Edgar Filing: INERGY L P

Large accelerated filer

Accelerated filer

Non-accelerated filer

¨ (Do not check if a smaller reporting company)

Smaller reporting company

Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2012

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

For the transition period from to .

COMMISSION FILE NUMBER: 0-32453

Inergy, L.P.

(Exact name of registrant as specified in its charter)

Delaware

43-1918951

(State or other jurisdiction of

incorporation or organization)

(IRS Employer

Identification No.)

Two Brush Creek Blvd., Suite 200

Kansas City, Missouri

64112

(Address of principal executive offices)

(Zip code)

(816) 842-8181

(Registrant’s telephone number, including area code)

(Former name, former address and former fiscal year,

if changed since last report)

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

Indicate by check mark whether the registrant 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.

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, 2012 (unaudited) and September 30, 2011		3
Unaudited Consolidated Statements of Operations for the Three and Nine Months Ended June 30, 2012 and 2011		4
Unaudited Consolidated Statement of Partners’ Capital for the Nine Months Ended June 30, 2012		5
Unaudited Consolidated Statements of Cash Flows for the Nine Months Ended June 30, 2012 and 2011		6
Unaudited Notes to Consolidated Financial Statements		8

Item 2 – Management’s Discussion and Analysis of Financial Condition and Results of Operations		36

Item 3 – Quantitative and Qualitative Disclosures About Market Risk		55

Item 4 – Controls and Procedures		56

Part II – Other Information

Item 1 – Legal Proceedings		58

Item 1A – Risk Factors		58

Item 2 – Unregistered Sales of Equity Securities and Use of Proceeds		58

Item 3 – Defaults Upon Senior Securities		58

Item 4 – Mine Safety Disclosures		58

Item 5 – Other Information		58

Item 6 – Exhibits		58

Signature		61

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,		September 30,
	2012		2011
	*(unaudited)*
Assets
Current assets:
Cash and cash equivalents	$	4.9	$	11.5
Accounts receivable, less allowance for doubtful accounts of $0.4 million and $0.2 million at June 30, 2012 and September 30, 2011, respectively		88.5		112.9
Inventories (Note 3)		46.3		155.1
Assets from price risk management activities		40.6		17.1
Prepaid expenses and other current assets		23.7		16.1
Current assets held for sale (Note 5)		1,174.1		115.2

Total current assets		1,378.1		427.9

Property, plant and equipment (Note 3)		2,042.7		1,857.8
Less: accumulated depreciation		411.1		322.8

Property, plant and equipment, net		1,631.6		1,535.0

Intangible assets (Note 3):
Customer accounts		42.5		39.7
Other intangible assets		51.6		56.9

		94.1		96.6
Less: accumulated amortization		27.1		29.0

Intangible assets, net		67.0		67.6

Assets held for sale (Note 5)		—		1,146.7
Goodwill		162.4		162.0
Other assets		1.4		1.7

Total assets	$	3,240.5	$	3,340.9


Liabilities and partners’ capital
Current liabilities:
Accounts payable	$	102.0	$	145.6
Accrued expenses		84.0		72.1
Liabilities from price risk management activities		13.5		19.0
Current portion of long-term debt (Note 8)		1,188.5		3.2
Liabilities held for sale (Note 5)		62.0		82.1

Total current liabilities		1,450.0		322.0

Long-term debt, less current portion (Note 8)		519.5		1,833.4
Other long-term liabilities		21.4		19.3
Deferred income taxes		19.7		20.2

Partners’ capital (Note 9):
Limited partner unitholders (125,827,173 and 119,147,858 common units issued and outstanding as of June 30, 2012 and September 30, 2011, respectively, and 5,882,105 and 12,165,499 Class B units issued and outstanding at June 30, 2012 and September 30, 2011, respectively)		1,088.1		1,146.0

Total Inergy, L.P. partners’ capital		1,088.1		1,146.0
Interest of non-controlling partners in subsidiaries		141.8		—

Total partners’ capital		1,229.9		1,146.0

Total liabilities and partners’ capital	$	3,240.5	$	3,340.9

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

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,
	2012			2011			2012			2011
Revenue:
Propane	$	203.7		$	220.4		$	1,132.3		$	1,187.9
Other		167.9			168.3			570.3			517.3

		371.6			388.7			1,702.6			1,705.2
Cost of product sold (excluding depreciation and amortization as shown below):
Propane		148.2			164.0			851.2			819.1
Other		93.3			107.7			340.7			321.4

		241.5			271.7			1,191.9			1,140.5
Expenses:
Operating and administrative		83.1			77.4			247.1			243.6
Depreciation and amortization		38.2			48.0			136.6			141.8
Loss on disposal of assets		2.2			0.5			5.8			3.1

Operating income (loss)		6.6			(8.9	)		121.2			176.2

Other income (expense):
Interest expense, net		(22.8	)		(27.2	)		(73.2	)		(87.5	)
Early extinguishment of debt		(1.7	)		(0.2	)		(26.6	)		(49.6	)
Other income		0.1			1.1			1.5			1.2

Income (loss) before income taxes		(17.8	)		(35.2	)		22.9			40.3
Benefit (provision) for income taxes		0.1			(0.3	)		(0.2	)		(0.7	)

Net income (loss)		(17.7	)		(35.5	)		22.7			39.6
Net (income) loss attributable to non-controlling partners in subsidiary		(4.1	)		—			(7.8	)		28.2

Net income (loss) attributable to partners	$	(21.8	)	$	(35.5	)	$	14.9		$	67.8

Total limited partners’ interest in net income (loss)	$	(21.8	)	$	(35.5	)	$	14.9		$	67.8


Net income (loss) per limited partner unit:
Basic	$	(0.15	)	$	(0.32	)	$	0.17		$	0.67

Diluted	$	(0.17	)	$	(0.32	)	$	0.11		$	0.60


Weighted-average limited partners’ units outstanding (in thousands):
Basic		125,818			112,538			124,698			101,215
Dilutive units		—			—			6,858			11,862

Diluted		125,818			112,538			131,556			113,077

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

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, 2011	$	1,146.0		$	—		$	1,146.0
Net proceeds from issuance of common units by Inergy Midstream, L.P.		—			292.7			292.7
Net proceeds from common unit options exercised		0.7			—			0.7
Certain costs related to Inergy Midstream, L.P.’s initial public offering		(4.3	)		—			(4.3	)
Unit-based compensation charges		9.8			—			9.8
Retirement of common units		(1.3	)		—			(1.3	)
Distributions		(219.7	)		(7.6	)		(227.3	)
Gain (loss) on issuance of Inergy Midstream, L.P. units		133.8			(133.8	)		—
Gain (loss) associated with contribution of US Salt, LLC		17.3			(17.3	)		—
Comprehensive income:
Net income		14.9			7.8			22.7
Change in unrealized fair value on cash flow hedges		(9.1	)		—			(9.1	)

Comprehensive income								13.6

Balance at June 30, 2012	$	1,088.1		$	141.8		$	1,229.9

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

INERGY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

(unaudited)


	Nine Months Ended June 30,
	2012			2011
Operating activities
Net income	$	22.7		$	39.6
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and depletion		115.9			112.3
Amortization		20.7			29.5
Amortization of deferred financing costs, swap premium and net bond discount		3.9			5.7
Unit-based compensation charges		9.8			4.4
Provision for doubtful accounts		1.8			2.6
Loss on disposal of assets		5.8			3.1
Deferred income taxes		(0.5	)		(0.2	)
Early extinguishment of debt		10.0			11.2
Changes in operating assets and liabilities, net of effects from acquisitions:
Accounts receivable		40.6			(31.6	)
Inventories		128.7			(8.3	)
Prepaid expenses and other current assets		(7.4	)		(6.7	)
Other assets (liabilities)		0.4			(0.2	)
Accounts payable and accrued expenses		(44.1	)		9.6
Customer deposits		(17.0	)		(36.9	)
Net liabilities from price risk management activities		(38.1	)		(3.6	)

Net cash provided by operating activities		253.2			130.5

Investing activities
Acquisitions, net of cash acquired		(23.4	)		(757.4	)
Purchases of property, plant and equipment		(168.7	)		(126.2	)
Proceeds from sale of assets		7.3			20.2
Proceeds from redemption of bond offering escrow		—			588.0

Net cash used in investing activities		(184.8	)		(275.4	)

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

INERGY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (continued)

(in millions)

(unaudited)


	Nine Months Ended June 30,
	2012			2011
Financing activities
Proceeds from the issuance of Inergy, L.P. long-term debt	$	887.2		$	1,837.0
Proceeds from the issuance of Inergy Midstream, L.P. long-term debt		385.8			—
Principal payments on Inergy, L.P. long-term debt		(1,344.1	)		(1,748.6	)
Principal payments on Inergy Midstream, L.P. long-term debt		(61.6	)		—
Proceeds from the issuance of promissory note		255.0			—
Principal payment on promissory note		(255.0	)		—
Distributions		(219.7	)		(176.1	)
Distributions paid to non-controlling partners		(7.6	)		(51.5	)
Payments for deferred financing costs		(6.5	)		(17.0	)
Proceeds from swap settlement		0.8			—
Costs associated with the simplification of capital structure		—			(1.1	)
Net proceeds from issuance of Inergy, L.P. common units		—			311.4
Net proceeds from issuance of Inergy Midstream, L.P. common units		292.7			—
Retirement of common units		(1.3	)		—
Net proceeds from Inergy, L.P. common unit options exercised		0.7			5.1
Other		(1.4	)		(0.1	)

Net cash provided by (used in) financing activities		(75.0	)		159.1

Net increase (decrease) in cash		(6.6	)		14.2
Cash at beginning of period		11.5			144.4

Cash at end of period	$	4.9		$	158.6


Supplemental schedule of noncash investing and financing activities
Change in the value of intangible assets and equity	$	(3.0	)	$	—

Net change to property, plant and equipment through accounts payable and accrued expenses	$	11.9		$	8.7

Change in the fair value of interest rate swap liability and related long-term debt	$	—		$	4.8


Acquisitions, net of cash acquired:
Current assets	$	5.2		$	5.0
Property, plant and equipment		12.4			436.2
Contractual rights		—			266.9
Intangible assets		6.1			9.7
Goodwill		0.4			51.9
Other assets		0.1			1.0
Current liabilities		0.3			(12.3	)
Debt		(1.1	)		(1.0	)

Total acquisitions, net of cash acquired	$	23.4		$	757.4

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

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 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.

Inergy Midstream

On November 14, 2011, Inergy Midstream, LLC converted into a Delaware limited partnership and changed its name to Inergy Midstream, L.P. (“Inergy Midstream”). Inergy Midstream converted into a limited partnership in connection with the initial public offering (“IPO”) of its common units representing limited partnership interests. Inergy Midstream was formed by Inergy to acquire, develop, own and operate midstream energy assets.

On November 25, 2011, Inergy Midstream assigned 100% of its membership interests in each of US Salt, LLC (“US Salt”) and Tres Palacios Gas Storage LLC to Inergy.

On December 21, 2011, Inergy Midstream completed its IPO. Inergy Midstream sold 16,000,000 common units to public investors and the underwriters exercised their option to purchase an additional 2,400,000 common units. Prior to this offering, there had been no public market for Inergy Midstream’s common units. The Inergy Midstream common units began trading on the New York Stock Exchange on December 16, 2011, under the symbol “NRGM.” Upon completion of the offering, Inergy owned, directly or indirectly, an approximate 75.2% limited partner interest and all of the incentive distribution rights, or IDRs, in Inergy Midstream. The IDRs entitle Inergy to receive 50% of all Inergy Midstream’s distributions in excess of the initial quarterly distribution of $0.37 per unit. Additionally, Inergy indirectly owns NRGM GP, LLC, the general partner of Inergy Midstream, which entitles the general partner to management but no economic rights in Inergy Midstream.

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

On May 14, 2012, Inergy contributed 100% of the membership interests in US Salt to Inergy Midstream (“US Salt Contribution”) for $182.5 million of cash and 473,707 Inergy Midstream common units issued directly to Inergy. The cash proceeds were used to repay outstanding borrowings under Inergy’s revolving credit facility. Following the US Salt Contribution, Inergy owns approximately 56.4 million limited partner units of NRGM, representing an approximate 75% ownership interest. In connection with the US Salt Contribution, (i) US Salt’s guarantee of Inergy’s senior notes, as well as the lien granted to the lenders of Inergy’s credit agreement on US Salt’s membership interest and substantially all of its assets, were released; and (ii) US Salt’s membership interests and substantially all of its assets were pledged as collateral under the Inergy Midstream credit facility.

NRGM GP, LLC Change of Control Event

In connection with the IPO, Inergy and Inergy Holdings GP, LLC (“Holdings GP”), the indirect owner of Inergy’s general partner, entered into a membership interest purchase agreement under which, under certain circumstances, Holdings GP will be required to purchase from Inergy, and Inergy will be required to sell to Holdings GP, all of the membership interests in MGP GP, LLC, the entity that controls Inergy Midstream’s general partner, for nominal consideration. MGP GP, LLC is a wholly owned subsidiary of Inergy and the general partner of Inergy Midstream Holdings, L.P., which is the sole member of Inergy Midstream’s general partner and direct holder of all of its incentive distribution rights. Under the agreement, Holdings GP is required to purchase MGP GP, LLC in the event that (i) a change of control of Inergy occurs at a time when Inergy is entitled to receive less than 50% of all cash distributed with respect to Inergy Midstream’s limited partner interests and incentive distribution rights or (ii) through dilution or a distribution to the Inergy common unitholders of Inergy’s interests in Inergy Midstream, Inergy is entitled to receive less than 25% of all cash distributed with respect to Inergy Midstream’s limited partner interests and incentive distribution rights.

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 and transportation of natural gas and natural gas liquids (“NGL”) for third parties, NGL fractionation and distribution, processing of natural gas and the production and sale of salt products.

Following the Inergy Midstream IPO and US Salt contribution, Inergy’s midstream assets include the Tres Palacios natural gas storage facility in Texas and the West Coast NGL business. Through Inergy’s ownership interest in Inergy Midstream, Inergy has an investment in midstream assets including four natural gas storage facilities in New York (Stagecoach, Thomas Corners, Steuben and Seneca Lake), natural gas transportation assets in New York and Pennsylvania, an NGL storage facility in New York (Bath storage facility), and a solution-mining and salt production company (US Salt).

Basis of Presentation

The financial information contained herein as of June 30, 2012, and for the three-month and nine-month periods ended June 30, 2012 and 2011, 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, 2012, are not indicative of the results of operations that may be expected for the entire fiscal year.

The accompanying consolidated financial statements include the accounts of Inergy, L.P. and its wholly owned subsidiaries, Inergy Propane, LLC (“Inergy Propane”), Inergy Partners, LLC (“Partners”), IPCH Acquisition Corp. (“IPCHA”), Tres Palacios Gas Storage LLC and Inergy Finance Corp. The accompanying consolidated financial statements also include the accounts of our majority-owned subsidiary, Inergy Midstream, and its wholly-owned subsidiaries. All significant intercompany transactions, including distribution income, and balances have been eliminated in consolidation.

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

On April 25, 2012, Inergy entered into a definitive agreement to contribute its retail propane operations to Suburban Propane Partners, L.P. (“SPH”). ASC 205 requires that in order for a transaction to be considered discontinued operations, the gross cash flows related to the continuing involvement with the discontinued operations must be immaterial. The financial statements do not report the retail propane operations as discontinued as the involvement of Inergy with the retail propane operations subsequent to the close of this transaction, although sold, is expected to be material due to a propane supply arrangement expected to be executed between Inergy and SPH; however, this continues to be evaluated. The assets and liabilities associated with the retail propane operations have accordingly been classified as held for sale in these financial statements. See Note 5 for a discussion of the amounts related to the assets and liabilities held for sale.

The accompanying consolidated financial statements should be read in conjunction with the consolidated financial statements of Inergy, L.P. and subsidiaries and the notes thereto included in Form 10-K as filed with the Securities and Exchange Commission for the fiscal year ended September 30, 2011.

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 and variable 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 and variable 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 loss of $0.6 million and a net gain of $0.3 million in the three months ended June 30, 2012 and 2011, respectively, and a net loss of $0.1 million and a net gain of $0.3 million in the nine months ended June 30, 2012 and 2011, respectively, related to the ineffective portion of its fair value hedging instruments. In addition, Inergy recognized no gain or loss for the three and nine months ended June 30, 2012 and 2011, 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 and variable interest payments. The commodity derivatives are recorded on the balance sheet at fair value as price risk management assets or liabilities, and the interest rate swaps are recorded as other 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 or interest expense, as applicable, 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 loss was $15.8 million and $6.7 million at June 30, 2012 and September 30, 2011, respectively. Included in accumulated other comprehensive loss at June 30, 2012 was a loss of $9.4 million attributable to commodity instruments and a loss of $6.4 million attributable to interest rate swaps. Included in accumulated other comprehensive loss at September 30, 2011 was a loss of $2.4 million attributable to commodity instruments and a loss of $4.3 million attributable to interest rate swaps. Approximately $8.7 million is expected to be reclassified to earnings from other comprehensive income over the next twelve months. Inergy’s comprehensive income (loss) was $(27.1) million and $(38.3) million for the three months ended June 30, 2012 and 2011, respectively, and $13.6 million and $33.2 million for the nine months ended June 30, 2012 and 2011, respectively.

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

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.

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 $47.0 million and $51.7 million for the three months ended June 30, 2012 and 2011, respectively, and $157.2 million for both the nine months ended June 30, 2012 and 2011.

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 and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the periods presented. 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. Substantially all wholesale propane and other liquids inventories are designated under a fair value hedge program and are consequently marked to market. The remaining portion is stated at the lower of cost or market and is computed predominantly using the average cost method. Propane and other liquids inventories being hedged and adjusted for market value at June 30, 2012 and September 30, 2011, amount to $35.5 million and $147.7 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 historical cost less accumulated depreciation. Inergy capitalizes all construction-related direct labor and material costs as well as the cost of funds used during construction. Amounts capitalized for cost of funds used during construction amounted to $4.2 million and $3.3 million for the three months ended

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

June 30, 2012 and 2011, respectively, and $11.8 million and $11.4 million for the nine months ended June 30, 2012 and 2011, respectively. Depreciation is computed by the straight-line method over the estimated useful lives of the assets, as follows:


	Years
Buildings and improvements		15-25
Office furniture and equipment		3–7
Vehicles		5–10
Tanks and plant equipment		5–30
Base gas		10

Salt deposits are depleted on a unit of production method.

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		15–20
Covenants not to compete		2–10
Deferred financing costs		4–10

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, 2011. No indicators of impairment were identified requiring an interim impairment test during the nine-month period ended June 30, 2012.

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

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

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.

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. Basic net income applicable to partners’ common interest is increased for the disproportionate ownership of Class B units in the undistributed earnings relative to their ownership of distributed earnings. This impact resulted in an increase to basic net income per limited partner unit of $0.02 and $0.05 for the three and nine month periods ended June 30, 2012, respectively. 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. Diluted net income per limited partner unit is not adjusted for the above described difference in Class B units’ share of undistributed and distributed earnings as the calculation assumes full conversion of the Class B units, which results in the most dilutive earnings per unit.

As the effect of including incremental units associated with options were anti-dilutive for the three months ended June 30, 2012 and 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, 2012 and 2011. Anti-dilutive unit options and Class B units outstanding totaled 5,891,953 and 12,041,942 for the three months ended June 30, 2012 and 2011, respectively.

Asset Retirement Obligations

An asset retirement obligation (ARO) is an estimated liability for the cost to retire a tangible asset. The fair value of certain AROs could not be made as settlement dates (or range of dates) associated with these assets were not estimable.

Accounting for Unit-Based Compensation

Inergy sponsors a Long Term Incentive 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 $3.6 million and $1.5 million during the three months ended June 30, 2012 and 2011, respectively, and $9.8 million and $4.4 million during the nine months ended June 30, 2012 and 2011, 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

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

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 11 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, 2012, the estimated fair value of the Company’s fixed-rate Senior Notes, based on available trading information, totaled $1,214.3 million compared with the aggregate principal amount at maturity of $1,200.8 million. The fair value of debt was determined based on market quotes from Bloomberg. This is considered a level 1 pricing source within the fair value hierarchy. At June 30, 2012, the Company’s credit agreement (“Credit Agreement”) consisted of a $550 million revolving loan facility (“Revolving Loan Facility”). The carrying value at June 30, 2012, of amounts outstanding under the Credit Agreement of $170.2 million approximated fair value due primarily to the floating interest rate associated with the Credit Agreement. At June 30, 2012, Inergy Midstream’s $600 million revolving credit facility (“NRGM Credit Facility”) had amounts outstanding of $324.2 million, which approximated fair value due primarily to the floating interest rate associated with borrowings under the NRGM Credit Facility. See Note 8 for a discussion of the Company’s debt.

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 were adopted on October 1, 2011, and are disclosed in Note 7.

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Note 3 – Certain Balance Sheet Information

Inventories consisted of the following at June 30, 2012 and September 30, 2011, respectively (in millions):


	June 30, 2012		September 30, 2011
Propane gas and other liquids	$	40.7	$	149.8
Appliances, parts, supplies and other		5.6		5.3

Total inventory	$	46.3	$	155.1

Property, plant and equipment consisted of the following at June 30, 2012 and September 30, 2011, respectively (in millions):


	June 30, 2012		September 30, 2011
Tanks and plant equipment	$	624.2	$	531.1
Buildings, land and improvements		884.4		840.7
Vehicles		34.8		25.0
Construction in process		307.0		271.7
Base gas		134.0		132.1
Salt deposits		41.6		41.6
Office furniture and equipment		16.7		15.6

		2,042.7		1,857.8
Less: accumulated depreciation		411.1		322.8

Total property, plant and equipment, net	$	1,631.6	$	1,535.0

Intangible assets consisted of the following at June 30, 2012 and September 30, 2011, respectively (in millions):


	June 30, 2012		September 30, 2011
Customer accounts	$	42.5	$	39.7
Covenants not to compete		9.1		7.4
Deferred financing and other costs		42.5		49.5

		94.1		96.6
Less: accumulated amortization		27.1		29.0

Total intangible assets, net	$	67.0	$	67.6

Note 4 – Business Acquisitions

On November 11, 2011, Inergy completed the acquisition of substantially all the assets of Papco, LLC / South Jersey Terminal, LLC (“Papco”), located in Bridgeton, New Jersey.

On January 13, 2012, Inergy completed the acquisition of substantially all the assets of Baker-Doucette, Inc. (d/b/a Woodstock Oil Company) and Rising Moon, LLC (d/b/a Woodstock Propane Company) (“Woodstock”), located in Bryant Pond, Maine.

On February 13, 2012, Inergy completed the acquisition of all operating assets at the Aztec, New Mexico location of Alliance Propane, LLC (d/b/a Mesa Propane).

The above described acquisitions are not material to the financial statements.

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

The purchase price allocation for these acquisitions has been prepared on a preliminary basis pending final asset valuation and asset rationalization. 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 – Assets Held for Sale

As discussed in Note 1, the assets and liabilities associated with the retail propane operations have been classified as held for sale in these financial statements.

The following table details the assets and liabilities held for sale at June 30, 2012 and September 30, 2011, respectively (in millions):


	June 30, 2012		September 30, 2011
Assets held for sale
Accounts receivable, less allowance for doubtful accounts of $1.9 million and $2.4 million at June 30, 2012 and September 30, 2011, respectively	$	42.8	$	54.8
Inventories		38.1		57.8
Prepaid expenses and other current assets		1.9		2.1
Property, plant and equipment, net		460.8		—
Intangible assets, net		293.7		—
Goodwill		336.1		—
Other assets		0.7		0.5

Current assets held for sale		1,174.1		115.2

Property, plant and equipment, net		—		494.4
Intangible assets, net		—		316.2
Goodwill		—		336.1

Total assets held for sale	$	1,174.1	$	1,261.9


Liabilities held for sale
Accounts payable	$	0.2	$	0.6
Accrued expenses		12.9		13.1
Customer deposits		34.9		52.0
Obligations under noncompetition agreements and notes to former owners of businesses acquired		14.0		16.4

Total liabilities held for sale	$	62.0	$	82.1

Note 6 – 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 8. Additional information related to derivatives is provided in Note 2 and Note 7.

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

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 certain of its 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 these 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.

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, 2012 and September 30, 2011, respectively (in millions):


	June 30, 2012				September 30, 2011
	Fixed Price Payor		Fixed Price Receiver		Fixed Price Payor		Fixed Price Receiver
Propane, crude and heating oil (barrels)		6.9		6.4		10.1		10.6
Natural gas (MMBTUs)		8.1		7.8		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.

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

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,
	2012			2011			2012			2011
Derivatives in fair value hedging relationships:
Commodity ^(a)	$	2.9		$	0.2		$	10.7		$	9.5
Debt^(b)		(0.3	)		6.8			—			4.8

Total fair value of derivatives	$	2.6		$	7.0		$	10.7		$	14.3


	Amount of Gain (Loss) Recognized in Net Income on Item Being Hedged
	Three Months Ended June 30,						Nine Months Ended June 30,
	2012			2011			2012			2011
Derivatives in fair value hedging relationships:
Commodity ^(a)	$	(3.5	)	$	0.1		$	(10.8	)	$	(9.2	)
Debt^(b)		0.3			(6.8	)		—			(4.8	)

Total fair value of derivatives	$	(3.2	)	$	(6.7	)	$	(10.8	)	$	(14.0	)


	Amount of Gain (Loss) Recognized in OCI on Effective Portion of Derivatives
	Three Months Ended June 30,						Nine Months Ended June 30,
	2012			2011			2012			2011
Derivatives in cash flow hedging relationships:
Commodity ^(c)	$	(8.5	)	$	0.1		$	(8.8	)	$	0.5
Debt ^(e)		(1.0	)		(2.0	)		(2.1	)		(2.0	)

Total fair value of derivatives	$	(9.5	)	$	(1.9	)	$	(10.9	)	$	(1.5	)


	Amount of Gain (Loss) Reclassified from OCI to Net Income
	Three Months Ended June 30,						Nine Months Ended June 30,
	2012			2011			2012			2011
Derivatives in cash flow hedging relationships:
Commodity ^(c)	$	(0.3	)	$	1.0		$	(1.9	)	$	4.9
Debt ^(e)		0.1			—			0.1			—

Total fair value of derivatives	$	(0.2	)	$	1.0		$	(1.8	)	$	4.9

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)


	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,
	2012		2011		2012		2011
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,
	2012		2011		2012		2011
Derivatives not designated as hedging instruments:
Commodity^(d)	$	6.9	$	5.5	$	11.4	$	11.2

(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.

All contracts subject to price risk had a maturity of twenty-seven months or less; however, approximately 98% of the contracts expire within twelve months.

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, 2012 and September 30, 2011, were energy marketers and propane retailers, resellers and dealers.

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, 2012, is $20.4 million for which the Company has posted collateral of $13.1 million. In addition, the Company has made an initial margin deposit of $13.3 million to NYMEX in the normal course of business. The Company has received collateral of $11.7 million in the normal course of business. All collateral amounts have been netted against the asset or liability with the respective counterparty.

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Note 7 – Fair Value Measurements

FASB Accounting Standards Codification Subtopic 820-10 (“ASC 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, 2012, 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.

No changes in valuation techniques were made by the Company during the nine months ended June 30, 2012.

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, 2012 and September 30, 2011 (in millions):


	June 30, 2012
	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	$	1.7	$	37.8	$	7.6	$	47.1	$	10.0	$	37.1	$	(6.5	)	$	40.6
Inventory		—		35.5		—		35.5		—		—		—			35.5
Interest rate swaps		—		—		—		—		—		—		—			—

Total assets at fair value	$	1.7	$	73.3	$	7.6	$	82.6	$	10.0	$	37.1	$	(6.5	)	$	76.1


Liabilities
Liabilities from price risk management	$	1.2	$	30.5	$	0.4	$	32.1	$	11.5	$	20.6	$	(18.6	)	$	13.5
Interest rate swaps		—		6.4		—		6.4		6.4		—		—			6.4

Total liabilities at fair value	$	1.2	$	36.9	$	0.4	$	38.5	$	17.9	$	20.6	$	(18.6	)	$	19.9


	September 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	$	1.2	$	23.4	$	4.0	$	28.6	$	8.8	$	19.8	$	(11.5	)	$	17.1
Inventory		—		147.7		—		147.7		—		—		—			147.7
Interest rate swap		—		0.5		—		0.5		0.5		—		—			0.5

Total assets at fair value	$	1.2	$	171.6	$	4.0	$	176.8	$	9.3	$	19.8	$	(11.5	)	$	165.3


Liabilities
Liabilities from price risk management	$	0.9	$	15.4	$	2.7	$	19.0	$	5.4	$	13.6	$	—		$	19.0
Interest rate swap		—		4.3		—		4.3		4.3		—		—			4.3

Total liabilities at fair value	$	0.9	$	19.7	$	2.7	$	23.3	$	9.7	$	13.6	$	—		$	23.3

^(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.

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, ASC 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, 2012
Assets
Beginning balance	$	4.0
Beginning balance recognized during the period as a component of cost of product sold		(3.7	)
Change in value of contracts executed during the period		7.3

Ending balance	$	7.6


Liabilities
Beginning balance	$	(2.7	)
Beginning balance recognized during the period as a component of cost of product sold		2.5
Change in value of contracts executed during the period		(0.2	)

Ending balance	$	(0.4	)

Note 8 – Long-Term Debt

Long-term debt consisted of the following at June 30, 2012 and September 30, 2011, respectively (in millions):


	June 30, 2012		September 30, 2011
Inergy credit agreement:
Revolving loan facility	$	170.2	$	81.2
Term loan facility		—		300.0
Inergy senior unsecured notes		1,200.8		1,445.1
Inergy fair value hedge adjustment on senior unsecured notes		—		0.5
Inergy bond/swap premium		10.8		13.8
Inergy bond discount		—		(5.3	)
Inergy obligations under noncompetition agreements and notes to former owners of businesses acquired		2.0		1.3
NRGM credit facility		324.2		—

Total debt		1,708.0		1,836.6
Less: current portion		1,188.5		3.2

Total long-term debt	$	519.5	$	1,833.4

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Included in the current portion of long-term debt is $1,187.0 million of senior notes tendered as of July 26, 2012. On August 1, 2012, these senior notes were exchanged for approximately $1,000.0 million in SPH senior notes and cash from SPH in conjunction with the contribution of Inergy’s retail propane operations to SPH discussed in Notes 1, 5 and 13. These senior notes were cancelled and are no longer on the consolidated balance sheet at August 1, 2012. In accordance with ASC 210, the full amount of the debt tendered has been classified as current on the June 30, 2012 consolidated balance sheet due to the intent at June 30, 2012 to use the retail propane assets held for sale of $1,174.1 million in part to effectuate the exchange of the senior notes.

On November 24, 2009, Inergy entered into a secured credit facility (“Credit Agreement”) which provided 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 was to 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 was to mature on February 2, 2015, and 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 1.00% 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%.

On July 28, 2011, Inergy further amended its amended and restated Credit Agreement to (i) raise the aggregate revolving commitment from $525 million to $700 million (“Revolving Loan Facility”) with the amount existing as a singular tranche, (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.

On April 13, 2012, Inergy further amended its amended and restated Credit Agreement. This amendment, among other things, (i) permits Inergy to sell up to 5,000,000 Inergy Midstream common units, (ii) permits Inergy to sell all of the assets or capital stock of US Salt pursuant to which US Salt will be released as a subsidiary guarantor under the Credit Agreement, (iii) decreases the aggregate revolving commitment and general partnership commitment from $700 million to $550 million, and (iv) adjusts several of the financial covenants.

On July 26, 2012, Inergy further amended its amended and restated Credit Agreement in order to: (i) permit Inergy to enter into a series of transactions as described in the Contribution Agreement dated as of April 25, 2012 among Inergy and Suburban Propane Partners, L.P, (ii) permit Inergy to repurchase, repay or redeem all or any portion of the senior notes that remain outstanding after the closing of the Contribution Agreement, (iii) modify certain negative and financial covenants under the Credit Agreement, and (iv) allow Inergy to redeem, buy back or otherwise acquire up to $100,000,000 of its common units on or prior to March 31, 2013 subject to meeting certain financial covenant requirements. This amendment did not become effective until the contribution of Inergy’s retail propane assets to SPH closed on August 1, 2012. In conjunction with the close of this transaction, $1,187.0 million in Inergy senior notes were exchanged for SPH senior notes, thereby eliminating the senior notes from Inergy’s consolidated balance sheet on August 1, 2012.

The Credit Agreement contains various covenants and restrictive provisions that limit its ability to, among other things:

•

incur additional debt;

•

make distributions on or redeem or repurchase units;

•

make certain investments and acquisitions;

•

incur or permit certain liens to exist;

•

enter into certain types of transactions with affiliates;

•

merge, consolidate or amalgamate with another company; and

•

transfer or otherwise dispose of assets.

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

The Credit Agreement (as of June 30, 2012) contains the following financial covenants:

•

the ratio of Inergy’s total funded debt (as defined in the Credit Agreement) to consolidated EBITDA (as defined in the Credit Agreement) for the four fiscal quarters most recently ended must be no greater than 5.75 to 1.0;

•

the ratio of Inergy’s senior secured funded debt (as defined in the Credit Agreement) to consolidated EBITDA (as defined in the Credit Agreement) for the four fiscal quarters most recently ended must be no greater than 2.75 to 1.0; and

•

the ratio of Inergy’s consolidated EBITDA to consolidated interest expense (as defined in the Credit Agreement), for the four fiscal quarters then most recently ended, must not be less than 2.25 to 1.0.

If Inergy should fail to perform its obligations under these and other covenants, the Revolving Loan Facility could be terminated and any outstanding borrowings, together with accrued interest, under the Credit Agreement could be declared immediately due and payable. The Credit Agreement also has cross default provisions that apply to any other material indebtedness of Inergy.

All borrowings under the Credit Agreement are generally secured by all of Inergy’s assets and the equity interests in all of Inergy’s wholly owned subsidiaries, and loans thereunder bear interest, at Inergy’s option, subject to certain limitations, at a rate equal to the following:

•

the Adjusted LIBO Rate, which is defined as the LIBO Rate plus a margin varying from 1.75% to 3.00%.

In conjunction with the Inergy Midstream IPO, on December 21, 2011, Inergy entered into the following transactions:

•

Entered into a $255 million unsecured promissory note with JPMorgan Chase Bank (“Promissory Note”). The promissory note was assumed by Inergy Midstream and paid in full utilizing proceeds from the IPO.

•

Paid in full the $300 million balance outstanding on the Term Loan Facility.

•

Tendered for substantially all the $95 million outstanding on the 2015 Senior Notes.

•

Tendered for $150 million of the $750 million outstanding on the 2021 Senior Notes.

•

The debt payments described above were funded by the $255 million proceeds from the Promissory Note, $80 million borrowing on the NRGM Credit Facility (discussed below) and borrowings on the Revolving Loan Facility.

At June 30, 2012, the balance outstanding under the Credit Agreement was $170.2 million. At September 30, 2011, the balance outstanding under the Credit Agreement was $381.2 million, of which $300.0 million was borrowed under the Term Loan Facility and $81.2 million under the Revolving Loan Facility. The interest rates of the Revolving Loan Facility are based on prime rate and LIBOR plus the applicable spreads, resulting in interest rates which were between 3.25% and 5.25% at June 30, 2012, and 2.73% and 4.75% at September 30, 2011. The interest rate on the Term Loan Facility was based on LIBOR plus the applicable spread, resulting in an interest rate that was 3.23% at September 30, 2011. Availability under the Credit Agreement amounted to $325.5 million and $575.3 million at June 30, 2012 and September 30, 2011, respectively. Outstanding standby letters of credit under the Credit Agreement amounted to $54.3 million and $43.5 million at June 30, 2012 and September 30, 2011, respectively.

During fiscal year 2011, Inergy entered into eleven interest rate swaps, one of which was scheduled to mature in 2015 (notional amount of $25 million) and the remaining ten were scheduled to mature in 2018 (aggregate notional amount of $250 million). In August 2011, Inergy’s ten interest rate swaps maturing in 2018 were terminated. In December 2011, the remaining interest rate swap maturing in 2015 was terminated and the Company entered into a new interest rate swap scheduled to mature in 2018 (notional amount of $50 million). This swap agreement, which was to expire on the same date as the maturity date of the related senior unsecured notes and contained call provisions consistent with the underlying senior unsecured notes, required the counterparty to pay Inergy an amount based on the stated fixed interest rate due every nine months. In exchange, Inergy was 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 one-month LIBOR interest rate plus a spread of 5.218%

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

applied to the same aggregate notional amount of $50 million. This swap agreement had been accounted for as a fair value hedge. Amounts received or paid under the agreement were accrued and recognized over the life of the agreement as an adjustment to interest expense. In May 2012, this interest rate swap was terminated.

Inergy is party to six interest rate swap agreements scheduled to mature in 2015 to hedge its exposure to variable interest payments due under the Credit Agreement. Certain of these swap agreements with a notional amount of $100.0 million do not commence quarterly settlements until October 1, 2012. These swap agreements require Inergy to pay the counterparty an amount based on fixed rates from 0.84% 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 $225 million. These swap agreements have been accounted for as cash flow hedges.

At June 30, 2012, the Company was in compliance with the debt covenants in the Credit Agreement and senior unsecured notes.

Inergy Midstream’s Credit Facility

On December 21, 2011, Inergy Midstream entered into a new $500 million revolving credit facility (“NRGM Credit Facility”) with a December 2016 maturity date. The NRGM Credit Facility is available to fund acquisitions, working capital and internal growth projects and for general partnership purposes. The NRGM Credit Facility has an accordion feature that allows Inergy Midstream to increase loan commitments by up to $250 million, subject to the lenders’ agreement and the satisfaction of certain conditions. In addition, its credit facility includes a sub-limit up to $10 million for same-day swing line advances and a sub-limit up to $100 million for letters of credit.

On April 16, 2012, Inergy Midstream exercised a portion of its accordion feature under the NRGM Credit Facility and increased the loan commitments thereunder by $100 million. The aggregate amount of revolving loan commitments under the NRGM Credit Facility now equals $600 million. Inergy Midstream may continue to increase the loan commitments by up to $150 million, subject to the lenders’ agreement and the satisfaction of certain conditions.

At June 30, 2012, the balance outstanding under the NRGM Credit Facility was $324.2 million. Outstanding standby letters of credit under the NRGM Credit Facility amounted to $2.1 million at June 30, 2012. As a result, Inergy Midstream has approximately $273.7 million of remaining capacity at June 30, 2012, subject to compliance with any applicable covenants under such facility.

Inergy and its wholly owned subsidiaries do not provide credit support or guarantee any amounts outstanding under the NRGM Credit Facility.

The NRGM Credit Facility contains various covenants and restrictive provisions that limit its ability to, among other things:

•

incur additional debt;

•

make distributions on or redeem or repurchase units;

•

make certain investments and acquisitions;

•

incur or permit certain liens to exist;

•

enter into certain types of transactions with affiliates;

•

merge, consolidate or amalgamate with another company; and

•

transfer or otherwise dispose of assets.

If Inergy Midstream fails to perform its obligations under these and other covenants, the lenders’ credit commitment could be terminated and any outstanding borrowings, together with accrued interest, under its credit facility could be declared immediately due and payable. The NRGM Credit Facility also has cross default provisions that apply to any other material indebtedness of Inergy Midstream.

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Borrowings under the NRGM Credit Facility are generally secured by pledges of the equity interests in Inergy Midstream’s wholly owned subsidiaries, and guarantees issued by all of Inergy Midstream’s subsidiaries. Borrowings under the NRGM Credit Facility (other than swing line loans) will bear interest at its option at either:

•

the Alternate Base Rate, which is defined as the highest 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 0.75% to 1.75% depending on our most recent total leverage ratio; or

•

the Adjusted LIBO Rate, which is defined as the LIBO Rate plus a margin varying from 1.75% to 2.75% depending on Inergy Midstream’s most recent total leverage ratio.

Swing line loans bear interest at the Alternate Base Rate plus a margin varying from 0.75% to 1.75%. The unused portion of the NRGM Credit Facility is subject to a commitment fee ranging from 0.30% to 0.50% per annum according to its most recent total leverage ratio. Interest on Alternative Base Rate loans is payable quarterly or, if the Adjusted LIBO Rate applies, it may be paid at more frequent intervals.

The NRGM Credit Facility requires maintenance of a consolidated leverage ratio (as defined in its credit agreement) of not more than 5.00 to 1.00 and an interest coverage ratio (as defined in its credit agreement) of not less than 2.50 to 1.00.

Note 9 – Partners’ Capital

Inergy Midstream

On May 14, 2012, Inergy Midstream issued 473,707 shares directly to Inergy in conjunction with the contribution of US Salt.

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 December 31, 2011, Inergy distributed 205,748 Class B units. Immediately following this distribution, 50% of the Class B units outstanding that were held by each holder of a Class B unit, and all of the additional Class B units issued in kind as a distribution during the four-quarter period following the Merger, converted into Inergy common units at a conversion ratio of one Class B unit for one Inergy common unit. This resulted in the conversion of 6,586,968 Class B units into Inergy common 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.

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Quarterly Distributions of Available Cash

A summary of the Company’s post-simplification limited partner quarterly distribution for the nine months ended June 30, 2012, is presented below:


Nine Months Ended June 30, 2012
Record Date	Payment Date		Per Unit Rate		Distribution Amount *(in millions)*
November 7, 2011		November 14, 2011	$	0.705	$	83.9
February 7, 2012		February 14, 2012	$	0.705		88.7
May 8, 2012		May 15, 2012	$	0.375		47.1

					$	219.7

On July 26, 2012, Inergy declared a distribution of $0.375 per limited partner unit to be paid on August 14, 2012, to unitholders of record on August 7, 2012.

Note 10 – Commitments and Contingencies

Inergy’s propane operations periodically enter into agreements with suppliers to purchase fixed quantities of propane, distillates, natural gas and liquids at fixed prices. At June 30, 2012, the total of these firm purchase commitments was $259.0 million, approximately 98% 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’s midstream operations have entered into certain purchase commitments in connection with the identified growth projects primarily related to the Watkins Glen NGL development project and the MARC I pipeline. The Watkins Glen NGL development project entails the conversion of certain caverns created by US Salt into 2.1 million barrels of NGL storage. The MARC I pipeline project is a 39 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, 2012, the total of Inergy’s midstream operations’ firm purchase commitments was approximately $50.8 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.

Following the announcement of the Merger Agreement, two class action lawsuits were filed by unitholders of Inergy (the “Inergy Unitholder Lawsuits”) 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 parties to the Inergy Unitholder Lawsuits have entered into a Memorandum of Understanding whereby in consideration for the settlement and dismissal of the claims, the individual Class B unitholders will forego and relinquish a total of 135,539 Class B units to be received as distributions following the date on which the settlement and dismissal become final and no longer appealable. On March 29, 2012, the court approved the terms of the settlement, which included the certification of a settlement class and the dismissal with prejudice of all claims. Also as part of the settlement, the defendants in the Inergy Unitholder Lawsuits other than Inergy must pay fees and expenses to counsel for the plaintiffs in the amount of $1.8 million, which amount is covered by insurance.

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

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

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, 2012 and September 30, 2011, Inergy’s self-insurance reserves were $25.2 million and $20.6 million, respectively. Inergy estimates that $14.1 million of this balance will be paid subsequent to June 30, 2013. As such, $14.1 million has been classified in other long-term liabilities on the consolidated balance sheets.

Note 11 – 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 and transportation of natural gas and NGL for third parties, NGL fractionation and distribution, processing of natural gas and the production and sale of salt products. Results of operations for the current year acquisitions are included in the propane 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. Assets and liabilities held for sale are related entirely to the propane segment.

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, 2012
	Propane Operations		Midstream Operations		Intersegment Operations			Corporate Assets		Total
Retail propane revenues	$	96.3	$	—	$	—		$	—	$	96.3
Wholesale propane revenues		100.6		6.8		—			—		107.4
Storage, fractionation and other midstream revenues		—		120.4		(3.3	)		—		117.1
Transportation revenues		14.9		4.9		—			—		19.8
Propane-related appliance sales revenues		3.3		—		—			—		3.3
Retail service revenues		3.6		—		—			—		3.6
Rental service and other revenues		5.2		—		—			—		5.2
Distillate revenues		18.9		—		—			—		18.9
Gross profit (excluding depreciation and amortization)		73.2		56.9		—			—		130.1
Identifiable assets		81.9		52.9		—			—		134.8
Goodwill		0.4		141.8		—			20.2		162.4
Property, plant and equipment		26.0		2,010.8		—			5.9		2,042.7
Expenditures for property, plant and equipment		2.4		62.2		—			0.2		64.8


	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 (excluding depreciation and amortization)		72.2		46.9		(2.1	)		—		117.0
Identifiable assets		98.7		80.7		—			—		179.4
Goodwill		—		141.3		—			20.2		161.5
Property, plant and equipment		14.9		1,707.4		—			12.0		1,734.3
Expenditures for property, plant and equipment		3.8		60.1		—			—		63.9

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)


	Nine Months Ended June 30, 2012
	Propane Operations		Midstream Operations		Intersegment Operations			Corporate Assets		Total
Retail propane revenues	$	601.1	$	—	$	—		$	—	$	601.1
Wholesale propane revenues		494.4		37.1		(0.3	)		—		531.2
Storage, fractionation and other midstream revenues		—		381.0		(8.7	)		—		372.3
Transportation revenues		41.1		14.4		—			—		55.5
Propane-related appliance sales revenues		13.3		—		—			—		13.3
Retail service revenues		11.8		—		—			—		11.8
Rental service and other revenues		21.2		—		—			—		21.2
Distillate revenues		96.2		—		—			—		96.2
Gross profit (excluding depreciation and amortization)		346.7		164.0		—			—		510.7
Identifiable assets		81.9		52.9		—			—		134.8
Goodwill		0.4		141.8		—			20.2		162.4
Property, plant and equipment		26.0		2,010.8		—			5.9		2,042.7
Expenditures for property, plant and equipment		10.7		168.4		—			0.5		179.6


	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 (excluding depreciation and amortization)		431.6		136.0		(2.9	)		—		564.7
Identifiable assets		98.7		80.7		—			—		179.4
Goodwill		—		141.3		—			20.2		161.5
Property, plant and equipment		14.9		1,707.4		—			12.0		1,734.3
Expenditures for property, plant and equipment		11.4		123.1		—			0.4		134.9

Note 12 – Condensed Consolidating Financial Information

Inergy is a holding company and owns no operating assets and has no significant operations independent of its subsidiaries. Obligations under its outstanding senior notes listed in Note 8 are jointly and severally guaranteed by Inergy’s wholly owned domestic subsidiaries. Subsequent to Inergy Midstream’s IPO on December 21, 2011, Inergy Midstream and its wholly owned subsidiaries no longer guarantee Inergy’s senior notes.

The tables below present condensed consolidated financial statements for Inergy (parent) on a stand-alone, unconsolidated basis, and its combined guarantor and combined non-guarantor subsidiaries as of June 30, 2012, and for the three and nine months ended June 30, 2012. Comparative financial statements have not been provided as Inergy Midstream was a guarantor of the senior notes in the prior period. The financial information may not necessarily be indicative of the results of operations, cash flows or financial position had the subsidiaries operated as independent entities.

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Condensed Consolidating Balance Sheet

As of June 30, 2012

(in millions)


	Parent		Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	3.0	$	1.9	$	—	$	—		$	4.9
Accounts receivable		—		67.0		21.5		—			88.5
Inventories		—		41.3		5.0		—			46.3
Other		—		58.6		5.8		(0.1	)		64.3
Current assets held for sale		—		1,174.1		—		—			1,174.1

Total current assets		3.0		1,342.9		32.3		(0.1	)		1,378.1

Property, plant and equipment, net		—		854.7		776.9		—			1,631.6
Goodwill and intangible assets, net		20.2		82.6		126.6		—			229.4
Investment in subsidiary		2,468.6		—		—		(2,468.6	)		—
Other assets		—		1.4		—		—			1.4

Total assets	$	2,491.8	$	2,281.6	$	935.8	$	(2,468.7	)	$	3,240.5


Liabilities and partners’ capital
Current liabilities:
Accounts payable	$	—	$	88.8	$	13.2	$	—		$	102.0
Other		1,188.5		67.2		30.4		(0.1	)		1,286.0
Liabilities held for sale		—		62.0		—		—			62.0

Total current liabilities		1,188.5		218.0		43.6		(0.1	)		1,450.0

Long-term liabilities:
Long-term debt, less current portion		195.5		—		324.0		—			519.5
Other long-term liabilities		19.7		20.5		0.9		—			41.1

Total long-term liabilities		215.2		20.5		324.9		—			560.6

Partners’ capital		1,088.1		2,043.1		425.5		(2,468.6	)		1,088.1
Interest of non-controlling partners in subsidiary		—		—		141.8		—			141.8

Total partners’ capital		1,088.1		2,043.1		567.3		(2,468.6	)		1,229.9

Total liabilities and partners’ capital	$	2,491.8	$	2,281.6	$	935.8	$	(2,468.7	)	$	3,240.5

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Condensed Consolidating Statements of Operations

Three Months Ended June 30, 2012

(in millions)


	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Revenue:
Propane	$	—		$	203.7		$	—		$	—		$	203.7
Other		—			122.6			48.6			(3.3	)		167.9

		—			326.3			48.6			(3.3	)		371.6

Cost of product sold (excluding depreciation and amortization as shown below):
Propane		—			148.2			—			—			148.2
Other		—			87.6			9.0			(3.3	)		93.3

		—			235.8			9.0			(3.3	)		241.5

Expenses:
Operating and administrative		—			75.0			8.1			—			83.1
Depreciation and amortization		—			25.4			12.8			—			38.2
Loss on disposal of assets		—			2.2			—			—			2.2

Operating income (loss)		—			(12.1	)		18.7			—			6.6

Other income (expense):
Interest expense, net		(22.1	)		—			(0.7	)		—			(22.8	)
Early extinguishment of debt		(1.7	)		—			—			—			(1.7	)
Other income		—			0.1			—			—			0.1
Equity in net income of subsidiary		2.0			—			—			(2.0	)		—

Income (loss) before income taxes		(21.8	)		(12.0	)		18.0			(2.0	)		(17.8	)
Benefit for income taxes		—			0.1			—			—			0.1

Net income (loss)		(21.8	)		(11.9	)		18.0			(2.0	)		(17.7	)
Net income attributable to non-controlling partners in subsidiary		—			—			(4.1	)		—			(4.1	)

Net income (loss) attributable to partners	$	(21.8	)	$	(11.9	)	$	13.9		$	(2.0	)	$	(21.8	)

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Condensed Consolidating Statements of Operations

Nine Months Ended June 30, 2012

(in millions)


	Parent			Guarantor Subsidiaries		Non- Guarantor Subsidiaries			Eliminations			Consolidated
Revenue:
Propane	$	—		$	1,132.3	$	—		$	—		$	1,132.3
Other		—			436.5		142.3			(8.5	)		570.3

		—			1,568.8		142.3			(8.5	)		1,702.6

Cost of product sold (excluding depreciation and amortization as shown below):
Propane		—			851.2		—			—			851.2
Other		—			318.1		31.1			(8.5	)		340.7

		—			1,169.3		31.1			(8.5	)		1,191.9

Expenses:
Operating and administrative		—			226.1		21.0			—			247.1
Depreciation and amortization		—			99.1		37.5			—			136.6
Loss on disposal of assets		—			5.8		—			—			5.8

Operating income		—			68.5		52.7			—			121.2

Other income (expense):
Interest expense, net		(72.5	)		—		(0.7	)		—			(73.2	)
Early extinguishment of debt		(26.6	)		—		—			—			(26.6	)
Other income		—			1.5		—			—			1.5
Equity in net income of subsidiary		114.0			—		—			(114.0	)		—

Income (loss) before income taxes		14.9			70.0		52.0			(114.0	)		22.9
Provision for income taxes		—			0.2		—			—			0.2

Net income (loss)		14.9			69.8		52.0			(114.0	)		22.7
Net income attributable to non-controlling partners in subsidiary		—			—		(7.8	)		—			(7.8	)

Net income (loss) attributable to partners	$	14.9		$	69.8	$	44.2		$	(114.0	)	$	14.9

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Condensed Consolidating Statements of Cash Flows

Nine Months Ended June 30, 2012

(in millions)


	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities	$	—		$	149.3		$	103.9		$	—		$	253.2


Cash flows from investing activities:
Acquisitions, net of cash acquired		—			(22.3	)		—			—			(22.3	)
Purchases of property, plant and equipment		—			(39.4	)		(130.4	)		—			(169.8	)
US Salt, LLC contribution, net		—			107.7			(107.7	)		—			—
Other		—			7.3			—			—			7.3

Net cash provided by (used in) investing activities		—			53.3			(238.1	)		—			(184.8	)


Cash flows from financing activities:
Proceeds from the issuance of long-term debt		255.0			887.2			385.8			—			1,528.0
Principal payments on long-term debt		(255.0	)		(1,089.1	)		(316.6	)		—			(1,660.7	)
Distributions paid		(360.8	)		(219.7	)		(141.1	)		501.9			(219.7	)
Distributions paid to non-controlling partners		—			—			(7.6	)		—			(7.6	)
Distributions received		360.8			141.1			—			(501.9	)		—
Net proceeds from the issuance of common units		—			—			292.7			—			292.7
US Salt, LLC contribution, net		—			74.8			(74.8	)		—			—
Other		—			(3.5	)		(4.2	)		—			(7.7	)

Net cash provided by (used in) financing activities		—			(209.2	)		134.2			—			(75.0	)


Net decrease in cash		—			(6.6	)		—			—			(6.6	)
Cash at beginning of period		3.0			8.5			—			—			11.5

Cash at end of period	$	3.0		$	1.9		$	—		$	—		$	4.9

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Note 13 – Subsequent Events

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

On July 26, 2012, Inergy declared a distribution of $0.375 per limited partner unit to be paid on August 14, 2012, to unitholders of record on August 7, 2012.

On August 1, 2012, Inergy closed on its definitive agreement and contributed its retail propane operations to Suburban Propane Partners, L.P. (“SPH”) in exchange for consideration of approximately $1.8 billion. Under the terms of the agreement, Inergy received approximately 14.2 million SPH common units; and SPH exchanged $1,187.0 million of Inergy’s outstanding senior notes for approximately $1,000.0 million of new SPH senior notes and cash paid to noteholders tendering the exchange. Inergy has agreed to distribute approximately 14.1 million of the SPH common units it received to NRGY unitholders of record on a pro rata basis at a future record date to be determined by the board of directors of NRGY’s managing general partner, which management expects to occur within the next 30-45 days.

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, 2011. Unless the context indicates otherwise, the terms “Inergy,” “we,” “us,” “our,” “ours” and similar terms refer to Inergy, L.P. and its subsidiaries.

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”. Such forward-looking statements include, but are not limited to, statements that: (i) 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, (ii) we believe that the economic downturn that began in the second half of 2008 has caused certain of our retail propane customers to conserve or seek cheaper suppliers or energy sources and thereby purchase less propane, (iii) we believe our midstream operations could be negatively affected in the long term by sustained downturns or sluggishness in the economy and narrow seasonal spreads in the cost of natural gas along with new natural gas supply from prolific shale plays, which could affect long-term demand and market prices for natural gas and NGLs, (iv) we anticipate completion of our announced midstream capital expansion projects at various times, and (v) 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; failure to achieve growth plans; 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 (including permit and other regulatory proceedings associated with our development projects) and other risks and uncertainties detailed in our Securities and Exchange Commission filings. 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.

Recent Developments

Propane Operations

Credit Facility

On July 26, 2012, we further amended our amended and restated Credit Agreement in order to: (i) permit us to enter into a series of transactions as described in the Contribution Agreement dated as of April 25, 2012 among us and SPH, (ii) permit us to repurchase, repay or redeem all or any portion of the senior notes that remain outstanding after the closing of the Contribution Agreement, (iii) modify certain negative and financial covenants under the Credit Agreement, and (iv) allow us to redeem, buy back or otherwise acquire up to $100,000,000 of our common units on or prior to March 31, 2013.

Overview

We are a Delaware limited partnership formed to own and operate a growing retail and wholesale propane supply, marketing and distribution business. We also own a 75.0% limited partner interest and all the IDRs in Inergy Midstream, L.P. (“Inergy Midstream”). Inergy Midstream owns a growing midstream business that includes four natural gas storage facilities (Stagecoach, Thomas Corners, Steuben and Seneca Lake), interstate and intrastate natural gas transportation facilities in New York, a natural gas liquids (“NGL”) storage facility (the Bath storage facility) and a solution-mining and salt production company (US Salt). In addition to our interest in Inergy Midstream, we own midstream businesses including a natural gas storage facility (Tres Palacios) and an NGL business on the West Coast. We further intend to pursue our growth objectives in the midstream business through, among other things, future acquisitions. 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. Although the discussion below includes our retail propane business, effective August 1, 2012, we contributed this business to SPH.

Over the past several years, we have transformed our company from a propane distribution company into a diversified master limited partnership with significant investment in both the propane and midstream sectors. We continuously evaluate the best way to grow our company and unlock value for our unit holders. For example, we completed an initial public offering of approximately 25% of Inergy Midstream in December 2011. We expect to continue to evaluate transactions that both create investor value and grow our business, as it relates to both our propane and our midstream businesses.

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.

We have grown primarily through acquisitions. Since the inception of our predecessor in November 1996 through June 30, 2012, we have acquired 93 companies, including 85 retail propane companies and 8 midstream businesses, for an aggregate purchase price of approximately $2.9 billion, including working capital, assumed liabilities and acquisition costs.

On November 11, 2011, we completed the acquisition of Papco, LLC / South Jersey Terminal, LLC (“Papco”), located in Bridgeton, New Jersey.

On January 13, 2012, we completed the acquisition of substantially all the assets of Baker-Doucette, Inc. (d/b/a Woodstock Oil Company) and Rising Moon, LLC (d/b/a Woodstock Propane Company) (“Woodstock”), located in Bryant Pond, Maine.

On February 13, 2012, we completed the acquisition of all operating assets at the Aztec, New Mexico location (“Aztec”) of Alliance Propane, LLC (d/b/a Mesa Propane).

The purchase price allocation for these acquisitions has been prepared on a preliminary basis pending final asset valuation and asset rationalization. Changes to reflect 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 nine-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 nine-month peak heating season of October through March, have a significant effect on our financial performance. In any given area, warmer-than-normal temperatures, such as those we experienced in the nine months ended June 30, 2012, 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, 2011 and 2012. At the main pricing hub of Mont Belvieu, Texas (“Mt. Belvieu Price”) during the three-month period ended June 30, 2012, the average Mt. Belvieu Price was $0.97 with prices ranging from a low of $0.71 per gallon to a high of $1.22 per gallon and a price of $0.82 per gallon at June 30, 2012. During the nine-month period ended June 30, 2012, the average propane price was $1.22 with propane prices ranging from a low of $0.71 per gallon to a high of $1.54 per gallon. Further, the average Mt. Belvieu Price in our fiscal years of 2009, 2010 and 2011 was $0.77, $1.12 and $1.42 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 had historically been successful in passing on price increases to our customers, we were unable to fully do so in the three and nine months ended June 30, 2012, and we may not be able to fully do so 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 such as electricity and wood-burning and pellet-burning stoves which have become more economical than propane due to the high cost of propane, all of which has resulted in a decline in gross profit. These trends generally increase in periods of sustained cost increases such as we experienced as described above including thus far in fiscal 2012. 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 if 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 having a much closer correlation 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 further declined and remained at historically low levels since 2008, crude oil costs leveled off in the spring of 2009 before beginning another increase that persisted through the winter seasons of 2009-2010, 2010-2011 and 2011-2012 with propane prices following a similar pattern for the majority of this time. Further, propane was exported from the United States in greater quantities in 2011, and continues as such into 2012, than in the past due to higher propane costs overseas, leading to sustained higher propane costs in the United States. 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 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, shop for lower prices that may be available from other suppliers or begin using alternative energy sources, such as electricity or wood burning and pellet burning stoves to replace some or all of their propane usage.

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, transportation, 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 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 with prolific new shale plays primarily, and this dramatic change could affect our operations. Our Texas storage asset is currently being negatively impacted by both of these occurrences with both low natural gas prices and a narrow seasonal spread.

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 is satisfied primarily by production from conventional onshore and offshore production in the lower 48 states, as supplemented by production from historically declining pipeline imports from Canada, imports of LNG from foreign sources, and some Alaska production. In order to maintain current levels of U.S. natural gas supply and to meet the projected increase in demand, new sources of domestic natural gas must continue to be developed to offset an established trend of depletion associated with mature, conventional production as well as the uncertainty of future LNG imports and infrastructure challenges associated with sourcing additional production from Alaska. Over the past several years, a fundamental shift in production has emerged with the contribution of natural gas from unconventional resources (defined by the EIA as natural gas produced from shale formations and coal beds) increasing from 6% of total U.S. natural gas supply in 2000 to 16% in 2008. In fact, according to EIA data, during the three-year period from January 15, 2007 through December 15, 2010 domestic production of natural gas increased by an average of approximately 4% per annum, largely due to continued development of shale resources. The emergence of shale plays has resulted primarily from advances in horizontal drilling and hydraulic fracturing technologies, which have allowed producers to extract significant volumes of natural gas from these plays at cost-advantaged per unit economics versus most conventional plays.

Inergy Midstream has several significant capital projects under development related to its midstream operations, including:

•

MARC I Pipeline

Inergy Midstream is constructing the MARC I pipeline, a fully contracted natural gas transmission pipeline with 550 MMcf/d of interstate transportation service, which it expects to complete and place into service in 2012 with contracts extending to 2022. Inergy Midstream obtained its FERC certificate order authorizing the MARC I project in November 2011, and commenced full-scale construction in February 2012.

On February 13, 2012, the FERC denied an intervener’s request to stay and rehear the MARC I certificate order. On February 14, 2012, the intervener filed an appeal and emergency motion for stay of the MARC I certificate order with the Second Circuit Court of Appeals, and a temporary stay was granted on February 17, 2012. The temporary stay remained in place until it was vacated by a three-judge panel following oral arguments on February 28, 2012. On March 6, 2012, the Second Circuit granted the intervener’s request for an expedited briefing schedule. Briefs were filed by all parties in March and April, and oral arguments were held on May 31, 2012. On June 12, 2012, the appellate court held that FERC had properly discharged its responsibilities and denied with prejudice the intervener’s petition challenging FERC’s MARC I certificate order.

Inergy Midstream continues to construct the pipeline and expects to place into service the north 20-mile segment by September 1, 2012, and to complete and place into service the rest of the pipeline by October 1, 2012.

•

Watkins Glen NGL Storage Project

Inergy Midstream is developing a 2.1 million barrel NGL storage facility located near Watkins Glen, New York, which is approximately 95% contracted under a contract extending to 2016. Inergy Midstream continues to face delays in the permitting process due to other regulatory priorities (e.g., implementation of “fracking” regulations) and other reasons. Inergy Midstream expects to receive the underground storage permit required for the project this calendar year, and to complete and place into service the storage facility within 120 days of the final permit being granted.

•

North/South II Expansion Project

Inergy Midstream is developing the North/South II expansion project, which is expected to enable shippers to move higher volumes of natural gas bi-directionally through the Stagecoach facility from Millennium to TGP’s 300 Line, and all points in between. As part of this project, Inergy Midstream plans to (i) extend the Stagecoach north lateral approximately three miles to interconnect with the East Pipeline, which will allow shippers to transport volumes from TGP’s 300 Line (as well as intermediate points, including Millennium) to the point of interconnection between the East Pipeline and the Dominion transmission system in Tompkins County, New York, and (ii) expand, through the installation of additional compression or looping, the capacity of the Stagecoach laterals, which will enable shippers to move higher volumes of natural gas over the existing North/South pipeline route. Inergy Midstream is working to acquire the land required to complete the 3-mile lateral extension under CNYOG’s blanket authority, evaluating uprating options for the East Pipeline, and discussing commercial commitments with potential shippers.

•

Commonwealth Pipeline

On February 29, 2012, Inergy Midstream announced plans to explore the marketing and development of a new interstate natural gas pipeline (“Commonwealth Pipeline”) with affiliates of UGI Corporation and WGL Holdings, Inc. As proposed, Commonwealth Pipeline would run approximately 200 miles from the southern terminus of Inergy Midstream’s MARC I pipeline to a point of interconnection with Washington Gas Light’s distribution system in Maryland. Inergy Midstream is exploring costs, route options and other information required to complete a feasibility study, and assessing market demand for the proposed transportation capacity. To the extent the partners determine that the project is economically feasible, affiliates of UGI Corporation and WGL Holdings, Inc. are expected to become anchor shippers on the new pipeline. The project sponsors held a non-binding open season for capacity on the Commonwealth Pipeline in the second calendar quarter, and on June 18, 2012, announced that the initial results from the open season were positive. The project sponsors are working to finalize route information and have commenced negotiating precedent agreements with potential shippers.

In addition to Inergy Midstream’s significant growth projects, Inergy Midstream is working on a number of initiatives that it expects to enhance customer flexibility, deliver operational synergies and augment its platform of future growth opportunities. For example, in the second calendar quarter Inergy Midstream (i) filed applications requesting FERC authorization to effectively convert its Steuben gas tariff from cost-based rates to market-based rates, by merging the entity that owns its Steuben gas storage facility into the entity that owns its Thomas Corner and Seneca Lake gas storage facilities, and (ii) interconnected its Seneca Lake west lateral pipeline and the Millennium Pipeline, thus enhancing deliverability and receipt flexibility for its Seneca Lake natural gas storage customers.

In addition, we also have the following capital project under development related to our midstream operations:

•

the Tres Palacios header extension project, which involves laying approximately 20 miles of pipeline to connect the Tres Palacios north header system to the tailgate of Copano’s Houston Central gas processing plant in Colorado County, Texas. On December 20, 2011, we filed an application with the FERC requesting the authorization required to complete this project. We expect to receive FERC authorization and place the extension project into service in the second half of calendar 2012.

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, 2012, of approximately $50.8 million in our midstream operations. These capital requirements, along with the refinancings of normal maturities of existing debt, will 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, 2012 Compared to Three Months Ended June 30, 2011

The following table summarizes the consolidated statement of operations components for the three months ended June 30, 2012 and 2011, respectively (in millions):


	Three Months Ended June 30,						Change
	2012			2011			In Dollars			Percentage
Revenue	$	371.6		$	388.7		$	(17.1	)		(4.4	)%
Cost of product sold		241.5			271.7			(30.2	)		(11.1	)

Gross profit (excluding depreciation and amortization)		130.1			117.0			13.1			11.2
Operating and administrative expenses		83.1			77.4			5.7			7.4
Depreciation and amortization		38.2			48.0			(9.8	)		(20.4	)
Loss on disposal of assets		2.2			0.5			1.7			340.0

Operating income (loss)		6.6			(8.9	)		15.5			174.2
Interest expense, net		(22.8	)		(27.2	)		4.4			16.2
Early extinguishment of debt		(1.7	)		(0.2	)		(1.5	)		(750.0	)
Other income		0.1			1.1			(1.0	)		(90.9	)

Loss before income taxes		(17.8	)		(35.2	)		17.4			49.4
Benefit (provision) for income taxes		0.1			(0.3	)		0.4			133.3

Net loss		(17.7	)		(35.5	)		17.8			50.1
Net income attributable to non-controlling partners		(4.1	)		—			(4.1	)		*

Net loss attributable to partners	$	(21.8	)	$	(35.5	)	$	13.7			38.6	%

* Not meaningful

The following table summarizes revenues, including associated volume of gallons sold, for the three months ended June 30, 2012 and 2011, respectively (in millions):


	Revenues										Gallons
	Three Months Ended June 30,				Change						Three Months Ended June 30,				Change
	2012		2011		In Dollars			Percent			2012		2011		In Units			Percent
Propane
Retail propane	$	96.3	$	120.1	$	(23.8	)		(19.8	)%		38.9		45.7		(6.8	)		(14.9	)%
Wholesale propane		107.4		100.3		7.1			7.1			107.0		66.6		40.4			60.7
Other retail		45.9		43.0		2.9			6.7			—		—		—			—
Midstream		122.0		125.3		(3.3	)		(2.6	)		—		—		—			—

Total	$	371.6	$	388.7	$	(17.1	)		(4.4	)%		145.9		112.3		33.6			29.9	%

Volume. During the three months ended June 30, 2012, we sold 38.9 million retail gallons of propane, a decrease of 6.8 million gallons or 14.9% from the 45.7 million retail gallons sold during the same three-month period in 2011. Gallons sold during the three months ended June 30, 2012, decreased compared to the same prior year period primarily as a result of lower volumes sold at our existing locations of 6.9 million, partially offset by acquisition-related volume of 0.1 million. During the three months ended June 30, 2012, we believe that retail propane gallon sales continued to be impacted by several ongoing factors, including, most notably, lower demand arising from customer conservation, high commodity prices, significantly above average temperatures that continued from the two previous quarters, and customers switching to other suppliers or energy sources.

Wholesale gallons delivered increased 40.4 million gallons, or 60.7%, to 107.0 million gallons in the three months ended June 30, 2012, from 66.6 million gallons in the three months ended June 30, 2011. This increase was driven primarily by several factors as follows: 1) gallons arising from certain new contracts with third parties to market and deliver all of the product produced at certain of their production facilities; 2) new gallons arising from an increase in production related to another facility for which we had an existing contract to market and deliver all of the product produced at that facility; and 3) increased gallon sales to new and certain of our existing customers.

The total natural gas liquid gallons sold or processed by our West Coast NGL operations increased 16.2 million gallons, or 17.3%, to 110.1 million gallons during the three months ended June 30, 2012, from 93.9 million gallons during the same three-month period in 2011. This increase was primarily attributable to increased volume processed and increased volume of natural gas liquid products processed due to new contracts with existing customers.

During the three months ended June 30, 2012 and 2011, our Northeast natural gas facilities (Stagecoach, Steuben and Thomas Corners) were 95% to 100% contracted on a firm basis and our Bath NGL storage facility was approximately 100% contracted. Our Tres Palacios storage facility was approximately 53% and 60% contracted on a firm basis during the three months ended June 30, 2012 and 2011, respectively. Additionally, our Tres Palacios storage facility was approximately 100% and 73% contracted including interruptible storage contracts during the three months ended June 30, 2012 and 2011, respectively. Our Seneca Lake storage facility, which was acquired in July 2011, was approximately 70% contracted on a firm basis during the three months ended June 30, 2012.

Revenues. Revenues for the three months ended June 30, 2012, were $371.6 million, a decrease of $17.1 million, or 4.4%, from $388.7 million during the same prior year period.

Revenues from retail propane sales were $96.3 million for the three months ended June 30, 2012, compared to $120.1 million during the same three-month period in 2011. This $23.8 million, or 19.8%, decrease was primarily due to an $18.2 million decline arising from lower gallons sold to existing customers as described above and a $5.9 million decline due to a lower overall average selling price of propane. These factors were partially offset by a $0.3 million increase resulting from acquisition-related sales. As discussed below, the lower overall average selling price resulted from a decline in the cost of propane during the three months ended June 30, 2012 compared to the same prior year period.

Revenues from wholesale propane sales were $107.4 million in the three months ended June 30, 2012, an increase of $7.1 million, or 7.1%, from $100.3 million in the three months ended June 30, 2011. The increase can be attributed to greater volumes sold to existing and new customers, which contributed $60.9 million to the increase, partially offset by a decrease of $53.9 million due to a lower average sales price for commodities sold.

Revenues from other retail sales, which primarily includes distillates, service, rental, appliance sales and transportation services, were $45.9 million for the three months ended June 30, 2012, an increase of $2.9 million, or 6.7%, from $43.0 million during the same three-month period in 2011. Revenues from other retail sales increased $12.2 million as a result of acquisition-related sales, partially offset by a $4.1 million decrease in distillate revenues and a $5.2 million decline in other revenues. The decline in distillate revenues was driven by a $4.4 million decrease due to lower volumes sold at existing locations, partially offset by an increase of $0.3 million arising from a higher selling price of distillates.

Revenues from storage, fractionation and other midstream activities were $122.0 million for the three months ended June 30, 2012, a decrease of $3.3 million or 2.6% from $125.3 million during the same three-month period in 2011. Revenues from our West Coast NGL operations decreased $12.6 million primarily as a result of lower average selling prices, which was partially offset by new contracts with existing customers. In addition, revenues at our Stagecoach facility increased $4.6 million due to the placement into service of our North/South expansion project, and $1.9 million due to demand for interruptible wheeling service as a result of customer demand to move gas to and from our interconnecting pipes primarily due to increasing natural gas development in Pennsylvania. Additionally, the acquisition of our Seneca Lake storage facility in July 2011 increased revenue by $2.2 million.

Cost of Product Sold. Cost of product sold for the three months ended June 30, 2012, was $241.5 million, a decrease of $30.2 million, or 11.1%, from $271.7 million during the same three-month period in 2011.

Retail propane cost of product sold was $48.5 million for the three months ended June 30, 2012, a decrease of $22.7 million, or 31.9%, when compared to $71.2 million for the same three-month period in 2011. Retail cost of product sold was driven by a $12.5 million decrease resulting from a lower weighted average cost per gallon and a $10.7 million decline due to lower volumes sold at existing locations as discussed above, partially offset by a $0.4 million increase due to changes in non-cash charges on derivative contracts associated with retail propane fixed price sales contracts and a $0.1 million increase due to acquisition-related sales. The lower weighted average cost was impacted by an approximate 35% decline in the wholesale cost of propane during the three months ended June 30, 2012 compared to the same prior year period.

Wholesale propane cost of product sold in the three months ended June 30, 2012, was $99.7 million, an increase of $6.9 million, or 7.4%, from wholesale cost of product sold of $92.8 million in the three months ended June 30, 2011. This increase can be attributed to greater volumes sold to existing and new customers, which contributed $56.4 million to the increase, partially offset by a $49.5 million decrease due to a lower average purchase price.

Other retail cost of product sold was $28.3 million for the three months ended June 30, 2012, compared to $27.2 million during the same three-month period in 2011. This $1.1 million, or 4.0%, increase in other retail cost of product sold was primarily due to an increase in cost due to acquisitions of $7.7 million, partially offset by a $3.9 million decline in the cost of product sold for distillates and a $2.7 million decrease in other cost of retail sales.

Storage, fractionation and other midstream cost of product sold was $65.0 million for the three months ended June 30, 2012, a decrease of $15.5 million, or 19.3%, from $80.5 million during the same three-month period in 2011. Costs from our West Coast NGL operations decreased $11.5 million primarily as a result of lower average commodity prices of natural gas liquids. Stagecoach storage cost decreased $1.8 million comprised primarily of a $2.7 million decrease due to insurance reimbursements from a December 2010 compressor loss claim at the Stagecoach facility. Offsetting these decreases was an increase of $1.6 million resulting from storage related costs incurred as a result of placing our North/South expansion project into service in December 2011.

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 $15.5 million and $17.9 million for the three months ended June 30, 2012 and 2011, respectively. In addition, the depreciation expense associated with the delivery vehicles and customer tanks is reported within depreciation and amortization expense and amounted to $2.0 million and $7.3 million for the three months ended June 30, 2012 and 2011, 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 services amounted to $28.0 million and $25.4 million for the three months ended June 30, 2012 and 2011, respectively. Vehicle costs and wages for personnel directly involved in providing midstream services amounted to $1.5 million and $1.1 million for the three months ended June 30, 2012 and 2011, 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 (Excluding Depreciation and Amortization). Gross profit for the three months ended June 30, 2012, was $130.1 million, an increase of $13.1 million, or 11.2%, from $117.0 million during the same three-month period in 2011.

Retail propane gross profit was $47.8 million for the three months ended June 30, 2012, compared to $48.9 million in the same three-month period in 2011. This $1.1 million, or 2.2%, decrease was mostly due to a $7.5 million decline attributable to lower volumes sold at existing locations as further discussed above, partially offset by a $6.6 million increase resulting from a higher cash margin per gallon and a $0.2 million increase associated with acquisitions. The increase in the cash margin per gallon was due primarily to our ability to reduce our selling prices to certain customers at a slower rate than the decline in the cost of product. Also contributing to the change was a $0.4 decline in retail gross profit due to changes in non-cash charges on derivative contracts associated with retail propane fixed price sales contracts.

Wholesale propane gross profit was $7.7 million in the three months ended June 30, 2012, compared to $7.5 million in the three months ended June 30, 2011, an increase of $0.2 million, or 2.7%. This increase resulted primarily from increased volumes sold to existing and new customers, which contributed $4.5 million to the increase, partially offset by lower margin obtained, which resulted in a $4.4 million decrease.

Other retail gross profit was $17.6 million for the three months ended June 30, 2012, compared to $15.8 million for the same three-month period in 2011. This $1.8 million, or 11.4%, increase was due primarily to an increase of $4.5 million from acquisition-related gross profit, partially offset by a decline in gross profit from distillate sales and other sales of $0.2 million and $2.5 million, respectively.

Storage, fractionation and other midstream gross profit was $57.0 million in the three months ended June 30, 2012, compared to $44.8 million in the same three-month period in 2011, an increase of $12.2 million, or 27.2%. This change is primarily related to the placement into service of our North/South expansion project and an increase in demand for interruptible wheeling services, which in total contributed $4.9 million to the increase. The acquisition of Seneca Lake in July 2011 resulted in an increase of gross profit of $2.2 million. Partially offsetting this increase was a $1.1 million decrease at our West Coast facility, which can be attributed to lower margins attained through natural gas liquid products sold.

Operating and Administrative Expenses. Operating and administrative expenses were $83.1 million for the three months ended June 30, 2012, compared to $77.4 million in the same three-month period in 2011, an increase of $5.7 million, or 7.4%. This change was primarily due to an increase in operating expenses of $4.5 million due to the operations of acquisitions as well as an increase in transaction expenses of $3.2 million related to the sale of our retail propane operations to SPH and the contribution of our membership interest in US Salt to Inergy Midstream. Partially offsetting these increases was a $2.3 million decrease in vehicle expenses and other operating expenses as well as lower personnel costs from existing operations of $1.0 million.

Depreciation and Amortization. Depreciation and amortization was $38.2 million for the three months ended June 30, 2012, compared to $48.0 million during the same three-month period in 2011. This $9.8 million, or 20.4%, decrease resulted primarily from retail assets no longer being depreciated and amortized for the months of May and June 2012 as they were deemed held for sale, as well as certain assets becoming fully depreciated. Partially offsetting these decreaseses was an increase due to acquisitions and placing midstream assets into service during the three months ended June 30, 2012.

Interest Expense. Interest expense was $22.8 million for the three months ended June 30, 2012, compared to $27.2 million during the same three-month period in 2011. This $4.4 million, or 16.2%, decrease was due primarily to a decrease in the average interest rate incurred, and to a lesser extent, a decrease in outstanding borrowings. Additionally, during the three months ended June 30, 2012 and 2011, we capitalized $4.2 million and $3.3 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 benefit (provision) for income taxes for the three months ended June 30, 2012, was $0.1 million compared to $(0.3) million in the same three-month period in 2011. The benefit for income taxes for the three months ended June 30, 2012, was composed of $0.4 million of deferred income tax benefit, partially offset by $0.3 million of current income tax expense.

Net Loss. Net loss was $17.7 million for the three months ended June 30, 2012, compared to net loss of $35.5 million for the same three-month period in 2011. The $17.8 million, or 50.1%, decrease in net loss was primarily attributable to the higher gross profit and lower depreciation and amortization and interest expense discussed above, partially offset by higher operating and administrative expense in the three months ended June 30, 2012.

Net Income Attributable to Non-Controlling Partners. We recorded an expense of $4.1 million in the three months ended June 30, 2012 associated with the interests of non-controlling partners in subsidiaries. The expense of $4.1 million in the current period solely relates to the 25% minority interest in Inergy Midstream’s net income for the three months ended June 30, 2012. Inergy Midstream’s IPO occurred in December 2011.

EBITDA and Adjusted EBITDA. The following table summarizes EBITDA and Adjusted EBITDA for the three months ended June 30, 2012 and 2011, respectively (in millions):


	Three Months Ended June 30,
	2012			2011
EBITDA:
Net loss	$	(17.7	)	$	(35.5	)
Interest expense, net		22.8			27.2
Early extinguishment of debt		1.7			0.2
Provision (benefit) for income taxes		(0.1	)		0.3
Depreciation and amortization		38.2			48.0

EBITDA	$	44.9		$	40.2

Non-cash loss on derivative contracts		0.5			0.1
Long-term incentive and equity compensation expense		3.6			1.5
Loss on disposal of assets		2.2			0.5
Transaction costs		3.2			0.1

Adjusted EBITDA	$	54.4		$	42.4


	Three Months Ended June 30,
	2012			2011
EBITDA:
Net cash provided by operating activities	$	58.7		$	8.7
Net changes in working capital balances		(28.5	)		9.9
Non-cash early extinguishment of debt		(1.7	)		—
Provision for doubtful accounts		(1.4	)		(2.4	)
Amortization of deferred financing costs, swap premium and net bond discount		(1.2	)		(1.9	)
Long-term incentive and equity compensation expense		(3.6	)		(1.5	)
Loss on disposal of assets		(2.2	)		(0.5	)
Deferred income tax		0.4			0.2
Interest expense, net		22.8			27.2
Early extinguishment of debt		1.7			0.2
Provision (benefit) for income taxes		(0.1	)		0.3

EBITDA	$	44.9		$	40.2

Non-cash loss on derivative contracts		0.5			0.1
Long-term incentive and equity compensation expense		3.6			1.5
Loss on disposal of assets		2.2			0.5
Transaction costs		3.2			0.1

Adjusted EBITDA	$	54.4		$	42.4

EBITDA is defined as income (loss) before income taxes, plus net interest expense, early extinguishment of debt and depreciation and amortization expense. For the three months ended June 30, 2012 and 2011, EBITDA was $44.9 million and $40.2 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 $54.4 million for the three months ended June 30, 2012, compared to $42.4 million in the same three-month period in 2011. EBITDA and Adjusted EBITDA should not be considered an alternative to net income, income before income taxes, cash flows from operating activities, or any other measure of financial performance calculated in accordance with generally accepted accounting principles as those items are used to measure operating performance, liquidity or the ability to service debt obligations. We believe that EBITDA 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, 2012 Compared to Nine Months Ended June 30, 2011

The following table summarizes the consolidated statement of operations components for the nine months ended June 30, 2012 and 2011, respectively (in millions):


	Nine Months Ended June 30,						Change
	2012			2011			In Dollars			Percentage
Revenue	$	1,702.6		$	1,705.2		$	(2.6	)		(0.2	)%
Cost of product sold		1,191.9			1,140.5			51.4			4.5

Gross profit (excluding depreciation and amortization)		510.7			564.7			(54.0	)		(9.6	)
Operating and administrative expenses		247.1			243.6			3.5			1.4
Depreciation and amortization		136.6			141.8			(5.2	)		(3.7	)
Loss on disposal of assets		5.8			3.1			2.7			87.1

Operating income		121.2			176.2			(55.0	)		(31.2	)
Interest expense, net		(73.2	)		(87.5	)		14.3			16.3
Early extinguishment of debt		(26.6	)		(49.6	)		23.0			46.4
Other income		1.5			1.2			0.3			25.0

Income before income taxes		22.9			40.3			(17.4	)		(43.2	)
Provision for income taxes		0.2			0.7			(0.5	)		(71.4	)

Net income		22.7			39.6			(16.9	)		(42.7	)
Net (income) loss attributable to non-controlling partners		(7.8	)		28.2			(36.0	)		(127.7	)

Net income attributable to partners	$	14.9		$	67.8		$	(52.9	)		(78.0	)%

The following table summarizes revenues, including associated volume of gallons sold, for the nine months ended June 30, 2012 and 2011, respectively (in millions):


	Revenues										Gallons
	Nine Months Ended June 30,				Change						Nine Months Ended June 30,				Change
	2012		2011		In Dollars			Percent			2012		2011		In Units			Percent
Propane
Retail propane	$	601.1	$	747.2	$	(146.1	)		(19.6	)%		222.0		282.5		(60.5	)		(21.4	)%
Wholesale propane		531.2		440.7		90.5			20.5			398.6		322.1		76.5			23.8
Other retail		183.6		177.1		6.5			3.7			—		—		—			—
Midstream		386.7		340.2		46.5			13.7			—		—		—			—

Total	$	1,702.6	$	1,705.2	$	(2.6	)		(0.2	)%		620.6		604.6		16.0			2.6	%

Volume. During the nine months ended June 30, 2012, we sold 222.0 million retail gallons of propane, a decrease of 60.5 million gallons or 21.4% from the 282.5 million retail gallons sold during the same nine-month period in 2011. Gallons sold during the nine months ended June 30, 2012, decreased compared to the same prior year period primarily due to lower volumes sold at our existing locations of 61.4 million, partially offset by acquisition-related volume of 0.9 million. During the nine months ended June 30, 2012, we believe that retail propane gallon sales were impacted by several ongoing factors, including, most notably, lower demand arising from above average temperatures, customer conservation, high commodity prices and customers switching to other suppliers or energy sources. The weather during the nine months ended June 30, 2012 was approximately 21% warmer than the prior year period and approximately 20% warmer than normal in our areas of operations. These warmer temperatures had a significant negative impact on retail propane gallons sold during the nine months ended June 30, 2012. Additionally, although the average cost of propane declined approximately 28% during the three months ended June 30, 2012 compared to the preceding six month period ended March 31, 2012, the average wholesale cost of propane during our primary heating season from October to March 2012 increased approximately 2% compared to the same prior year period. We believe these higher costs during our primary heating season, impacted

customers’ buying decisions and conservation trends including customers seeking alternative sources of energy, such as electricity, wood burning and pellet burning stoves, since those sources can be more economical for the customer considering the higher cost of propane.

Wholesale gallons delivered increased 76.5 million gallons, or 23.8%, to 398.6 million gallons in the nine months ended June 30, 2012, from 322.1 million gallons in the nine months ended June 30, 2011. This increase was driven primarily by several factors as follows: 1) gallons arising from certain new contracts with third parties to market and deliver all of the product produced at certain of their production facilities; 2) new gallons arising from an increase in production related to another facility for which we had an existing contract to market and deliver all of the product produced at that facility; and 3) increased gallon sales to new and certain of our existing customers.

The total natural gas liquid gallons sold or processed by our West Coast NGL operations increased 24.1 million gallons, or 9.9%, to 266.8 million gallons during the nine months ended June 30, 2012, from 242.7 million gallons during the same nine-month period in 2011. This increase was primarily attributable to increased volume processed and increased volumes 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, 2012 and 2011, our Northeast natural gas facilities (Stagecoach, Steuben and Thomas Corners) were 95% to 100% contracted on a firm basis, and our Bath NGL storage facility was approximately 100% contracted. Our Tres Palacios storage facility was approximately 54% and 74% contracted on a firm basis during the nine months ended June 30, 2012 and 2011, respectively. Additionally, our Tres Palacios storage facility was approximately 83% contracted including interruptible storage contracts during the nine months ended June 30, 2012 and 2011. Our Seneca Lake storage facility, which was acquired in July 2011, was approximately 63% contracted on a firm basis during the nine months ended June 30, 2012.

Revenues. Revenues for the nine months ended June 30, 2012, were $1,702.6 million, a decrease of $2.6 million, or 0.2%, from $1,705.2 million during the same prior year period.

Revenues from retail propane sales were $601.1 million for the nine months ended June 30, 2012, compared to $747.2 million during the same nine-month period in 2011. This $146.1 million, or 19.6%, decrease was primarily due to a $162.3 million decline arising from lower volumes sold to existing customers as described above, partially offset by a $13.8 million increase due to a higher overall average selling price of propane and a $2.4 million increase resulting from acquisition-related sales. The overall average selling price of propane was higher than the same prior year period due to our ability to pass on to the customer at least a portion of the higher average wholesale cost of propane experienced during the primary heating season as further discussed above.

Revenues from wholesale propane sales were $531.2 million in the nine months ended June 30, 2012, an increase of $90.5 million, or 20.5%, from $440.7 million in the nine months ended June 30, 2011. The increase can be attributed to greater volumes sold to existing and new customers, which contributed $104.6 million to the increase, partially offset by a $14.3 million decline due to a lower average sales price for commodities sold.

Revenues from other retail sales, which primarily includes distillates, service, rental, appliance sales and transportation services, were $183.6 million for the nine months ended June 30, 2012, an increase of $6.5 million, or 3.7%, from $177.1 million during the same nine-month period in 2011. Revenue from other retail sales increased $31.0 million as a result of acquisitions, partially offset by a $17.6 million decrease in distillate revenues and a $6.9 million decline in other revenues. The decline in distillate revenues was driven by a $29.0 million decrease due to lower volumes sold at existing locations, partially offset by an increase of $11.4 million arising from a higher selling price of distillates.

Revenues from storage, fractionation and other midstream activities were $386.7 million for the nine months ended June 30, 2012, an increase of $46.5 million or 13.7% from $340.2 million during the same nine-month period in 2011. Revenues from our West Coast NGL operations increased $15.5 million primarily as a result of higher average selling prices and expected changes in types of natural gas liquids sold. This increase was also a result of increased natural gas liquid products sold as discussed above. In addition, revenues at our Stagecoach facility increased $10.6 million due to the placement into service of our North/South expansion project, and $4.3 million due to demand for interruptible wheeling service as a result of customer demand to move gas to and from our interconnecting pipes primarily due to increasing natural gas development in Pennsylvania. Additionally, the acquisition of the Seneca Lake storage facility in July 2011 increased revenue $6.5 million.

Cost of Product Sold. Cost of product sold for the nine months ended June 30, 2012, was $1,191.9 million, an increase of $51.4 million, or 4.5%, from $1,140.5 million during the same nine-month period in 2011.

Retail propane cost of product sold was $339.0 million for the nine months ended June 30, 2012, a decrease of $62.4 million, or 15.5%, when compared to $401.4 million for the same nine-month period in 2011. This lower retail cost of product sold was driven by an $87.2 million decrease resulting from lower volumes sold at existing locations as discussed above, partially offset by a $23.4 million increase to retail propane cost of goods sold due to a higher average per gallon cost of propane, a $1.3 million increase due to acquisition-related sales, and a $0.1 million increase due to changes in non-cash charges on derivative contracts associated with retail propane fixed price sales contracts.

Wholesale propane cost of product sold in the nine months ended June 30, 2012, was $512.2 million, an increase of $94.5 million, or 22.6%, from wholesale cost of product sold of $417.7 million in the nine months ended June 30, 2011. This increase can be attributed to greater volumes sold to existing and new customers, which contributed $99.1 million to the increase, partially offset by a $4.6 million decrease due to a lower average purchase price.

Other retail cost of product sold was $116.9 million for the nine months ended June 30, 2012, compared to $114.3 million during the same nine-month period in 2011. This $2.6 million, or 2.3%, increase was primarily due to a $19.1 million increase from acquisitions, partially offset by a $13.8 million decline in the cost for distillates and a $2.7 million decrease in the cost of other retail sales. The decrease in the cost of product sold for distillates was driven by a $24.4 million decline due to lower volumes sold at existing locations, partially offset by a $10.6 million increase due to a higher overall commodity cost.

Storage, fractionation and other midstream cost of product sold was $223.8 million for the nine months ended June 30, 2012, an increase of $16.7 million, or 8.1%, from $207.1 million during the same nine-month period in 2011. Costs from our West Coast NGL operations increased $14.8 million primarily as a result of higher average commodity prices of natural gas liquids and expected changes in types of natural gas liquids sold. This increase was also a result of increased natural gas liquid products sold as further discussed above. Stagecoach storage cost decreased $2.6 million comprised primarily of a $2.7 million decrease as a result of insurance reimbursements related to the Stagecoach central compressor loss. Offsetting this decrease at Stagecoach was a $2.3 million increase resulting from storage related costs incurred as a result of placing our North/South expansion project into service in December 2011.

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 $54.2 million and $57.1 million for the nine months ended June 30, 2012 and 2011, respectively. In addition, the depreciation expense associated with the delivery vehicles and customer tanks is reported within depreciation and amortization expense and amounted to $16.5 million and $22.1 million for the nine months ended June 30, 2012 and 2011, 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 services amounted to $82.3 million and $74.6 million for the nine months ended June 30, 2012 and 2011, respectively. Vehicle costs and wages for personnel directly involved in providing midstream services amounted to $4.2 million and $3.4 million for the nine months ended June 30, 2012 and 2011, 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 (Excluding Depreciation and Amortization). Gross profit for the nine months ended June 30, 2012, was $510.7 million, a decrease of $54.0 million, or 9.6%, from $564.7 million during the same nine-month period in 2011.

Retail propane gross profit was $262.1 million for the nine months ended June 30, 2012, compared to $345.8 million in the same nine-month period in 2011. This $83.7 million, or 24.2%, decrease was mostly due to a $75.1 million decline attributable to lower volumes sold at existing locations as further discussed above, coupled with a $9.6 million decline resulting from a lower cash margin per gallon. The decline in cash margin per gallon was due primarily to a decline in our sales to residential customers, which are higher margin customers that are highly sensitive to weather conditions and our inability to fully pass on to the customer in the form of higher selling price the higher cost of propane in the current period due to customer resistance to any increases. Also contributing was a $0.1 million decline due to changes in non-cash charges on derivative contracts associated with retail propane fixed price sales contracts. These factors were partially offset by an increase in retail gross profit of $1.1 million associated with acquisitions.

Wholesale propane gross profit was $19.0 million in the nine months ended June 30, 2012, compared to $23.0 million in the nine months ended June 30, 2011, a decrease of $4.0 million, or 17.4%. This decrease resulted from lower margins, which contributed $9.7 million to the decrease, partially offset by a $5.5 million increase in volumes sold to existing and new customers.

Other retail gross profit was $66.7 million for the nine months ended June 30, 2012, compared to $62.8 million for the same nine-month period in 2011. This $3.9 million, or 6.2%, increase was due primarily to an increase of $11.9 million arising from acquisition-related gross profit, partially offset by a decline in gross profit from distillate sales and other sales of $3.8 million and $4.2 million, respectively.

Storage, fractionation and other midstream gross profit was $162.9 million in the nine months ended June 30, 2012, compared to $133.1 million in the same nine-month period in 2011, an increase of $29.8 million, or 22.4%. This change is primarily related to the placement into service of our North/South expansion project and an increase in demand for interruptible wheeling services, which in total contributed $12.6 million to the increase. The acquisition of Seneca Lake in July 2011 resulted in an increase of gross profit of $6.3 million. An additional $0.7 million of this increase was attributable to increased margins attained through natural gas liquid products sold at our West Coast facility.

Operating and Administrative Expenses. Operating and administrative expenses were $247.1 million for the nine months ended June 30, 2012, compared to $243.6 million in the same nine-month period in 2011, an increase of $3.5 million, or 1.4%. This change was primarily due to an increase in operating expenses of $11.7 million due to the operations of acquisitions. Partially offsetting this increase was a $4.7 million decrease in transaction expenses related to acquisitions in the prior fiscal year, and lower personnel costs from existing operations of $3.5 million.

Depreciation and Amortization. Depreciation and amortization was $136.6 million for the nine months ended June 30, 2012, compared to $141.8 million during the same nine-month period in 2011. This $5.2 million, or 3.7%, decrease resulted primarily from retail assets no longer being depreciated and amortized for the months of May and June 2012 as they were deemed held for sale, as well as certain assets becoming fully depreciated. Partially offsetting these decreases was an increase due to acquisitions and placing midstream assets into service during the nine months ended June 30, 2012.

Interest Expense. Interest expense was $73.2 million for the nine months ended June 30, 2012, compared to $87.5 million during the same nine-month period in 2011. This $14.3 million, or 16.3%, decrease was due primarily to a decrease in the average interest rate incurred, partially offset by a slight increase in average outstanding borrowings. Additionally, during the nine months ended June 30, 2012 and 2011, we capitalized $11.8 million and $11.4 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 months ended June 30, 2012, we paid in full the $300 million balance outstanding on our term loan facility, tendered for substantially all the $95 million outstanding on our 2015 senior notes, tendered for $150 million of the $750 million outstanding on our 2021 senior notes, and reduced the Inergy revolving credit facility by $150 million. The loss associated with the above described transactions amounted to $26.6 million and was primarily related to the tender premiums and the write-off of previously capitalized charges associated with the original issuance of the respective 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, 2012, was $0.2 million compared to $0.7 million in the same nine-month period in 2011. The provision for income taxes for the nine months ended June 30, 2012, was composed of $0.7 million of current income tax expense, partially offset by $0.5 million of deferred income tax benefit.

Net Income. Net income was $22.7 million for the nine months ended June 30, 2012, compared to net income of $39.6 million for the same nine-month period in 2011. The $16.9 million, or 42.7%, decrease in net income was primarily attributable to the lower gross profit and higher operating and administrative expenses discussed above for the nine months ended June 30, 2012, partially offset by the $23.0 million decrease in charges related to the early extinguishment of debt, and the $14.3 million decrease in interest expense for the nine months ended June 30, 2012.

Net (Income) Loss Attributable to Non-Controlling Partners. The non-controlling interest in the prior period was related entirely to earnings of non-controlling partners prior to the November 2010 merger. The merger eliminated this group of non-controlling partners. The current period earnings of non-controlling partners relate solely to the Inergy Midstream IPO in December 2011.

EBITDA and Adjusted EBITDA. The following table summarizes EBITDA and Adjusted EBITDA for the nine months ended June 30, 2012 and 2011, respectively (in millions):


	Nine Months Ended June 30,
	2012			2011
EBITDA:
Net income	$	22.7		$	39.6
Interest expense, net		73.2			87.5
Early extinguishment of debt		26.6			49.6
Provision for income taxes		0.2			0.7
Depreciation and amortization		136.6			141.8

EBITDA	$	259.3		$	319.2

Non-cash gain on derivative contracts		(0.1	)		(0.2	)
Long-term incentive and equity compensation expense		9.8			4.4
Loss on disposal of assets		5.8			3.1
Transaction costs		4.3			9.0

Adjusted EBITDA	$	279.1		$	335.5


	Nine Months Ended June 30,
	2012			2011
EBITDA:
Net cash provided by operating activities	$	253.2		$	130.5
Net changes in working capital balances		(63.1	)		77.7
Non-cash early extinguishment of debt		(10.0	)		(11.2	)
Provision for doubtful accounts		(1.8	)		(2.6	)
Amortization of deferred financing costs, swap premium and net bond discount		(3.9	)		(5.7	)
Long-term incentive and equity compensation expense		(9.8	)		(4.4	)
Loss on disposal of assets		(5.8	)		(3.1	)
Deferred income tax		0.5			0.2
Interest expense, net		73.2			87.5
Early extinguishment of debt		26.6			49.6
Provision for income taxes		0.2			0.7

EBITDA	$	259.3		$	319.2

Non-cash gain on derivative contracts		(0.1	)		(0.2	)
Long-term incentive and equity compensation expense		9.8			4.4
Loss on disposal of assets		5.8			3.1
Transaction costs		4.3			9.0

Adjusted EBITDA	$	279.1		$	335.5

EBITDA is defined as income (loss) before income taxes, plus net interest expense, early extinguishment of debt and depreciation and amortization expense. For the nine months ended June 30, 2012 and 2011, EBITDA was $259.3 million and $319.2 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 $279.1 million for the nine months ended June 30, 2012, compared to $335.5 million in the same nine-month period in 2011. EBITDA and Adjusted EBITDA should not be considered an alternative to net income, income before income taxes, cash flows from operating activities, or any other measure of financial performance calculated in accordance with generally accepted accounting principles as those items are used to measure operating performance, liquidity or the ability to service debt obligations. We believe that EBITDA 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 $253.2 million and $130.5 million for the nine-month periods ending June 30, 2012 and 2011, respectively. The $122.7 million increase in operating cash flows was primarily attributable to an approximate $60.0 million increase in cash collections on inventory sales associated with certain new contracts entered into during the spring of 2011. Also contributing to the increase in operating cash flows was a decrease of $21.8 million in cash cost of early extinguishment of debt, as well as a $14.5 million decrease in cash interest expense.

Net investing cash outflows were $184.8 million and $275.4 million for the nine-month periods ending June 30, 2012 and 2011, respectively. Net cash outflows were primarily impacted by a $734.0 million decrease in cash outlays related to acquisitions, partially offset by a $588.0 million investment in escrow account that was utilized in fiscal 2011 to fund the Tres Palacios acquisition, a $12.9 million decrease in proceeds from the sale of assets, and a $42.5 million increase in capital expenditures. The increase in capital expenditures is primarily related to the previously discussed midstream expansion projects.

Net financing cash inflows (outflows) were $(75.0) million and $159.1 million for the nine-month periods ending June 30, 2012 and 2011, respectively. The net change was primarily impacted by a $221.1 million decrease in net borrowings.

We believe that anticipated cash from operations and borrowing capacity under our credit facilities described below will be sufficient to meet our liquidity needs for the foreseeable future subject to compliance with any applicable covenants under such facility. 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, 2012, we have firm purchase commitments totaling approximately $50.8 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 Facilities

Inergy, L.P.

On November 24, 2009, we entered into a secured credit facility (“Credit Agreement”) which at the time provided 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 was to 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 was repaid in full in December 2011 as discussed below. The term loan was to mature on February 2, 2015, and did 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 1.00% 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%.

On July 28, 2011, we further amended our amended and restated Credit Agreement to (i) raise the aggregate revolving commitment from $525 million to $700 million (“Revolving Loan Facility”) with that amount existing as a singular tranche, (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.

On April 13, 2012, we further amended our amended and restated Credit Agreement. This amendment, among other things, (i) permits us to sell up to 5,000,000 Inergy Midstream common units, (ii) permits us to sell all of the assets or capital stock of US Salt pursuant to which US Salt will be released as a subsidiary guarantor under the Credit Agreement, (iii) decreases the aggregate revolving commitment and general partnership commitment from $700 million to $550 million, and (iv) adjusts several of the financial covenants.

On July 26, 2012, we further amended our amended and restated Credit Agreement in order to: (i) permit us to enter into a series of transactions as described in the Contribution Agreement dated as of April 25, 2012 among us and Suburban Propane Partners, L.P, (ii) permit us to repurchase, repay or redeem all or any portion of the senior notes that remain outstanding after the closing of the Contribution Agreement, (iii) modify certain negative and financial covenants under the Credit Agreement, and (iv) allow us to redeem, buy back or otherwise acquire up to $100,000,000 of our common units on or prior to March 31, 2013. This amendment did not become effective until the contribution of Inergy’s retail

propane assets to SPH closed on August 1, 2012. In conjunction with the close of this transaction, $1,187.0 million in Inergy senior notes were exchanged for SPH senior notes, thereby eliminating the senior notes from Inergy’s consolidated balance sheet on August 1, 2012.

The Credit Agreement contains various covenants and restrictive provisions that limit our ability to, among other things:

•

incur additional debt;

•

make distributions on or redeem or repurchase units;

•

make certain investments and acquisitions;

•

incur or permit certain liens to exist;

•

enter into certain types of transactions with affiliates;

•

merge, consolidate or amalgamate with another company; and

•

transfer or otherwise dispose of assets.

The Credit Agreement (as of June 30, 2012) contains the following financial covenants:

•

the ratio of our total funded debt (as defined in the Credit Agreement) to consolidated EBITDA (as defined in the Credit Agreement) for the four fiscal quarters most recently ended must be no greater than 5.75 to 1.0;

•

the ratio of our senior secured funded debt (as defined in the Credit Agreement) to consolidated EBITDA (as defined in the Credit Agreement) for the four fiscal quarters most recently ended must be no greater than 2.75 to 1.0; and

•

the ratio of our consolidated EBITDA to consolidated interest expense (as defined in the Credit Agreement), for the four fiscal quarters then most recently ended, must not be less than 2.25 to 1.0.

At June 30, 2012, our ratio of total funded debt to consolidated EBITDA was 4.88 to 1.0; our ratio of senior secured funded debt to consolidated EBITDA was 0.60 to 1.0; and our ratio of consolidated EBITDA to consolidated interest expense was 3.22 to 1.0.

If we should fail to perform our obligations under these and other covenants, the Revolving Loan Facility could be terminated and any outstanding borrowings, together with accrued interest, under the Credit Agreement could be declared immediately due and payable. The Credit Agreement also has cross default provisions that apply to any other material indebtedness of ours.

All borrowings under the Credit Agreement are generally secured by all of our assets and the equity interests in all of our wholly owned subsidiaries, and loans thereunder bear interest, at our option, subject to certain limitations, at a rate equal to the following:

•

the Adjusted LIBO Rate, which is defined as the LIBO Rate plus a margin varying from 1.75% to 3.00%.

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.

In conjunction with the Inergy Midstream IPO on December 21, 2011, Inergy entered into the following transactions:

•

Paid in full the $300 million balance outstanding on the Term Loan Facility.

•

Tendered for substantially all the $95 million outstanding on the 2015 Senior Notes.

•

Tendered for $150 million of the $750 million outstanding on the 2021 Senior Notes.

•

Inergy Midstream, L.P.

On December 21, 2011, Inergy Midstream entered into a new $500 million, five-year revolving credit facility (“NRGM Credit Facility”). The NRGM Credit Facility is available to fund acquisitions, working capital and internal growth projects and for general partnership purposes. The NRGM Credit Facility has an accordion feature that allows Inergy Midstream to increase the available borrowings under the facility by up to $250 million, subject to the lenders’ agreement and the satisfaction of certain conditions. In addition, the NRGM Credit Facility includes a sub-limit up to $10 million for same-day swing line advances and a sub-limit up to $100 million for letters of credit.

On April 16, 2012, Inergy Midstream exercised a portion of the accordion feature under the NRGM Credit Facility and increased the loan commitments thereunder by $100 million. The aggregate amount of revolving loan commitments under the NRGM Credit Facility is now $600 million.

Inergy and its wholly owned subsidiaries do not provide credit support or guarantee any amounts outstanding under the NRGM Credit Facility.

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

Interest Rate Risk

We have a revolving line of credit subject to the risk of loss associated with movements in interest rates. At June 30, 2012, we did not have any floating rate obligations borrowed under our revolving line of credit (net of certain interest rate swaps, which convert our revolving line of credit to a fixed rate). Inergy Midstream also has a revolving credit facility subject to the risk of loss associated with movements in interest rates. At June 30, 2012, Inergy Midstream had floating rate obligations totaling $324.2 million. Floating rate obligations expose us and Inergy Midstream to the risk of increased interest expense in the event of increases in short-term interest rates.

If the floating rate were to fluctuate by 100 basis points from June 2012 levels, our interest expenditures would change by a total of approximately $3.2 million per year.

Commodity Price, Market and Credit Risk

Inherent in our contractual portfolio are certain business risks, including market risk and credit risk. Market risk is the risk that the value of the portfolio will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by suppliers, customers or financial counterparties to a contract. We take an active role in managing and controlling market and credit risk and have established control procedures, which are reviewed on an ongoing basis. We monitor market risk through a variety of techniques, including daily reporting of the portfolio’s position to senior management. 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, 2012 and 2011, 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, 2012 and September 30, 2011, was assets of $40.6 million and $17.1 million, respectively, and liabilities of $13.5 million and $19.0 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 million change in the market value of the contracts as there were 1.1 million gallons of net unbalanced positions at June 30, 2012.

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, 2012, 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, 2012, that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

Changes in Internal Control over Financial Reporting

In fiscal 2012, we completed the acquisitions of Papco, Woodstock and Aztec. 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.

PART II – OTHER INFORMATION

Item 1.

Legal Proceedings

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

Item 1A.

Risk Factors

The Company has identified an additional risk factor, as discussed below, in addition to those disclosed in “Item 1A, Risk Factors” in the Company’s Annual Report on Form 10-K for the fiscal year ended September 31, 2011.

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

None.

Item 3.

Defaults Upon Senior Securities

None.

Item 4.

Mine Safety Disclosures

Not applicable.

Item 5.

Other Information

None.

Item 6.

Exhibits


2.1		Contribution Agreement, dated as of April 26, 2012, by and among Inergy, L.P., Inergy GP, LLC, Inergy Sales & Service, Inc. and Suburban Propane Partners, L.P. (incorporated by reference to Exhibit 2.1 to Inergy, L.P.’s Form 8-K filed on April 26, 2012).

2.1A		Amendment to Contribution Agreement dated June 15, 2012 by and among Inergy, L.P., Inergy GP, LLC, Inergy Sales & Service, Inc. and Suburban Propane Partners, L.P. (incorporated by reference to Exhibit 2.1 to Inergy, L.P.’s Form 8-K filed on June 15, 2012).

2.1B		Second Amendment to Contribution Agreement dated July 6, 2012 by and among Inergy, L.P., Inergy GP, LLC, Inergy Sales & Service, Inc. and Suburban Propane Partners, L.P. (incorporated by reference to Exhibit 2.1 to Inergy, L.P.’s Form 8-K filed on July 6, 2012).

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

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

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


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

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

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

3.2D		Third Amended and Restated Agreement of Limited Partnership of Inergy, L.P., dated as of November 5, 2010 (incorporated herein by reference to Exhibit 3.1 to Inergy, L.P.’s Form 8-K filed on November 5, 2010).

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).

3.9		Certificate of Limited Partnership of Inergy Midstream, L.P. dated November 14, 2011 (incorporated herein by reference to Exhibit 3.4 to Inergy Midstream, L.P.’s Amendment No. 3 to Form S-1 (File No. 333-176445) filed on November 21, 2011).

3.10		First Amended and Restated Agreement of Limited Partnership of Inergy Midstream, L.P. dated December 21, 2011 (incorporated herein by reference to Exhibit 4.2 to Inergy Midstream, L.P.’s Form S-8 (File No. 333-178659) filed on December 21, 2011).

*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

Pursuant to Rule 406T of Regulation S-T, the Interactive Data Files on Exhibit 101 hereto are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, are deemed not filed for purposes of Section 18 of the Securities and Exchange Act of 1934, as amended, and otherwise are not subject to liability under those sections.

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 general partner)

Date: August 2, 2012	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)