution amount (in millions)	$	76.1	$	55.2

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INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

A summary of the Company’s post-simplification limited partner quarterly distribution for the six months ended June 30, 2011 and 2010, is presented below:

Six Months Ended June 30, 2011
Record Date	Payment Date	Per Unit Rate		Distribution Amount (in millions)
February 7, 2011	February 14, 2011	$	0.705	$	77.4
May 6, 2011	May 13, 2011	$	0.705		77.6
				$	155.0
Six Months Ended June 30, 2010 (a)
Record Date	Payment Date	Per Unit Rate		Distribution Amount (in millions)
February 5, 2010	February 12, 2010		N/A	$	61.2
May 7, 2010	May 14, 2010		N/A		62.5
				$	123.7

(a) In the Simplification Transaction, Holdings was the surviving entity for accounting purposes, for comparative purpose, the prior year amount represents the aggregate Holdings limited partner quarterly distributions of both Holdings and Inergy. The aggregate distribution amount excludes all distributions from Inergy to Holdings.

On July 25, 2011, Inergy declared a distribution of $0.705 per limited partner unit to be paid on August 12, 2011, to unitholders of record on August 5, 2011, for a total distribution of $84.0 million with respect to the third fiscal quarter of 2011.

Note 9 – 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, 2011, the total of these firm purchase commitments was $129.9 million, the majority of which will occur over the course of the next twelve months. The Company also enters into non-binding agreements with suppliers to purchase quantities of propane, distillates, natural gas and liquids at variable prices at future dates at the then prevailing market prices.

Inergy has entered into certain purchase commitments in connection with the identified growth projects primarily related to the North/South Pipeline, Finger Lakes LPG and the MARC I Hub Line midstream assets. The North/South Project consists of adding additional compression and measurement facilities to our existing Stagecoach Laterals, which when completed is expected to have firm transportation capacity of 325,000 dekatherms per day. The Finger Lakes LPG expansion project is expected to convert certain of the US Salt caverns into LPG storage with a capacity of up to 5 million barrels. The MARC I Hub Line Project is a 40 mile, 30" bi-directional pipeline that will extend between our Stagecoach South Lateral interconnect with Tennessee Gas Pipeline Company's ("TGP") 300 Line near its compressor station 319 and Transco’s Leidy Line near its compressor station 517, and is expected to have a minimum of 550,000 dekatherms per day of firm transportation capacity. At June 30, 2011, the total of these firm purchase commitments was approximately $60.2 million and the majority of the purchases associated with these commitments are expected to occur over the course of the next twelve months.

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

24

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Following the announcement of the Merger Agreement, two unitholder class action lawsuits were filed as described in Item 3 of form 10-K as filed with the Securities and Exchange Commission for the fiscal year ended September 30, 2010. The outcome of these lawsuits cannot be predicted with certainty; however, management believes that Inergy does not have material potential liability in connection with these proceedings that would have a significant financial impact on its consolidated financial condition, results of operations or cash flows.

Inergy utilizes third-party insurance subject to varying retention levels of self-insurance, which management considers prudent. Such self-insurance relates to losses and liabilities primarily associated with medical claims, workers’ compensation claims and general, product, vehicle and environmental liability. Losses are accrued based upon management’s estimates of the aggregate liability for claims incurred using certain assumptions followed in the insurance industry and based on past experience. The primary assumption utilized is actuarially determined loss development factors. The loss development factors are based primarily on historical data. Inergy’s self insurance reserves could be affected if future claims development differs from the historical trends. Inergy believes changes in health care costs, trends in health care claims of its employee base, accident frequency and severity and other factors could materially affect the estimate for these liabilities. Inergy continually monitors changes in employee demographics, incident and claim type and evaluates its insurance accruals and adjusts its accruals based on its evaluation of these qualitative data points. At June 30, 2011 and September 30, 2010, Inergy’s self-insurance reserves were $20.3 million and $19.3 million, respectively. Inergy estimates that $13.4 million of this balance will be paid subsequent to June 30, 2012. As such, $13.4 million has been classified in other-long-term liabilities on the consolidated balance sheets.

Note 10 – 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 and natural gas liquids for third parties, fractionation of natural gas liquids, processing of natural gas, distribution of natural gas liquids and the production and sale of salt. Results of operations for Schenck and Pennington are included in the propane segment, while results of operations for Tres Palacios are included in the midstream segment.

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

25

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

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

	Three Months Ended June 30, 2011
	Propane Operations		Midstream Operations		Intersegment Operations			Corporate Assets		Total
Retail propane revenues	$	120.1	$	—	$	—		$	—	$	120.1
Wholesale propane revenues		88.8		11.5		—			—		100.3
Storage, fractionation and other midstream revenues		—		123.1		(1.9	)		—		121.2
Transportation revenues		6.7		4.1		—			—		10.8
Propane-related appliance sales revenues		4.1		—		—			—		4.1
Retail service revenues		3.9		—		—			—		3.9
Rental service and other revenues		5.7		—		—			—		5.7
Distillate revenues		22.6		—		—			—		22.6
Gross profit		72.2		46.9		(2.1	)		—		117.0
Identifiable assets		205.6		80.7		—			—		286.3
Goodwill		335.1		141.3		—			20.2		496.6
Property, plant and equipment		785.3		1,707.4		—			12.0		2,504.7
Expenditures for property, plant and equipment		3.8		60.1		—			—		63.9

	Three Months Ended June 30, 2010
	Propane Operations		Midstream Operations		Intersegment Operations			Corporate Assets		Total
Retail propane revenues	$	104.3	$	—	$	—		$	—	$	104.3
Wholesale propane revenues		57.5		6.0		—			—		63.5
Storage, fractionation and other midstream revenues		—		82.6		(0.2	)		—		82.4
Transportation revenues		5.0		3.1		—			—		8.1
Propane-related appliance sales revenues		4.9		—		—			—		4.9
Retail service revenues		3.9		—		—			—		3.9
Rental service and other revenues		6.4		—		—			—		6.4
Distillate revenues		18.1		—		—			—		18.1
Gross profit		71.5		33.2		(0.2	)		—		104.5
Identifiable assets		141.5		53.3		—			—		194.8
Goodwill		367.1		96.4		—			20.2		483.7
Property, plant and equipment		809.9		898.9		—			11.6		1,720.4
Expenditures for property, plant and equipment		3.6		8.4		—			0.7		12.7

26

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

	Nine Months Ended June 30, 2011
	Propane Operations		Midstream Operations		Intersegment Operations			Corporate Assets		Total
Retail propane revenues	$	747.2	$	—	$	—		$	—	$	747.2
Wholesale propane revenues		413.8		27.0		(0.1	)		—		440.7
Storage, fractionation and other midstream revenues		—		329.7		(2.6	)		—		327.1
Transportation revenues		15.0		13.1		—			—		28.1
Propane-related appliance sales revenues		15.5		—		—			—		15.5
Retail service revenues		13.1		—		—			—		13.1
Rental service and other revenues		21.4		—		—			—		21.4
Distillate revenues		112.1		—		—			—		112.1
Gross profit		431.6		136.0		(2.9	)		—		564.7
Identifiable assets		205.6		80.7		—			—		286.3
Goodwill		335.1		141.3		—			20.2		496.6
Property, plant and equipment		785.3		1,707.4		—			12.0		2,504.7
Expenditures for property, plant and equipment		11.4		123.1		—			0.4		134.9

	Nine Months Ended June 30, 2010
	Propane Operations		Midstream Operations		Intersegment Operations			Corporate Assets		Total
Retail propane revenues	$	697.1	$	—	$	—		$	—	$	697.1
Wholesale propane revenues		372.5		22.1		(0.1	)		—		394.5
Storage, fractionation and other midstream revenues		—		218.7		(0.9	)		—		217.8
Transportation revenues		13.7		13.3		—			—		27.0
Propane-related appliance sales revenues		17.2		—		—			—		17.2
Retail service revenues		13.2		—		—			—		13.2
Rental service and other revenues		20.6		—		—			—		20.6
Distillate revenues		97.0		—		—			—		97.0
Gross profit		423.4		96.9		(0.9	)		—		519.4
Identifiable assets		141.5		53.3		—			—		194.8
Goodwill		367.1		96.4		—			20.2		483.7
Property, plant and equipment		809.9		898.9		—			11.6		1,720.4
Expenditures for property, plant and equipment		10.7		51.9		—			1.1		63.7

Note 11 – Subsequent Events

The Company has identified subsequent events requiring disclosure through the date of the filing of this Form 10-Q.

On July 13, 2011, Inergy closed on its previously announced acquisition of the Seneca Lake natural gas storage facility located in Schuyler County, New York, and two related pipelines for approximately $65 million from New York State Electric & Gas Corporation. The natural gas storage facility and its West lateral were acquired by Arlington Storage Company, LLC (“ASC”) and are subject to FERC jurisdiction. The East lateral was acquired by Inergy Pipeline East, LLC and is subject to light-handed regulation by the New York Public Service Commission.

27

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

On July 25, 2011, Inergy declared a distribution of $0.705 per limited partner unit to be paid on August 12, 2011, to unitholders of record on August 5, 2011, for a total distribution of $84.0 million with respect to the third fiscal quarter of 2011.

On July 28, 2011, Inergy amended its amended and restated Credit Agreement to (i) raise the aggregate revolving commitment from $525 million to $700 million, (ii) reduce the applicable rate on revolving loans and commitment fees, (iii) modify and refresh certain covenants and covenant baskets, and (iv) extend the maturity date from November 22, 2013 to July 28, 2016.

In August 2011, Inergy’s ten interest rate swaps maturing in 2018 were terminated, and the Company received approximately $14.3 million in proceeds. These swaps had an aggregate notional amount of $250 million.

On August 9, 2011, Inergy announced that it plans to file a registration statement for an initial public offering of a minority interest of the common units of a new master limited partnership to be named Inergy Midstream, L.P. (the “MLP”). The MLP will be formed to initially own and operate Inergy’s northeast U.S. midstream storage and transportation business.

28

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 of Inergy, L.P. for the fiscal year ended September 30, 2010.

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 (“Reform Act”). Such forward-looking statements include, but are not limited to, statements that: (i) the North/South Pipeline project is expected to have firm transportation capacity of 325,000 dekatherms per day and the Finger Lakes LPG expansion project is expected to convert certain of the US Salt caverns into LPG storage with a capacity of up to 5 million barrels, (ii) management believes that Inergy does not have material potential liability in connection with the unitholder class action lawsuits that would have a significant financial impact on its consolidated financial condition, results of operations or cash flows, (iii) we believe that volatility in commodity prices will continue, and our ability to adjust to and manage our operations in response to this volatility may impact our operations and financial results, (iv) we believe that the economic downturn that began in the second half of 2008 has caused certain of our retail propane customers to conserve and thereby purchase less propane, (v) we believe our midstream operations could be negatively affected in the long term by sustained downturns or sluggishness in the economy, which could affect long-term demand and market prices for natural gas and NGLs, (vi) we anticipate completion of our announced midstream capital expansion projects at various times in 2011 and 2012, and (vii) we believe that anticipated cash from operations and borrowings under our credit facility will be sufficient to meet our liquidity needs for the foreseeable future. Such forward-looking statements involve risks, uncertainties and other factors which may cause the actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements. Such factors include, but are not limited to, the following: weather in our area of operations; market price of propane; availability of financing; changes in, or failure to comply with, government regulations; the costs, uncertainties and other effects of legal and administrative proceedings and other risks and uncertainties detailed in our Securities and Exchange Commission filings. For those statements, we claim the protections of the safe harbor for forward-looking statements contained in the Reform Act. We will not undertake and specifically decline any obligation to publicly release the result of any revisions to any forward-looking statements to reflect events or circumstances after the date of such statements or to reflect events or circumstances after anticipated or unanticipated events.

Overview

We are a growing retail and wholesale propane supply, marketing and distribution business. We also own and operate a growing midstream business that includes five natural gas storage facilities (“Stagecoach”, “Thomas Corners”, “Steuben”, “Seneca Lake” and “Tres Palacios”), a liquefied petroleum gas (“LPG”) storage facility (“Finger Lakes LPG”), a natural gas liquids (“NGL”) business and a solution-mining and salt production company (“US Salt”). We further intend to pursue our growth objectives in the propane and midstream business through, among other things, future acquisitions. Our propane acquisition strategy focuses on propane companies that meet our acquisition criteria, including targeting acquisition prospects that maintain a high percentage of retail sales to residential customers, operating in attractive markets and focusing our operations under established and locally recognized trade names. Our midstream growth objectives focus both on organically expanding our existing assets and acquiring future operations that leverage our existing operating platform, produce predominantly fee-based cash flow characteristics and have future organic or commercial expansion characteristics.

Both of our operating segments, propane and midstream, are supported by business development personnel groups. These groups’ daily responsibilities include research, sourcing, financial analysis and due diligence of potential acquisition targets and organic growth opportunities. These employees work closely with the operators of both of our segments in the course of their work to ensure the appropriate growth opportunities are pursued.

29

We have grown primarily through acquisitions. Since the inception of our predecessor in November 1996 through June 30, 2011, we have acquired 89 companies, including 82 retail propane companies and 7 midstream businesses, for an aggregate purchase price of approximately $2.9 billion, including working capital, assumed liabilities and acquisition costs.

On October 14, 2010, we completed the acquisition of Tres Palacios Gas Storage LLC (“Tres Palacios”), which owns and operates a natural gas storage facility located in Matagorda County, Texas. Tres Palacios leases the surface and subsurface rights necessary to operate and expand the storage facility under an operating lease that expires on December 31, 2037, which is subject to automatic renewal for two 20-year extension periods unless Tres Palacios elects not to extend the term of the lease. The lease payments vary based on the FERC-certificated working gas capacity of the caverns which are in service as well as an incremental payment for physical volumes of gas injected and / or withdrawn from the caverns in service. Based on our current estimates, which assumes cavern 4 will be in service during the second fiscal quarter of 2014, we anticipate that the contractual obligation as of June 30, 2011, to be the following (in millions, excluding the above mentioned incremental payments as future volumes are currently unknown):

Total	Less than 1 year		1-3 years		4-5 years		After 5 years
$ 406.7	$	11.4	$	24.5	$	31.3	$	339.5

On October 19, 2010, we completed the acquisition of the propane assets of Schenck Gas Services, LLC (“Schenck”), located in East Hampton, New York. On November 15, 2010, we completed the acquisition of the propane assets of Pennington Energy Corporation (“Pennington”), headquartered in Morenci, Michigan. Most recently, on July 13, 2011, we acquired the Seneca Lake natural gas storage facility and two related pipeline laterals from NYSEG.

The purchase price allocations for these acquisitions have been prepared on a preliminary basis pending final asset valuation and asset rationalization, and changes are expected when additional information becomes available. Changes to final asset valuation of prior fiscal year acquisitions have been included in our consolidated financial statements but are not material.

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

Because a substantial portion of our propane is used in the weather-sensitive residential markets, the temperatures realized in our areas of operations, particularly during the six-month peak heating season of October through March, have a significant effect on our financial performance. In any given area, warmer-than-normal temperatures will tend to result in reduced propane use, while sustained colder-than-normal temperatures will tend to result in greater propane use. Therefore, we use information on normal temperatures in understanding how historical results of operations are affected by temperatures that are colder or warmer than normal and in preparing forecasts of future operations, which are based on the assumption that normal weather will prevail in each of our operating regions. “Heating degree days” are a general indicator of how weather impacts propane usage and are calculated for any given period by adding the difference between 65 degrees and the average temperature of each day in the period (if less than 65 degrees). While a substantial portion of our propane is used by our customers for heating needs, our propane operations are geographically diversified and not all of our propane sales are weather sensitive. Together, these factors may make it difficult to draw definitive conclusions as to the correlation of our gallon sales to weather calculations comparing weather in a year to normal or to the prior year.

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. Propane prices continued to be volatile during 2010 and thus far in 2011. At the main pricing hub of Mount Belvieu, Texas (“Mt. Belvieu Price”) during the three-month period ended June 30, 2011, the average Mt. Belvieu Price was $1.50 with prices ranging from a low of $1.38 per gallon to a high of $1.62 per gallon and a price of $1.49 per gallon at June 30, 2011. During the nine-month period ended June 30, 2011, the average propane price was $1.38 with propane prices ranging from a low of $1.17 per gallon to a high of $2.29 per gallon. Further the average Mt. Belvieu Price in our fiscal years of 2008, 2009 and 2010 was $1.59, $0.77 and $1.12 per gallon, respectively. Our ability to pass on price increases to our customers and our hedging program has historically limited the impact that such volatility has had on our results from operations and we will continue to hedge virtually 100% of our exposure from fixed prices; however, those higher propane costs have led to higher selling prices by us and have negatively impacted our volume sales and may continue to do so in the future for reasons discussed below. While we have historically been successful in passing on any price increases to our customers, there can be no guarantees that this trend

30

will continue in the future. In periods of increasing propane costs, we have experienced a decline in our gross profit as a percentage of revenues. In addition, during those periods we have historically experienced conservation of propane gallons used by our customers in addition to lesser gallon sales as a result of customers switching to lower price propane providers as well as alternative energy sources, all of which has resulted in a decline in gross profit. These trends generally increase in periods of sustained cost increases such as we have experienced thus far in fiscal 2011. Further, improved technology in new appliances, including those using propane, has resulted in fewer gallons of propane used by our customers for their needs thus resulting in lesser gallon sales for us. In periods of decreasing costs, we have experienced an increase in our gross profit as a percentage of revenues. There is no assurance that because propane prices decline customers will use more propane and thus historical gallon sales declines we’ve attributed to customer conservation and losses will reverse. Propane is a by-product of both crude oil refining and natural gas processing and thus typically follows the same pricing pattern as these two commodities with crude oil pricing being the more influential of the two historically. The prices of crude oil and natural gas had maintained historically high costs in calendar years 2007 and 2008 before both began to fall rather dramatically in late 2008 and throughout the 2008-2009 winter season. While natural gas pricing has remained at historically low levels since this decline, crude oil costs leveled off in the spring of 2009 before beginning another increase that persisted through both winter seasons of 2009-2010 and 2010-2011 with propane prices following a similar pattern for the majority of this time. As such, our selling prices of propane have been at higher levels in order to attempt to maintain our historical gross margin per gallon with these higher prices negatively impacting our volume sales for the reasons discussed above. We do not attempt to predict the underlying commodity prices; however, we monitor these prices daily and adjust our operations and retail prices to maintain expected margins by passing on the wholesale costs to end users of our product. We believe that volatility in commodity prices will continue, and our ability to adjust to and manage our operations in response to this volatility may impact our operations and financial results.

We believe that the economic downturn that began in the second half of 2008 has caused certain of our retail propane customers to conserve and thereby purchase less propane and in some instances shop for lower prices that may be available from other suppliers or shop for alternative energy sources to replace some or all of their propane usage. This trend is expected to continue throughout the life of the economic downturn. In addition, although we believe the economic downturn has not currently had a material impact on our cash collections, it is possible that a prolonged economic downturn could have a negative impact on our future cash collections.

We believe our wholesale supply, marketing and distribution business complements our retail distribution business. Through our wholesale operations, we distribute propane and also offer price risk management services to propane retailers, resellers and other related businesses as well as energy marketers and dealers, through a variety of financial and other instruments, including:

• forward contracts involving the physical delivery of propane;

• swap agreements which requires payments to (or receipt of payments from) counterparties based on the differential between a fixed and variable price for propane; and

• options, futures contracts on the New York Mercantile Exchange and other contractual arrangements.

We engage in derivative transactions to reduce the effect of price volatility on our product costs and to help ensure the availability of propane during periods of short supply. We attempt to balance our contractual portfolio by purchasing volumes only when we have a matching purchase commitment from our wholesale customers. However, we may experience net unbalanced positions from time to time.

Our midstream operations primarily include the storage, processing, fractionation and sale of natural gas and NGLs and, to a lesser extent, the wholesale distribution of salt from solution mining operations of US Salt. The cash flows from these operations are predominantly fee-based under one to ten year contracts with substantial, creditworthy counterparties and, therefore, are generally economically stable and not significantly affected in the short term by changing commodity prices, seasonality or weather fluctuations.

The majority of our operating cash flows in our midstream operations are generated by our natural gas storage operations. Most of our natural gas storage revenues are based on regulated market-based tariff rates, which are driven in large part by competition and demand for our storage capacity and deliverability. Demand for storage in our key midstream market in the northeastern United States is projected to continue to be strong, driven by a shortage in storage capacity and a higher than average annual growth in natural gas demand. This demand growth is primarily driven by the natural gas-fired

31

electric generation sector and conversion from petroleum based fuels. Demand for storage in Texas is expected to strengthen driven primarily by growth in natural gas fired generation and increasing gas supplies from growing shale developments such as the Eagle Ford shale. Demand for storage can be negatively impacted during periods in which there is a narrow seasonal spread between current and future natural gas prices. The natural gas industry is currently experiencing a significant shift in the sources of supply, and this dramatic change could affect our operations.

We believe our midstream operations could be negatively affected in the long term by sustained downturns or sluggishness in the economy, which could affect long-term demand and market prices for natural gas and NGLs, all of which are beyond our control and could impair our ability to meet our long-term goals. However, we also believe that the contractual fee-based nature of our midstream operations may serve to mitigate this potential risk.

Traditionally, supply to our markets has come from the Gulf Coast region, onshore and offshore, as well as from Canada. The national supply profile is shifting to new sources of natural gas from basins in the Rockies, Mid-Continent, Appalachia and East Texas. In addition, the natural gas supply outlook includes new LNG regasification facilities under various stages of development in multiple locations. LNG can be a new source of potential supply, but the timing and extent of incremental supply ultimately realized from LNG is yet to be determined and, at present, LNG remains a small percentage of the overall supply to the markets we serve. These supply shifts and other changes to the natural gas market may have an impact on our storage operations and our development plans and may ultimately drive the need for more domestic capacity for natural gas storage.

Currently, we have three significant capital projects related to our midstream operations: (1) Finger Lakes LPG storage expansion, (2) North/South Pipeline Project and (3) MARC I Hub Line Project. The Finger Lakes LPG storage expansion project relates to the development of certain caverns acquired in the acquisition of US Salt in August 2008. The solution mining process creates caverns that can be developed into LPG or natural gas storage after the salt has been extracted. The Finger Lakes LPG expansion project, which is located in Watkins Glenn, New York, is expected to convert certain of the caverns at US Salt into LPG storage with a capacity of up to 5 million barrels. While we anticipate completion of this project in the first half of fiscal 2012, this completion continues to be pending regulatory approval, which approval progress thus far has been slow so there can be no assurance this completion date will be met.

The North/South Pipeline Project consists of adding additional compression and measurement facilities to our existing Stagecoach Laterals and when completed is expected to have firm transportation capacity of 325,000 dekatherms per day. We received the FERC approvals required for the project in January 2011, and commenced construction in February. The North/South Project is supported by long-term contracts and is expected to be placed into service by late 2011.

The MARC I Hub Line Project is a 40 mile, 30" bi-directional pipeline located in Bradford, Sullivan, and Lycoming counties in Pennsylvania. The planned pipeline will extend between our Stagecoach South Lateral interconnect with Tennessee Gas Pipeline Company's ("TGP") 300 Line near its compressor station 319 and Transco’s Leidy Line near its compressor station 517. The MARC I Hub Line Project is expected to have a minimum of 550,000 dekatherms per day of firm transportation capacity. The FERC issued an Environmental Assessment of the project on May 27, 2011 (including a recommendation that an order authorizing the project contain a “finding of no significant impact”), and the company and various interveners have filed comments in response to the EA. We expect the MARC I Hub Line Project to be placed into service in mid-2012.

Our MARC I Hub Line Project and the North/South Project, when placed into service, will allow us to wheel volumes on a firm transportation basis through approximately 75 miles of pipe to and from TPG’s 300 Line, Transco's Leidy Line and the Millennium Pipeline and all points in between. The two projects combined are expected to add over 55,000 horsepower of additional compression and 875,000 dekatherms per day of transportation capacity to our midstream business in the Northeast.

In connection with the Seneca Lake acquisition, ASC has filed an application and reservoir suitability report with the New York State Department of Environmental Conservation, in which ASC requests approval to expand the Seneca Lake gas storage facility to add 595,800 Mcf of additional working gas capacity.

As we execute on our strategic objectives, capital expansion projects will continue to be an important part of our growth plan. We have committed capital and investment expenditures at June 30, 2011, of approximately $60.2 million in our midstream operations. These capital requirements, along with the refinancings of normal maturities of existing debt, will

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require us to continue long-term borrowings. An inability to access capital at competitive rates could adversely affect our ability to implement our strategy. Market disruptions or a downgrade in our credit ratings may increase the cost of borrowing or adversely affect our ability to access one or more sources of liquidity. During the past several years, capital expansion projects have been exposed to cost pressures associated with the availability of skilled labor and the pricing of materials. Although certain costs have begun to decrease, there will be continual focus on project management activities to address these pressures as we move forward with planned expansion opportunities. Significant cost increases could negatively affect the returns ultimately earned on current and future expansions.

Our midstream operations in the United States are subject to regulations at the federal and state level. Regulations applicable to the gas and NGL storage industries have a significant effect on the nature of our midstream operations and the manner in which they operate. Changes to regulations are ongoing and we cannot predict the future course of changes in the regulatory environment or the ultimate effect that any future changes will have on our midstream operations.

Results of Operations

Three Months Ended June 30, 2011 Compared to Three Months Ended June 30, 2010

The following table summarizes the consolidated statement of operations components for the three months ended June 30, 2011 and 2010, respectively(in millions):

	Three Months Ended June 30,						Change
	2011			2010			In Dollars			Percentage
Revenue	$	388.7		$	291.6		$	97.1			33.3	%
Cost of product sold		271.7			187.1			84.6			45.2
Gross profit		117.0			104.5			12.5			12.0
Operating and administrative expenses		77.4			75.3			2.1			2.8
Depreciation and amortization		48.0			40.5			7.5			18.5
Loss on disposal of assets		0.5			2.1			(1.6	)		(76.2	)
Operating loss		(8.9	)		(13.4	)		4.5			33.6
Interest expense, net		(27.2	)		(23.1	)		(4.1	)		(17.7	)
Early extinguishment of debt		(0.2	)		—			(0.2	)		*
Other income		1.1			0.8			0.3			37.5
Loss before income taxes		(35.2	)		(35.7	)		0.5			1.4
Benefit (provision) for income taxes		(0.3	)		0.6			(0.9	)		(150.0	)
Net loss		(35.5	)		(35.1	)		(0.4	)		(1.1	)
Net loss attributable to non-controlling partners		—			47.5			(47.5	)		*
Net income (loss) attributable to partners	$	(35.5	)	$	12.4		$	(47.9	)		386.3	%

* Not meaningful

The following table summarizes revenues, including associated volume of gallons sold, for the three months ended June 30, 2011 and 2010, respectively (in millions):

	Revenues									Gallons
	Three Months Ended June 30,				Change					Three Months Ended June 30,				Change
	2011		2010		In Dollars		Percent			2011		2010		In Units		Percent
Propane
Retail propane	$	120.1	$	104.3	$	15.8		15.1	%		45.7		45.0		0.7		1.6	%
Wholesale propane		100.3		63.5		36.8		58.0			66.6		57.1		9.5		16.6
Other retail		43.0		38.3		4.7		12.3			—		—		—		—
Midstream		125.3		85.5		39.8		46.5			—		—		—		—
Total	$	388.7	$	291.6	$	97.1		33.3	%		112.3		102.1		10.2		10.0	%

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Volume.During the three months ended June 30, 2011, we sold 45.7 million retail gallons of propane, an increase of 0.7 million gallons or 1.6% from the 45.0 million retail gallons sold during the same three-month period in 2010. Gallons sold during the three months ended June 30, 2011, increased slightly as compared to the same prior year period as a result of acquisition-related volume of 1.5 million gallons, partially offset by lower volumes sold at our existing locations of 0.8 million gallons. During the three months ended June 30, 2011, we believe that retail propane gallon sales were impacted by several ongoing factors, including most notably customer conservation and high commodity prices.

Wholesale gallons delivered increased 9.5 million gallons, or 16.6%, to 66.6 million gallons in the three months ended June 30, 2011, from 57.1 million gallons in the three months ended June 30, 2010. The increase was due primarily to higher demand and volumes sold to existing and new customers.

The total natural gas liquid gallons sold or processed by our West Coast NGL operations increased 8.5 million gallons, or 9.9%, to 94.2 million gallons during the three months ended June 30, 2011, from 85.7 million gallons during the same three-month period in 2010. This increase was primarily attributable to increased volume processed and increased volume of natural gas liquid products sold. Both of the aforementioned changes were primarily due to local market conditions.

During the three months ended June 30, 2011 and 2010, our Northeast natural gas facility was 100% contracted on a firm basis, and our LPG storage facility was approximately 100% contracted. During the three months ended June 30, 2011 our newly acquired Tres Palacios storage facility was approximately 70% contracted on a firm and interruptible basis.

Revenues. Revenues for the three months ended June 30, 2011, were $388.7 million, an increase of $97.1 million, or 33.3%, from $291.6 million during the same three-month period in 2010.

Revenues from retail propane sales were $120.1 million for the three months ended June 30, 2011, compared to $104.3 million during the same three-month period in 2010. This $15.8 million, or 15.1%, increase was primarily due to a revenue improvement of $13.4 million arising from a higher overall average selling prices of propane and a $3.8 million increase resulting from acquisition-related sales, partially offset by a $1.4 million revenue decline due to lower gallons sold to existing customers as described above. The overall average selling price of propane increased due to an increase in the wholesale cost of propane as further discussed above.

Revenues from wholesale propane sales were $100.3 million in the three months ended June 30, 2011, an increase of $36.8 million or 58.0%, from $63.5 million in the three months ended June 30, 2010. The increase can be attributed to a higher average sales price, which contributed $25.7 million to the increase and $11.1 million in higher volumes sold to existing and new customers.

Revenues from other retail sales, which primarily includes distillates, service, rental, appliance sales and transportation services, were $43.0 million for the three months ended June 30, 2011, an increase of $4.7 million, or 12.3%, from $38.3 million during the same three-month period in 2010. Revenue from other retail sales rose primarily due to an increase in distillate revenues of $4.4 million and an increase in acquisition-related sales of $0.2 million. Distillate revenues from existing locations increased as a result of a higher comparable average selling price of distillates due to a higher wholesale cost, partially offset by lower volume sold.

Revenues from storage, fractionation and other midstream activities were $125.3 million for the three months ended June 30, 2011, an increase of $39.8 million or 46.5% from $85.5 million during the same three-month period in 2010. Revenues from our West Coast NGL operations increased $28.2 million primarily as a result of increased natural gas liquid products sold, along with higher average selling prices of natural gas liquids. Additionally, the acquisition of our Tres Palacios gas storage facility increased revenues by $11.0 million.

Cost of Product Sold.Cost of product sold for the three months ended June 30, 2011, was $271.7 million, an increase of $84.6 million, or 45.2%, from $187.1 million during the same three-month period in 2010.

Retail propane cost of product sold was $71.2 million for the three months ended June 30, 2011, an increase of $14.7 million, or 26.0%, when compared to $56.5 million for the same three-month period in 2010. This higher retail cost of product sold was driven by a $13.8 million increase arising from the higher average per gallon cost of propane and a $2.2 million increase due to acquisition-related sales. These factors were partially offset by a $1.1 million decline in retail propane cost of product sold resulting from lower volume sales at our existing locations as discussed above and a $0.2 million decrease due to changes in non-cash charges on derivative contracts associated with retail propane fixed price sales contracts.

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Wholesale propane cost of product sold in the three months ended June 30, 2011, was $92.8 million, an increase of $36.0 million or 63.4%, from wholesale cost of product sold of $56.8 million in the three months ended June 30, 2010. This increase resulted from the higher average purchase price of propane which contributed $25.1 million to the increase and $10.9 million from the higher volumes sold to existing and new customers.

Other retail cost of product sold was $27.2 million for the three months ended June 30, 2011, compared to $21.1 million during the same three-month period in 2010. This $6.1 million, or 28.9%, increase was primarily due to a $4.8 million increase in the cost for distillates and a $1.3 million increase in the cost of other retail sales. The increase in the cost of product sold for distillates was driven by a $5.7 million increase due to a higher overall commodity cost, partially offset by a $0.9 million decline due to lower volumes sold at existing locations.

Storage, fractionation and other midstream cost of product sold was $80.5 million for the three months ended June 30, 2011, an increase of $27.8 million, or 52.8%, from $52.7 million during the same three-month period in 2010. Costs from our West Coast NGL operations were $26.0 million higher as a result of increased natural gas liquid products sold, along with higher average commodity prices of natural gas liquids. Additionally, the acquisition of our Tres Palacios gas storage facility resulted in a $2.8 million increase in cost of product sold year over year.

Our retail and wholesale cost of product sold consists primarily of tangible products sold including all propane, distillates and other natural gas liquids sold and all propane-related appliances sold. Other costs incurred in conjunction with the distribution of these products are included in operating and administrative expenses and consist primarily of wages to delivery personnel, delivery vehicle costs consisting of fuel costs, repair and maintenance and lease expense. Costs associated with delivery vehicles approximated $17.9 million and $16.6 million for the three months ended June 30, 2011 and 2010, respectively. In addition, the depreciation expense associated with the delivery vehicles and customer tanks is reported within depreciation and amortization expense and amounted to $7.3 million and $8.3 million for the three months ended June 30, 2011 and 2010, respectively. Since we include these costs in our operating and administrative expense and depreciation and amortization expense 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.

Our storage, fractionation and other midstream cost of product sold consists primarily of commodity and transportation costs. Other costs incurred in conjunction with these services are included in operating and administrative expense and depreciation and amortization expense and consist primarily of depreciation, vehicle costs consisting of fuel costs and repair and maintenance and wages. Depreciation expense for storage, fractionation and other midstream amounted to $25.4 million and $18.7 million for the three months ended June 30, 2011 and 2010, respectively. Vehicle costs and wages for personnel directly involved in providing midstream services amounted to $1.1 million and $0.7 million for the three months ended June 30, 2011 and 2010, respectively. Since we include these costs in our operating and administrative expense and depreciation and amortization expense 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.Gross profit for the three months ended June 30, 2011, was $117.0 million, an increase of $12.5 million, or 12.0%, from $104.5 million during the same three-month period in 2010.

Retail propane gross profit was $48.9 million for the three months ended June 30, 2011, compared to $47.8 million in the same three-month period in 2010. This $1.1 million, or 2.3%, increase was mostly due to a $1.6 million improvement arising from acquisitions, partially offset by a $0.3 million gross profit decline attributable to lower retail gallon sales at existing locations as discussed above, and a slightly lower cash margin per gallon, which resulted in a $0.4 million decline in gross profit.

Wholesale propane gross profit was $7.5 million in the three months ended June 30, 2011, compared to $6.7 million in the three months ended June 30, 2010, an increase of $0.8 million or 11.9%. This increase resulted from higher margins obtained which contributed to $0.6 million of the increase and increased volumes sold to existing and new customers which contributed $0.2 million of the increase.

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Other retail gross profit was $15.8 million for the three months ended June 30, 2011, compared to $17.2 million for the same three-month period in 2010. This $1.4 million, or 8.1%, decrease was due primarily to a $1.2 million decline in appliance, parts and other retail gross profit and a $0.4 million decline in gross profit from distillate sales, partially offset by a $0.2 million increase from acquisition-related gross profit.

Storage, fractionation and other midstream gross profit was $44.8 million in the three months ended June 30, 2011, compared to $32.8 million in the same three-month period in 2010, an increase of $12.0 million, or 36.6%. This increase was primarily attributable to the gas storage acquisition of Tres Palacios, which contributed $8.2 million to the higher gross profit. In addition, $2.2 million of this increase was attributable to increased natural gas liquid products sold.

Operating and Administrative Expenses. Operating and administrative expenses were $77.4 million for the three months ended June 30, 2011, compared to $75.3 million in the same three-month period in 2010, an increase of $2.1 million or 2.8%. This change was primarily due to increased operating expenses of $2.8 million due to the operations of acquisitions, and higher vehicle expenses from existing operations. Vehicle expenses increased approximately $1.4 million due to higher fuel prices. Partially offsetting these increases was lower personnel costs from existing operations, which decreased $2.9 million.

Depreciation and Amortization.Depreciation and amortization was $48.0 million for the three months ended June 30, 2011, compared to $40.5 million during the same three-month period in 2010. This $7.5 million, or 18.5%, increase resulted primarily from acquisitions.

Interest Expense.Interest expense was $27.2 million for the three months ended June 30, 2011, compared to $23.1 million during the same three-month period in 2010. This $4.1 million, or 17.7%, increase was due to an increase in the average outstanding borrowings during the period due to acquisitions, partially offset by a decrease in the average interest rate incurred on those borrowings. Additionally, during the three months ended June 30, 2011 and 2010, we capitalized $3.3 million and $1.5 million, respectively, of interest related to certain capital improvement projects in our midstream segment as further described below in the “Liquidity and Sources of Capital” section.

Benefit (Provision) for Income Taxes. The provision for income taxes for the three months ended June 30, 2011, was $0.3 million compared to a benefit for income taxes of $0.6 million in the same three-month period in 2010. The provision for income taxes for the three months ended June 30, 2011, was composed of $0.5 million of current income tax expense together with $0.2 million of deferred income tax benefit. The benefit for income taxes for the three months ended June 30, 2010, was composed of $0.2 million of current income tax benefit together with $0.4 million of deferred income tax benefit.

Net Loss.Net loss was $35.5 million for the three months ended June 30, 2011, compared to net loss of $35.1 million for the same three-month period in 2010. The $0.4 million, or 1.1%, change in net loss was primarily attributable to increased depreciation and amortization and interest expense in the 2011 period, partially offset by higher gross profit.

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EBITDA and Adjusted EBITDA.The following table summarizes EBITDA and Adjusted EBITDA for the three months ended June 30, 2011 and 2010, respectively (in millions):

	Three Months Ended June 30,
	2011			2010
EBITDA:
Net income (loss) attributable to partners	$	(35.5	)	$	12.4
Net loss attributable to non-controlling partners in Inergy, L.P.		—			(47.6	)
Interest expense, net		27.2			23.1
Early extinguishment of debt		0.2			—
Provision (benefit) for income taxes		0.3			(0.6	)
Depreciation and amortization		48.0			40.5
EBITDA	$	40.2		$	27.8
Non-cash loss on derivative contracts		0.1			0.4
Long-term incentive and equity compensation expense		1.5			1.4
Loss on disposal of assets		0.5			2.1
Transaction costs		0.1			1.4
Adjusted EBITDA	$	42.4		$	33.1

^(a)ITDA – Interest expense, taxes, depreciation and amortization expense.

	Three Months Ended June 30,
	2011			2010
EBITDA:
Net cash provided by operating activities	$	8.7		$	0.4
Net changes in working capital balances		9.9			12.3
Non-cash early extinguishment of debt		—			—
Provision for doubtful accounts		(2.4	)		(2.4	)
Amortization of deferred financing costs, swap premium and net bond discount		(1.9	)		(1.7	)
Unit-based compensation charges		(1.5	)		(1.4	)
Loss on disposal of assets		(0.5	)		(2.1	)
Interest of non-controlling partners in ASC’s consolidated EBITDA		—			(0.1	)
Deferred income tax		0.2			0.3
Interest expense, net		27.2			23.1
Early extinguishment of debt		0.2			—
Provision (benefit) for income taxes		0.3			(0.6	)
EBITDA	$	40.2		$	27.8
Non-cash loss on derivative contracts		0.1			0.4
Long-term incentive and equity compensation expense		1.5			1.4
Loss on disposal of assets		0.5			2.1
Transaction costs		0.1			1.4
Adjusted EBITDA	$	42.4		$	33.1

EBITDA is defined as income (loss) before income taxes, plus net interest expense and depreciation and amortization expense. For the three months ended June 30, 2011 and 2010, EBITDA was $40.2 million and $27.8 million, respectively. As indicated in the table, Adjusted EBITDA represents EBITDA excluding the gain or loss on derivative contracts associated with retail propane fixed price sales contracts, the gain or loss on the disposal of assets, long-term incentive and equity compensation expenses and transaction costs. Transaction costs are third party professional fees and other costs that are incurred in conjunction with closing a transaction. Adjusted EBITDA was $42.4 million for the three months ended June 30, 2011, compared to $33.1 million in the same three-month period in 2010. 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

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EBITDA provides additional information for evaluating our ability to make the minimum quarterly distribution and is presented solely as a supplemental measure. We believe that Adjusted EBITDA provides additional information for evaluating our financial performance without regard to our financing methods, capital structure and historical cost basis. 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, 2011 Compared to Nine Months Ended June 30, 2010

The following table summarizes the consolidated statement of operations components for the nine months ended June 30, 2011 and 2010, respectively(in millions):

	Nine Months Ended June 30,						Change
	2011			2010			In Dollars			Percentage
Revenue	$	1,705.2		$	1,484.4		$	220.8			14.9	%
Cost of product sold		1,140.5			965.0			175.5			18.2
Gross profit		564.7			519.4			45.3			8.7
Operating and administrative expenses		243.6			231.2			12.4			5.4
Depreciation and amortization		141.8			117.7			24.1			20.5
Loss on disposal of assets		3.1			5.8			(2.7	)		(46.6	)
Operating income		176.2			164.7			11.5			7.0
Interest expense, net		(87.5	)		(67.4	)		(20.1	)		(29.8	)
Early extinguishment of debt		(49.6	)		—			(49.6	)		*
Other income		1.2			0.9			0.3			33.3
Income before income taxes		40.3			98.2			(57.9	)		(59.0	)
Provision for income taxes		(0.7	)		(0.3	)		(0.4	)		(133.3	)
Net income		39.6			97.9			(58.3	)		(59.6	)
Net (income) loss attributable to non-controlling partners		28.2			(47.7	)		75.9			159.1
Net income attributable to partners	$	67.8		$	50.2		$	17.6			35.1	%

* Not meaningful

The following table summarizes revenues, including associated volume of gallons sold, for the nine months ended June 30, 2011 and 2010, respectively (in millions):

	Revenues									Gallons
	Nine Months Ended June 30,				Change					Nine Months Ended June 30,				Change
	2011		2010		In Dollars		Percent			2011		2010		In Units			Percent
Propane
Retail propane	$	747.2	$	697.1	$	50.1		7.2	%		282.5		294.7		(12.2	)		(4.1	)%
Wholesale propane		440.7		394.5		46.2		11.7			322.1		341.3		(19.2	)		(5.6	)
Other retail		177.1		161.7		15.4		9.5			—		—		—			—
Midstream		340.2		231.1		109.1		47.2			—		—		—			—
Total	$	1,705.2	$	1,484.4	$	220.8		14.9	%		604.6		636.0		(31.4	)		(4.9	)%

Volume.During the nine months ended June 30, 2011, we sold 282.5 million retail gallons of propane, a decrease of 12.2 million gallons or 4.1% from the 294.7 million retail gallons sold during the same nine-month period in 2010. Gallons sold during the nine months ended June 30, 2011, decreased as compared to the same prior year period as a result of lower volumes sold at our existing locations of 39.1 million, partially offset by an increase arising from acquisition volume of 26.9 million gallons. The primary cause of the declining volumes at existing locations was (1) a decline in low margin agricultural propane sold due to lesser crop drying demand in the current year period compared to prior year, (2) continued customer conservation, which we believe has resulted from the continued impact of the overall weak United States economic environment and higher propane costs, which have been at record high prices the past several years and which have increased during the nine month period ended June 30, 2011, (3) volume declines from net customer losses primarily

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as a result of higher selling prices, and (4) warmer weather in our South and Southeast areas of operations. The average wholesale cost of propane has increased approximately 22% during the nine months ended June 30, 2011, compared to the same prior year period, continuing to impact customer buying decisions and conservation trends. Although certain of our areas of operations (South and Southeast) were warmer during the nine month period ended June 30, 2011, compared to the same prior year period, on a consolidated retail basis, weather during the nine months ended was approximately 2% colder than the prior year period and approximately 1.6% colder than normal.

Wholesale gallons delivered decreased 19.2 million gallons, or 5.6%, to 322.1 million gallons in the nine months ended June 30, 2011, from 341.3 million gallons in the nine months ended June 30, 2010. The decrease was due primarily to lower demand and volumes sold to existing and new customers.

The total natural gas liquid gallons sold or processed by our West Coast NGL operations decreased 10.4 million gallons, or 3.9%, to 254.6 million gallons during the nine months ended June 30, 2011, from 265.0 million gallons during the same nine-month period in 2010. This decrease was primarily attributable to decreased volume processed, partially offset by increased volume of natural gas liquid products sold. Both of the aforementioned changes were primarily due to local market conditions.

During the nine months ended June 30, 2011 and 2010, our Northeast natural gas facility was 100% contracted on a firm basis, and our LPG storage facility was approximately 100% contracted. During the nine months ended June 30, 2011 our newly acquired Tres Palacios storage facility was approximately 80% contracted on a firm and interruptible basis.

Revenues. Revenues for the nine months ended June 30, 2011, were $1,705.2 million, an increase of $220.8 million, or 14.9%, from $1,484.4 million during the same nine-month period in 2010.

Revenues from retail propane sales were $747.2 million for the nine months ended June 30, 2011, compared to $697.1 million during the same nine-month period in 2010. This $50.1 million, or 7.2%, increase was due to a higher overall average selling price of propane and acquisition-related sales, which resulted in higher retail propane revenues of $75.4 million and $67.1 million, respectively. The overall average selling price of propane increased due to an increase in the wholesale cost of propane. These factors were partially offset by a $92.4 million revenue decline arising from a decrease in gallons sold to existing customers as described above.

Revenues from wholesale propane sales were $440.7 million in the nine months ended June 30, 2011, an increase of $46.2 million or 11.7%, from $394.5 million in the nine months ended June 30, 2010. This increase was driven by higher average selling prices and resulted in higher wholesale propane revenues of $68.5 million, partially offset by lower volumes sold to existing and new customers of $22.3 million.

Revenues from other retail sales, which primarily includes distillates, service, rental, appliance sales and transportation services, were $177.1 million for the nine months ended June 30, 2011, an increase of $15.4 million, or 9.5%, from $161.7 million during the same nine-month period in 2010. Revenue from other retail sales increased as a result of higher distillate revenues of $14.5 million and an increase related to acquisitions of $3.2 million, partially offset by a $2.3 million decline in appliance, parts and other retail revenues. Distillate revenues from existing locations increased as a result of a higher comparable average selling price of distillates due to a higher wholesale cost, partially offset by lower volume sold.

Revenues from storage, fractionation and other midstream activities were $340.2 million for the nine months ended June 30, 2011, an increase of $109.1 million or 47.2% from $231.1 million during the same nine-month period in 2010. Revenues from our West Coast NGL operations increased $66.7 million primarily as a result of increased natural gas liquid products sold, along with higher average selling prices of natural gas liquids. Additionally, the acquisition of our Tres Palacios gas storage facility and the commencement of Thomas Corners gas storage contracts in April 2010 increased revenues by $34.9 million and $6.0 million, respectively.

Cost of Product Sold.Cost of product sold for the nine months ended June 30, 2011, was $1,140.5 million, an increase of $175.5 million, or 18.2%, from $965.0 million during the same nine-month period in 2010.

Retail propane cost of product sold was $401.4 million for the nine months ended June 30, 2011, an increase of $41.6 million, or 11.6%, when compared to $359.8 million for the same nine-month period in 2010. This higher retail cost of product sold was driven by a $51.1 million increase arising from a higher average per gallon cost of propane and a $37.7

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million increase associated with acquisition-related sales. Also contributing to a higher cost of product sold was a $0.6 million increase due to changes in non-cash charges on derivative contracts associated with retail propane fixed price sales contracts. These factors were partially offset by a $47.8 million decline in cost of product sold resulting from lower volume sales at our existing locations as discussed above.

Wholesale propane cost of product sold in the nine months ended June 30, 2011, was $417.7 million, an increase of $43.7 million or 11.7%, from wholesale cost of product sold of $374.0 million in the nine months ended June 30, 2010. This increase resulted from the higher average purchase price of propane which contributed $64.8 million to the increase, partially offset by $21.1 million due to the lower volumes sold to existing and new customers.

Other retail cost of product sold was $114.3 million for the nine months ended June 30, 2011, compared to $95.4 million during the same nine-month period in 2010. This $18.9 million, or 19.8%, increase was primarily as a result of a $17.0 million increase in the cost for distillates, a $1.0 million increase in the cost of product sold associated with acquisition-related sales and a $0.9 million increase in the cost of other retail sales. The increase in the cost of product sold for distillates was driven by a $20.4 million increase due to a higher overall commodity cost, partially offset by a $3.4 million decline due to lower volumes sold at existing locations.

Storage, fractionation and other midstream cost of product sold was $207.1 million for the nine months ended June 30, 2011, an increase of $71.3 million, or 52.5%, from $135.8 million during the same nine-month period in 2010. Costs from our West Coast NGL operations were $64.4 million higher as a result of increased natural gas liquid products sold, along with higher average commodity prices of natural gas liquids. Additionally, the acquisition of our Tres Palacios gas storage facility resulted in a $7.5 million increase in cost of product sold year over year.

Our retail and wholesale cost of product sold consists primarily of tangible products sold including all propane, distillates and other natural gas liquids sold and all propane-related appliances sold. Other costs incurred in conjunction with the distribution of these products are included in operating and administrative expenses and consist primarily of wages to delivery personnel, delivery vehicle costs consisting of fuel costs, repair and maintenance and lease expense. Costs associated with delivery vehicles approximated $57.1 million and $51.9 million for the nine months ended June 30, 2011 and 2010, respectively. In addition, the depreciation expense associated with the delivery vehicles and customer tanks is reported within depreciation and amortization expense and amounted to $22.1 million and $24.5 million for the nine months ended June 30, 2011 and 2010, respectively. Since we include these costs in our operating and administrative expense and depreciation and amortization expense 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.

Our storage, fractionation and other midstream cost of product sold consists primarily of commodity and transportation costs. Other costs incurred in conjunction with these services are included in operating and administrative expense and depreciation and amortization expense and consist primarily of depreciation, vehicle costs consisting of fuel costs and repair and maintenance and wages. Depreciation expense for storage, fractionation and other midstream amounted to $74.6 million and $55.1 million for the nine months ended June 30, 2011 and 2010, respectively. Vehicle costs and wages for personnel directly involved in providing midstream services amounted to $3.4 million and $2.1 million for the nine months ended June 30, 2011 and 2010, respectively. Since we include these costs in our operating and administrative expense and depreciation and amortization expense 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.Gross profit for the nine months ended June 30, 2011, was $564.7 million, an increase of 45.3 million, or 8.7%, from $519.4 million during the same nine-month period in 2010.

Retail propane gross profit was $345.8 million for the nine months ended June 30, 2011, compared to $337.3 million in the same nine-month period in 2010. This $8.5 million, or 2.5%, increase was primarily driven by acquisitions and a higher cash margin per gallon, which contributed increases of $29.4 million and $24.3 million respectively. The higher cash margin per gallon was primarily due to the average selling price increasing at a greater rate than the increased cost of propane including the impact of lesser agricultural gallons sold, which generally have a lower margin. These factors were partially offset by a gross profit decline of $44.6 million attributable to lower retail gallon sales at existing locations as discussed above and a $0.6 million decline related to changes in non-cash charges on derivative contracts associated with retail propane fixed price sales contracts as discussed above.

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Wholesale propane gross profit was $23.0 million in the nine months ended June 30, 2011, compared to $20.5 million in the nine months ended June 30, 2010, an increase of $2.5 million or 12.2%. This increase resulted from higher margins obtained which contributed to $3.8 million of the increase, partially offset by $1.1 million due to the lower volumes sold to existing and new customers.

Other retail gross profit was $62.8 million for the nine months ended June 30, 2011, compared to $66.3 million for the same nine-month period in 2010. This $3.5 million, or 5.3%, decrease was primarily due to a $2.5 million decline in gross profit from distillates and a $3.2 million decline in other retail gross profit, partially offset by a $2.2 million increase in gross profit related to acquisitions.

Storage, fractionation and other midstream gross profit was $133.1 million in the nine months ended June 30, 2011, compared to $95.3 million in the same nine-month period in 2010, an increase of $37.8 million, or 39.7%. This increase was primarily attributable to the gas storage acquisition of Tres Palacios, which contributed $27.3 million to the higher gross profit. The completion of our Thomas Corners gas storage facility in November 2009, and the relating storage contracts coming online in April 2010, also increased gross profit by approximately $5.6 million.

Operating and Administrative Expenses. Operating and administrative expenses were $243.6 million for the nine months ended June 30, 2011, compared to $231.2 million in the same nine-month period in 2010, an increase of $12.4 million or 5.4%. Included in the 2011 operating expenses were $9.0 million of transaction costs, primarily financing commitment expenses for the Tres Palacios acquisition, directly related to closing acquisitions during the period. The transaction costs for the same period of the prior year were $2.1 million. In addition, operating expenses increased $19.1 million due to the operations of acquisitions, partially offset by lower personnel costs from existing operations, which decreased $14.5 million, and lower insurance and other operating expenses.

Depreciation and Amortization.Depreciation and amortization was $141.8 million for the nine months ended June 30, 2011, compared to $117.7 million during the same nine-month period in 2010. This $24.1 million, or 20.5%, increase resulted primarily from acquisitions.

Interest Expense.Interest expense was $87.5 million for the nine months ended June 30, 2011, compared to $67.4 million during the same nine-month period in 2010. This $20.1 million, or 29.8%, increase was due primarily to an increase in the average outstanding borrowings during the period due to acquisitions, partially offset by a decrease in the average interest rate incurred on those borrowings. Additionally, during the nine months ended June 30, 2011 and 2010, we capitalized $11.4 million and $4.9 million, respectively, of interest related to certain capital improvement projects in our midstream segment as further described below in the “Liquidity and Sources of Capital” section.

Early Extinguishment of Debt. During the nine-month period ended June 30, 2011, we exercised our equity offerings redemption option in addition to a partial tender offer and redeemed 48% of our 2015 senior notes. Further, we tendered over 90% of both our 2014 and 2016 senior notes and the remaining amounts were redeemed in full. The loss associated with the above described transactions amounted to $49.6 million and was primarily related to the tender premium and the write-off of previously capitalized charges associated with the original issuance of the respective debt.

Provision for Income Taxes. The provision for income taxes for the nine months ended June 30, 2011, was $0.7 million compared to $0.3 million in the same nine-month period in 2010. The provision for income taxes for the nine months ended June 30, 2011, was composed of $0.8 million of current income tax expense together with $0.1 million of deferred income tax benefit. The provision for income taxes for the nine months ended June 30, 2010, was composed entirely of current income tax expense.

Net Income.Net income was $39.6 million for the nine months ended June 30, 2011, compared to net income of $97.9 million for the same nine-month period in 2010. The $58.3 million, or 59.6%, decrease in net income was primarily attributable to the charge for the early extinguishment of debt, increased depreciation and amortization, operating and administrative expenses and interest expense in the 2011 period, partially offset by higher gross profit.

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EBITDA and Adjusted EBITDA.The following table summarizes EBITDA and Adjusted EBITDA for the nine months ended June 30, 2011 and 2010, respectively (in millions):

	Nine Months Ended June 30,
	2011			2010
EBITDA:
Net income attributable to partners	$	67.8		$	50.2
Interest of non-controlling partners in ASC’s consolidated ITDA(a)		—			(0.2	)
Net income (loss) attributable to non-controlling partners in Inergy, L.P.		(28.2	)		47.0
Interest expense, net		87.5			67.4
Early extinguishment of debt		49.6			—
Provision for income taxes		0.7			0.3
Depreciation and amortization		141.8			117.7
EBITDA	$	319.2		$	282.4
Non-cash gain on derivative contracts		(0.2	)		(0.7	)
Long-term incentive and equity compensation expense		4.4			4.9
Loss on disposal of assets		3.1			5.8
Transaction costs		9.0			2.1
Adjusted EBITDA	$	335.5		$	294.5

^(a)  ITDA – Interest expense, taxes, depreciation and amortization expense.

	Nine Months Ended June 30,
	2011			2010
EBITDA:
Net cash provided by operating activities	$	130.5		$	140.4
Net changes in working capital balances		77.7			92.1
Non-cash early extinguishment of debt		(11.2	)		—
Provision for doubtful accounts		(2.6	)		(2.1	)
Amortization of deferred financing costs, swap premium and net bond discount		(5.7	)		(5.4	)
Unit-based compensation charges		(4.4	)		(3.6	)
Loss on disposal of assets		(3.1	)		(5.8	)
Interest of non-controlling partners in ASC’s consolidated EBITDA		—			(0.9	)
Deferred income tax		0.2			—
Interest expense, net		87.5			67.4
Early extinguishment of debt		49.6			—
Provision for income taxes		0.7			0.3
EBITDA	$	319.2		$	282.4
Non-cash gain on derivative contracts		(0.2	)		(0.7	)
Long-term incentive and equity compensation expense		4.4			4.9
Loss on disposal of assets		3.1			5.8
Transaction costs		9.0			2.1
Adjusted EBITDA	$	335.5		$	294.5

EBITDA is defined as income (loss) before income taxes, plus net interest expense and depreciation and amortization expense. For the nine months ended June 30, 2011 and 2010, EBITDA was $319.2 million and $282.4 million, respectively. As indicated in the table, Adjusted EBITDA represents EBITDA excluding the gain or loss on derivative contracts associated with retail propane fixed price sales contracts, the gain or loss on the disposal of assets, long-term incentive and equity compensation expenses and transaction costs. Transaction costs are third party professional fees and other costs that are incurred in conjunction with closing a transaction. Adjusted EBITDA was $335.5 million for the nine months ended June 30, 2011, compared to $294.5 million in the same nine-month period in 2010. EBITDA and Adjusted EBITDA should not be considered an alternative to net income, income before income taxes, cash flows from operating

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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 provides additional information for evaluating our ability to make the minimum quarterly distribution and is presented solely as a supplemental measure. We believe that Adjusted EBITDA provides additional information for evaluating our financial performance without regard to our financing methods, capital structure and historical cost basis. 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.

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.

Liquidity and Sources of Capital

Cash Flows and Contractual Obligations

Net operating cash inflows were $130.5 million and $140.4 million for the nine-month periods ending June 30, 2011 and 2010, respectively. The $9.9 million decrease in operating cash flows was primarily attributable to the $38.4 million cash cost of our early extinguishment of debt, partially offset by an increase in cash components of net income and changes in working capital balances.

Net investing cash outflows were $275.4 million and $319.3 million for the nine-month periods ending June 30, 2011 and 2010, respectively. Net cash outflows were primarily impacted by a $588.0 million investment in escrow account that was utilized to fund the Tres Palacios acquisition and a $15.4 million increase in proceeds from sale of assets, partially offset by a $504.5 million increase in cash outlays related to acquisitions and a $55.0 million increase in capital expenditures.

Net financing cash inflows were $159.1 million and $172.8 million for the nine-month periods ending June 30, 2011 and 2010, respectively. The net change was primarily impacted by a $78.0 million decrease in proceeds related to the issuance of long-term debt, net of payments on long-term debt, a $48.9 million increase in the total distributions paid and a $6.6 million increase in payments for deferred financing costs, partially offset by a $111.6 million increase in proceeds from the issuance of common units.

We believe that anticipated cash from operations and borrowing capacity under our Credit Agreement described below will be sufficient to meet our liquidity needs for the foreseeable future. If our plans or assumptions change or are inaccurate, or we make acquisitions, we may need to raise additional capital. While global financial markets and economic conditions have been disrupted and volatile in the past, the conditions have improved more recently. However, we give no assurance that we can raise additional capital to meet these needs. We have identified capital expansion project opportunities in our midstream operations. As of June 30, 2011, we have firm purchase commitments totaling approximately $60.2 million related to certain of these projects. Additional commitments or expenditures, if any, we may make toward any one or more of these projects are at the discretion of the Partnership. Any discontinuation of the construction of these projects will likely result in less future cash flow and earnings than we have previously indicated.

Description of Credit Facility

On November 24, 2009, we entered into a secured credit facility (“Credit Agreement”) which provides borrowing capacity of up to $525 million in the form of a $450 million revolving general partnership credit facility (“General Partnership Facility”) and a $75 million working capital credit facility (“Working Capital Facility”). This facility will mature on November 22, 2013.

On February 2, 2011, we amended and restated the Credit Agreement to add a $300 million term loan facility (the “Term Loan Facility”). The term loan matures on February 2, 2015, and bears interest, at our option, subject to certain limitations, at a rate equal to the following:

• the Alternate Base Rate, which is defined as the higher of i) the federal funds rate plus 0.50%; ii) JP Morgan’s prime rate; or iii) the Adjusted LIBO Rate plus 1%; plus a margin varying from 1.00% to 2.25%; or

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• the Adjusted LIBO Rate, which is defined as the LIBO Rate plus a margin varying from 2.00% to 3.25%.

The Credit Agreement contains various affirmative and negative covenants and default provisions, as well as requirements with respect to the maintenance of specified financial ratios and limitations on making investments, permitting liens and entering into other debt obligations. All borrowings under the General Partnership Facility and Working Capital Facility bear interest, at our option, subject to certain limitations, at a rate equal to the following:

• the Alternate Base Rate, which is defined as the higher of i) the federal funds rate plus 0.50%; ii) JP Morgan’s prime rate; or iii) the Adjusted LIBO Rate plus 1%; plus a margin varying from 1.50% to 2.75%; or

• the Adjusted LIBO Rate, which is defined as the LIBO Rate plus a margin varying from 2.50% to 3.75%.

On January 19, 2011, we announced the pricing of $750 million in aggregate principal amount of senior unsecured notes (the “Notes Offering”). The 6.875% notes mature on August 1, 2021, and were issued at par. The Notes Offering closed on February 2, 2011.

We used the net proceeds from the Notes Offering and the Term Loan Facility to: (1) fund the partial redemption of our 8.75% Senior Notes due 2015 (the “2015 Notes”); (2) fund the tender offers for portions of the (a) 6.875% Senior Notes due 2014 (the “2014 Notes”), (b) 2015 Notes outstanding upon completion of the partial redemption of the 2015 Notes, and (c) 8.25% Senior Notes due 2016 (the “2016 Notes”); and (3) redeem all 2014 Notes and 2016 Notes not acquired in the tender offers related to such notes. The remaining net proceeds were used to repay outstanding borrowings under our General Partnership Facility and the Working Capital Facility and to provide additional working capital for general partnership purposes. The charges to net income associated with the tender offer and redemption were $49.6 million.

At June 30, 2011, the balance outstanding under the Credit Agreement was $300.0 million, all of which was borrowed under the Term Loan Facility. At September 30, 2010, there was no balance outstanding under the Credit Agreement. The interest rate on the Term Loan Facility is based on LIBOR plus the applicable spread, resulting in an interest rate that was 3.44% at June 30, 2011.

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. This requirement was met in April 2011.

On July 28, 2011, we amended our amended and restated Credit Agreement to (i) raise the aggregate revolving commitment from $525 million to $700 million, (ii) reduce the applicable rate on revolving loans and commitment fees, (iii) modify and refresh certain covenants and covenant baskets, and (iv) extend the maturity date from November 22, 2013 to July 28, 2016.

In August 2011, our ten interest rate swaps maturing in 2018 were terminated, and we received approximately $14.3 million in proceeds. These swaps had an aggregate notional amount of $250 million.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Interest Rate Risk

We have a term loan debt and a revolving line of credit subject to the risk of loss associated with movements in interest rates. At June 30, 2011, we had floating rate obligations totaling $575.0 million borrowed under our Term Loan Facility and our interest rate swaps, which convert a portion of our fixed rate senior unsecured notes due 2018 and 2015 to floating, with a notional amount of $275 million. Floating rate obligations expose us to the risk of increased interest expense in the event of increases in short-term interest rates.

If the floating rate were to fluctuate by 100 basis points from March 2011 levels, our interest expense would change by a total of approximately $5.8 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

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take an active role in managing and controlling market and credit risk and have established control procedures, which are reviewed on an ongoing basis. We monitor market risk through a variety of techniques, including daily reporting of the portfolio’s position to senior management. We attempt to minimize credit risk exposure through credit policies and periodic monitoring procedures as well as through customer deposits, letters of credit and entering into netting agreements that allow for offsetting counterparty receivable and payable balances for certain financial transactions, as deemed appropriate. The counterparties associated with assets from price risk management activities as of June 30, 2011 and 2010, were propane retailers, resellers, energy marketers and dealers.

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

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

Fair Value

The fair value of the derivatives and inventory exchange contracts related to price risk management activities as of June 30, 2011 and September 30, 2010, was assets of $13.6 million and $22.5 million, respectively, and liabilities of $16.5 million and $24.3 million, respectively.

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

Sensitivity Analysis

A theoretical change of 10% in the underlying commodity value would result in a $(0.1) change in the market value of the contracts as there were 0.4 million gallons of net unbalanced positions at June 30, 2011.

Item 4. Controls and Procedures

We maintain controls and procedures designed to provide a reasonable assurance that information required to be disclosed in our reports that we file or submit under the Securities Exchange Act of 1934 are recorded, processed, summarized and reported within the time periods specified by the rules and forms of the SEC, and that information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. An evaluation was performed under the supervision and with the participation of our management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as such terms are defined in Rule 13a-15(e) and 15d-15(e) of the Exchange Act). Based upon that evaluation, management, including the Chief Executive Officer and the Chief Financial Officer, concluded that our disclosure controls and procedures were effective as of June 30, 2011, at the reasonable assurance level. There have been no changes in our internal control over financial reporting (as defined in Rule 13(a)-15(f) or Rule 15d-15(f) of the Exchange Act) during the period ended June 30, 2011, that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

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Changes in Internal Control over Financial Reporting

In fiscal 2011, we completed the acquisitions of Tres Palacios, Schenck and Pennington. See Note 4 “Business Acquisitions” to the Consolidated Financial Statements included in Item 1 for discussion of the acquisitions and related financial data.

We are currently in the process of evaluating the internal controls and procedures of our current acquisitions. Further, we are in the process of integrating their operations. Management will continue to evaluate our internal control over financial reporting as we execute integration activities; however, integration activities could materially affect our internal control over financial reporting in future periods.

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PART II – OTHER INFORMATION

Item 1. Legal Proceedings

Part I, Item 1. Financial Statements, Note 9 to the Consolidated Financial Statements, of this Form 10-Q is hereby incorporated herein by reference.

Item 1A. Risk Factors

There have been no material changes to the risk factors disclosed in “Item 1A, Risk Factors” in the Company’s Annual Report on Form 10-K for the fiscal year ended September 30, 2010, or the Company’s Quarterly Report on Form 10-Q for the period ended March 31, 2011.

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

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Reserved

None.

Item 5. Other Information

None.

Item 6. Exhibits

3.1	Certificate of Limited Partnership of Inergy, L.P. (incorporated herein by reference to Exhibit 3.1 to Inergy, L.P.’s Registration Statement on Form S-1 (Registration No. 333-56976) filed on March 14, 2001).
3.1A	Certificate of Correction of Certificate of Limited Partnership of Inergy, L.P. (incorporated herein by reference to Exhibit 3.1 to Inergy, L.P.’s Form 10-Q (Registration No. 000-32543) filed on May 12, 2003).
3.2	Second Amended and Restated Agreement of Limited Partnership of Inergy, L.P. (incorporated herein by reference to Exhibit 3.1 to Inergy, L.P.’s Form 10-Q (Registration No. 000-32453) filed on February 13, 2004).
3.2A	Amendment No. 1 to Second Amended and Restated Agreement of Limited Partnership of Inergy, L.P. (incorporated herein by reference to Exhibit 3.1 to Inergy, L.P.’s Form 10-Q (Registration No. 000-32453) filed on May 14, 2004).
3.2B	Amendment No. 2 to Second Amended and Restated Agreement of Limited Partnership of Inergy, L.P. (incorporated herein by reference to Exhibit 3.1 to Inergy, L.P.’s Form 8-K filed on January 24, 2005).
3.2C	Amendment No. 3 to Second Amended and Restated Agreement of Limited Partnership of Inergy, L.P. (incorporated herein by reference to Exhibit 3.1 to Inergy, L.P.’s Form 8-K/A filed on August 17, 2005).

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3.3	Certificate of Formation as relating to Inergy Propane, LLC, as amended (incorporated herein by reference to Exhibit 3.3 to Inergy, L.P.’s Registration Statement on Form S-1/A (Registration No. 333-56976) filed on May 7, 2001).
3.4	Third Amended and Restated Limited Liability Company Agreement of Inergy Propane, LLC, dated as of July 31, 2001 (incorporated herein by reference to Exhibit 3.4 to Inergy, L.P.’s Registration Statement on Form S-1 (Registration No. 333-89010 filed on May 24, 2002).
3.5	Certificate of Formation of Inergy GP, LLC (incorporated herein by reference to Exhibit 3.5 to Inergy, L.P.’s Registration Statement on Form S-1/A (Registration No. 333-56976) filed on May 7, 2001).
3.6	Limited Liability Company Agreement of Inergy GP, LLC (incorporated herein by reference to Exhibit 3.6 to Inergy, L.P.’s Registration Statement on Form S-1/A (Registration No. 333-56976) filed on May 7, 2001).
3.7	Certificate of Formation as relating to Inergy Partners, LLC, as amended (incorporated herein by reference to Exhibit 3.7 to Inergy, L.P.’s Registration Statement on Form S-1/A (Registration No. 333-56976) filed on May 7, 2001).
3.8	Second Amended and Restated Limited Liability Company Agreement of Inergy Partners, LLC, dated as of July 31, 2001 (incorporated herein by reference to Exhibit 3.8 to Inergy, L.P.’s Registration Statement on Form S-1 (Registration No. 333-89010) filed on May 24, 2002).
*31.1	Certification of Chief Executive Officer of Inergy, L.P. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*31.2	Certification of Chief Financial Officer of Inergy, L.P. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*32.1	Certification of Chief Executive Officer of Inergy, L.P. pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
*32.2	Certification of Chief Financial Officer of Inergy, L.P. pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
*101.INS	XBRL Instance Document
*101.SCH	XBRL Taxonomy Extension Schema Document
*101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
*101.LAB	XBRL Taxonomy Extension Label Linkbase Document
*101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document
*101.DEF	XBRL Taxonomy Extension Definition Linkbase Document

* Filed herewith

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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 9, 2011	By:	/s/ R. Brooks Sherman, Jr.
		R. Brooks Sherman, Jr.
		Executive Vice President and Chief Financial Officer
		(Duly Authorized Officer and Principal Financial Officer and Principal Accounting Officer)

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