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, 2009

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

For the transition period from to .

COMMISSION FILE NUMBER: 0-32453

Inergy, L.P.

(Exact name of registrant as specified in its charter)

Delaware

43-1918951

(State or other jurisdiction of

incorporation or organization)

(IRS Employer

Identification No.)


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

(816) 842-8181

(Registrant’s telephone number, including area code)

(Former name, former address and former fiscal year,

if changed since last report)

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, 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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, 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 ¨ No ¨

The following units were outstanding at July 31, 2009:

Common units 55,769,587

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, 2009 (unaudited) and September 30, 2008		3
Unaudited Consolidated Statements of Operations for the Three and Nine Months Ended June 30, 2009 and 2008		4
Unaudited Consolidated Statement of Partners’ Capital for the Nine Months Ended June 30, 2009		5
Unaudited Consolidated Statements of Cash Flows for the Nine Months Ended June 30, 2009 and 2008		6
Unaudited Notes to Consolidated Financial Statements		8

Item 2 – Management’s Discussion and Analysis of Financial Condition and Results of Operations		26

Item 3 – Quantitative and Qualitative Disclosures About Market Risk		40

Item 4 – Controls and Procedures		41

Part II – Other Information

Item 1 – Legal Proceedings		42

Item 1A – Risk Factors		42

Item 2 – Unregistered Sales of Equity Securities and Use of Proceeds		42

Item 3 – Defaults Upon Senior Securities		42

Item 4 – Submission of Matters to a Vote of Security Holders		42

Item 5 – Other Information		42

Item 6 – Exhibits		43

Signature		44

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, 2009		September 30, 2008
	*(unaudited)*
Assets
Current assets:
Cash	$	13.0	$	17.3
Accounts receivable, less allowance for doubtful accounts of $5.4 million and $6.4 million at June 30, 2009 and September 30, 2008, respectively		84.3		128.5
Inventories (Note 3)		78.6		99.9
Assets from price risk management activities		26.5		33.3
Prepaid expenses and other current assets		19.0		21.9

Total current assets		221.4		300.9

Property, plant and equipment (Note 3)		1,443.2		1,275.0
Less: accumulated depreciation		301.4		244.7

Property, plant and equipment, net		1,141.8		1,030.3

Intangible assets (Note 3):
Customer accounts		268.5		266.7
Other intangible assets		132.8		127.0

		401.3		393.7
Less: accumulated amortization		125.1		105.5

Intangible assets, net		276.2		288.2

Goodwill		448.7		443.0
Other assets		7.1		4.0

Total assets	$	2,095.2	$	2,066.4


Liabilities and partners’ capital
Current liabilities:
Accounts payable	$	76.9	$	103.8
Accrued expenses		72.8		68.9
Customer deposits		40.0		87.7
Liabilities from price risk management activities		22.8		57.0
Current portion of long-term debt (Note 7)		22.9		60.5

Total current liabilities		235.4		377.9

Long-term debt, less current portion (Note 7)		1,087.7		1,046.1
Other long-term liabilities		0.9		1.0
Interest of non-controlling partners in ASC’s subsidiaries		4.0		3.6

Partners’ capital (Note 8):
Common unitholders (55,759,587 and 50,715,074 units issued and outstanding as of June 30, 2009 and September 30, 2008, respectively)		767.1		637.6
Non-managing general partner and affiliate		0.1		0.2

Total partners’ capital		767.2		637.8


Total liabilities and partners’ capital	$	2,095.2	$	2,066.4

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,
	2009			2008			2009			2008
Revenue:
Propane	$	135.5		$	220.9		$	988.6		$	1,149.6
Other		99.5			154.3			350.5			388.4

		235.0			375.2			1,339.1			1,538.0
Cost of product sold (excluding depreciation and amortization as shown below):
Propane		81.3			173.1			648.1			862.0
Other		56.4			113.4			207.3			261.5

		137.7			286.5			855.4			1,123.5

Gross profit		97.3			88.7			483.7			414.5
Expenses:
Operating and administrative		66.4			67.1			212.6			198.6
Depreciation and amortization		26.4			26.1			79.3			72.1
Gain (loss) on disposal of assets		(1.1	)		(0.4	)		(4.1	)		0.8

Operating income (loss)		3.4			(4.9	)		187.7			144.6

Other income (expense):
Interest expense, net		(17.2	)		(15.2	)		(52.1	)		(45.0	)
Other income		—			—			—			0.1

Income (loss) before income taxes and interest of non-controlling partners in ASC		(13.8	)		(20.1	)		135.6			99.7

Provision for income taxes		(0.2	)		(0.2	)		(0.4	)		(0.6	)
Interest of non-controlling partners in ASC’s consolidated net income		(0.3	)		(0.4	)		(1.0	)		(0.9	)

Net income (loss)	$	(14.3	)	$	(20.7	)	$	134.2		$	98.2


Partners’ interest information:
Non-managing general partner and affiliates interest in net income	$	12.0		$	8.9		$	34.5		$	26.9
Distribution paid on restricted units		0.3			0.1			0.6			0.2

Total interest in net income not attributable to limited partners’	$	12.3		$	9.0		$	35.1		$	27.1


Total limited partners’ interest in net income (loss)	$	(26.6	)	$	(29.7	)	$	99.1		$	71.1


Net income (loss) per limited partner unit:
Basic	$	(0.48	)	$	(0.60	)	$	1.89		$	1.43

Diluted	$	(0.48	)	$	(0.60	)	$	1.89		$	1.43


Weighted average limited partners’ units outstanding (in thousands):
Basic		55,311			49,711			52,427			49,687
Dilutive units		—			—			25			85

Diluted		55,311			49,711			52,452			49,772

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-Managing General Partner and Affiliate			Total Partners’ Capital
Balance at September 30, 2008	$	637.6		$	0.2		$	637.8
Net proceeds from issuance of common units		94.3			—			94.3
Net proceeds from common unit options exercised		0.8			—			0.8
Issuance of common units for acquisition		6.7			—			6.7
Unit based compensation charges		2.2			—			2.2
Retirement of common units		(0.8	)		—			(0.8	)
Distributions		(102.0	)		(34.8	)		(136.8	)
Comprehensive income:
Net income		99.7			34.5			134.2
Change in unrealized fair value on cash flow hedges		28.6			0.2			28.8

Comprehensive income								163.0

Balance at June 30, 2009	$	767.1		$	0.1		$	767.2

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,
	2009			2008
Operating activities
Net income	$	134.2		$	98.2
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation		59.4			54.4
Amortization		19.9			17.7
Amortization of deferred financing costs		2.4			1.8
Amortization of net bond discount		1.1			—
Unit-based compensation charges		2.2			1.2
Interest of non-controlling partners in ASC’s consolidated net income		1.0			0.9
Provision for doubtful accounts		3.2			5.0
(Gain) loss on disposal of assets		4.1			(0.8	)
Changes in operating assets and liabilities, net of effects from acquisitions:
Accounts receivable		41.4			(9.5	)
Inventories		21.4			14.1
Prepaid expenses and other current assets		2.7			3.9
Other liabilities		(0.1	)		(0.3	)
Accounts payable		(32.3	)		1.4
Accrued expenses		(5.0	)		(2.8	)
Customer deposits		(47.7	)		(32.5	)
Net liabilities from price risk management activities		1.3			(1.7	)

Net cash provided by operating activities		209.2			151.0

Investing activities
Acquisitions, net of cash acquired		(12.4	)		(101.7	)
Purchases of property, plant and equipment		(153.7	)		(147.9	)
Proceeds from sale of assets		5.4			27.3
Other		(0.4	)		(0.3	)

Net cash used in investing activities		(161.1	)		(222.6	)

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,
	2009			2008
Financing activities
Proceeds from the issuance of long-term debt	$	717.1		$	738.9
Premium on issuance of long-term debt		—			4.0
Principal payments on long-term debt		(721.7	)		(547.2	)
Distributions		(136.8	)		(117.7	)
Payments for deferred financing costs		(5.4	)		(3.5	)
Net proceeds from unit options exercised		0.8			0.9
Net proceeds from issuance of common units		94.3			—
Distributions to minority interests		(0.7	)		(0.8	)

Net cash provided by (used in) financing activities		(52.4	)		74.6

Net increase (decrease) in cash		(4.3	)		3.0
Cash at beginning of period		17.3			7.7


Cash at end of period	$	13.0		$	10.7


Supplemental schedule of noncash investing and financing activities
Additions to intangible assets through the issuance of noncompetition agreements and notes to former owners of businesses acquired	$	4.2		$	2.3


Net change to property, plant and equipment through accounts payable and accrued expenses	$	12.4		$	0.2


Increase in the fair value of interest rate swap liability and related long-term debt	$	3.3		$	3.0


Acquisitions, net of cash acquired:
Current assets	$	0.3		$	11.3
Property, plant and equipment		14.3			70.4
Intangible assets, net		(0.1	)		20.2
Goodwill		5.7			16.6
Other assets		—			0.5
Current liabilities		(1.1	)		(1.0	)
Issuance of equity		(6.7	)		—
Other liabilities		—			(16.3	)

	$	12.4		$	101.7

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

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

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

Pursuant to a partnership agreement, Inergy GP or any of its affiliates is entitled to reimbursement for all direct and indirect expenses incurred or payments it makes on behalf of Inergy and all other necessary or appropriate expenses allocable to Inergy or otherwise reasonably incurred by Inergy GP in connection with operating the Company’s business. These costs, which totaled approximately $0.6 million and $0.5 million for the three months ended June 30, 2009 and 2008, and $2.5 million and $3.1 million for the nine months ended June 30, 2009 and 2008, respectively, include compensation, bonuses and benefits paid to officers and employees of Inergy GP and its affiliates.

As of June 30, 2009, Holdings owns an aggregate 9.2% interest in Inergy, L.P., inclusive of ownership of all of the non-managing general partner and the managing general partner. This ownership is comprised of an approximate 0.8% general partnership interest and an approximate 8.4% limited partnership interest.

Nature of Operations

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

Basis of Presentation

The financial information contained herein as of June 30, 2009 and for the three-month and nine-month periods ended June 30, 2009 and 2008 is unaudited. The Company believes this information has been prepared in accordance with accounting principles generally accepted in the United States for interim financial information and Article 10 of Regulation S-X. The Company also believes this information includes all adjustments (consisting only of normal recurring adjustments) necessary to present fairly the financial position, results of operations and cash flows for the periods then ended. The retail distribution business is largely seasonal due to propane’s primary use as a heating source in residential and commercial buildings. Accordingly, the results of operations for the three-month and nine-month periods ended June 30, 2009 are not indicative of the results of operations that may be expected for the entire fiscal year.

The accompanying consolidated financial statements should be read in conjunction with the consolidated financial statements of Inergy, L.P. and subsidiaries and the notes thereto included in Form 10-K as filed with the Securities and Exchange Commission for the fiscal year ended September 30, 2008.

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Reclassifications

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

Note 2 – Summary of Significant Accounting Policies

Financial Instruments and Price Risk Management

Inergy utilizes certain derivative financial instruments to (i) manage its exposure to commodity price risk, specifically, the related change in the fair value of inventories, as well as the variability of cash flows related to forecasted transactions; (ii) ensure adequate physical supply of commodity will be available; and (iii) manage its exposure to interest rate risk associated with fixed rate borrowings. Inergy records all derivative instruments on the balance sheet as either assets or liabilities measured at fair value under the provisions of Statement of Financial Accounting Standards 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”), as amended. Changes in the fair value of these derivative financial instruments are recorded either through current earnings or as other comprehensive income, depending on the type of transaction.

Inergy is party to certain commodity derivative financial instruments that are designated as hedges of selected inventory positions, and qualify as fair value hedges, as defined in SFAS 133. Inergy is also party to certain interest rate swap agreements designed to manage interest rate risk exposure. Inergy’s overall objective for entering into fair value hedges is to manage its exposure to fluctuations in commodity prices and changes in the fair market value of its inventories and fixed rate borrowings. These derivatives are recorded at fair value on the balance sheets as price risk management assets or liabilities and the related change in fair value is recorded to earnings in the current period as cost of product sold.

Inergy also enters into derivative financial instruments that qualify as cash flow hedges, which hedge the exposure of variability in expected future cash flows predominantly attributable to forecasted purchases to supply fixed price sale contracts. These derivatives are recorded on the balance sheet at fair value as price risk management assets or liabilities. The effective portion of the gain or loss on these cash flow hedges is recorded in other comprehensive income in partner’s capital and reclassified into earnings as a component of cost of product sold in the same period in which the hedged transaction affects earnings. Any ineffective portion of the gain or loss is recognized as cost of product sold in the current period. Accumulated other comprehensive income (loss) was $3.5 million and $(25.3) million at June 30, 2009 and September 30, 2008, respectively. Approximately $4.2 million is expected to be reclassified to earnings from other comprehensive income over the next twelve months.

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. Operating and administrative expenses consist of all expenses incurred by Inergy other than those described above in cost

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

of product sold and depreciation and amortization. Certain of Inergy’s operating and administrative expenses and depreciation and amortization are incurred in the distribution of product and storage sales but are not included in cost of product sold. These amounts were $31.5 million and $32.8 million for the three months ended June 30, 2009 and 2008, respectively, and $98.7 million and $99.2 million for the nine months ended June 30, 2009 and 2008, respectively.

Use of Estimates

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

Inventories

Inventories for retail operations, which mainly consist of propane gas and other liquids, are stated at the lower of cost or market and are computed using the average-cost method. Wholesale propane and other liquids inventories are designated under a fair value hedge program and are consequently marked to market. All wholesale propane and other liquids inventories being hedged and carried at market value at June 30, 2009 and September 30, 2008 amount to $35.7 million and $36.4 million, respectively. Inventories for midstream operations are stated at the lower of cost or market and are computed predominantly using the average cost method.

Shipping and Handling Costs

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

Property, Plant and Equipment

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


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

Identifiable Intangible Assets

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

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

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


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

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

Goodwill

Goodwill is recognized pursuant to Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets,” (“SFAS 142”) for various acquisitions by Inergy as the excess of the cost of the acquisitions over the fair value of the related net assets at the date of acquisition. Under SFAS 142, 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 in a manner similar to a purchase price allocation in accordance with Statement of Financial Accounting Standards No. 141, “Business Combinations,” (“SFAS 141”) 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, 2008. No indicators of impairment were identified requiring an interim impairment test during the nine-month period ended June 30, 2009.

Income Taxes

Inergy is a publicly-traded master limited partnership. Partnerships are generally not subject to Federal income tax, although publicly-traded partnerships are treated as corporations for Federal income tax purposes and therefore are subject to federal income tax, unless the partnership generates at least 90% of its gross income from qualifying sources. If the qualifying income requirement is satisfied, the publicly-traded partnership will be treated as a partnership for Federal income tax purposes. Inergy Sales and Service, Inc. (“Services”), a subsidiary of Inergy, does not generate at least 90% of its gross income from qualifying sources, and as such, federal and state income taxes are provided on the taxable income of Services. The remaining Inergy subsidiaries generate at least 90% of gross income from qualifying sources. As a result, except for the operations of Services, Inergy’s net earnings for Federal income tax purposes are allocated to the individual partners for inclusion in their income tax returns. Legislation in certain states allows for taxation of partnerships. As such, certain state taxes for Inergy have also been included in the accompanying financial statements as income taxes due to the nature of the tax in those particular states. 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.

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Income Per Unit

The Company calculates basic net income per unit by dividing net income, after considering the Non-Managing General Partner’s interest, including priority distributions, by the weighted average number of limited partner units outstanding. Under this method, the calculation of net income per unit reflects an allocation of earnings to each class of units that is consistent with the partnership agreement’s treatment of the respective classes’ capital accounts. Diluted net income per limited partner unit is computed by dividing net income, after considering the Non-Managing General Partner’s interest, by the sum of weighted average number of common units and the effect of other dilutive units.

As the effect of including incremental units associated with options were antidilutive for the three months ended June 30, 2009 and 2008 due to the net loss reported for those periods, no unit options or other dilutive units were reflected in the applicable dilutive earnings per unit computations. As a result, both basic earnings per unit and diluted earnings per unit reflect the same calculation for the three-month periods ended June 30, 2009 and 2008, respectively. Weighted average antidilutive unit options outstanding totaled 33,139 and 63,400 for the three months ended June 30, 2009 and 2008, respectively.

Accounting for Unit-Based Compensation

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

The amount of compensation expense recorded by the Company under the provisions of SFAS 123(R) during the nine months ended June 30, 2009 and 2008 was approximately $2.2 million and $1.2 million, respectively. The compensation expense includes unit-based compensation expense for options and restricted shares on Inergy Holdings, L.P. units granted to the Company’s employees.

Segment Information

SFAS No. 131, “Disclosures about Segments of an Enterprise and Related Information” (“SFAS 131”) establishes standards for reporting information about operating segments, as well as related disclosures about products and services, geographic areas, and major customers. Further, SFAS 131 defines operating segments as components of an enterprise for which separate financial information is available that is evaluated regularly by the chief operating decision maker in deciding how to allocate resources and assessing performance. In determining reportable segments under the provisions of SFAS 131, Inergy examined the way it organizes its business internally for making operating decisions and assessing business performance. See Note 10 for disclosures related to Inergy’s propane and midstream segments.

Fair Value

Cash and cash equivalents, accounts receivable (net of reserve for bad debts) and payables are carried at cost, which approximates fair value due to their liquid and short-term nature. As of June 30, 2009, the estimated fair value of the fixed-rate Senior Notes, based on available trading information, totaled $1,001.5 million compared with the aggregate principal amount at maturity of $1,050.0 million. The Company’s credit agreement (“Credit Agreement”) consists of a $75 million revolving working capital facility (“Working Capital Facility”) and a $350 million revolving acquisition facility (“Acquisition Facility”). The carrying value at June 30, 2009 of amounts outstanding under the Credit Agreement of $43.5 million approximate fair value due primarily to the floating interest rate associated with the Credit Agreement.

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Recently Issued Accounting Pronouncements

SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS 159”) was issued in February 2007 to permit entities to choose to measure many financial instruments and certain other items at fair value at specified election dates. A business entity is required to report unrealized gains and losses on items for which the fair value option has been elected in earnings at each subsequent reporting date. The Company adopted SFAS 159 on October 1, 2008. The adoption of SFAS 159 did not have an impact on the Company’s financial statements.

SFAS No. 157, “Fair Value Measurements” (“SFAS 157”) was issued in September 2006 to define fair value, establish a framework for measuring fair value according to generally accepted accounting principles, and expand disclosures about fair value measurements. The Company adopted SFAS 157 on October 1, 2008. The adoption of SFAS 157 required certain additional footnote disclosures (Note 6), however, it did not have a significant impact on any amounts comprising the Balance Sheet, Statement of Operations, Statement of Partners’ Capital, or the Statement of Cash Flows.

In April 2007, the FASB issued FASB Staff Position No. FIN 39-1, “Amendment of FASB Interpretation No. 39” (“FSP 39-1”). FSP 39-1 permits companies to offset fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) against fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting agreement. In addition, upon the adoption, companies are permitted to change their accounting policy to offset or not offset fair value amounts recognized for derivative instruments under master netting arrangements. The Company adopted FSP 39-1 on October 1, 2008 and elected to change its accounting policy for derivative instruments executed with the same counterparty under a master netting agreement. 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. This change in accounting policy has been presented retroactively. The adoption of FSP 39-1 had the following impact on the September 30, 2008 balance sheet (in millions):


	Original Value		Adjustment			Adjusted Value
Assets from price risk management activities	$	79.2	$	(45.9	)	$	33.3
Prepaid expenses and other current assets		46.1		(24.2	)		21.9
Accrued expenses		89.5		(20.6	)		68.9
Customer deposits		96.5		(8.8	)		87.7
Liabilities from price risk management activities		97.7		(40.7	)		57.0

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities – an amendment of FASB Statement No. 133” (“SFAS 161”). SFAS 161 applies to all derivative instruments and related hedged items accounted for under SFAS 133. SFAS 161 requires entities to provide greater transparency about (a) how and why an entity uses derivative instruments, (b) how derivative instruments and related hedged items are accounted for under SFAS 133 and its related interpretations, and (c) how derivative instruments and related hedged items affect an entity’s financial position, results of operations, and cash flows. The Company adopted SFAS 161 on March 31, 2009. The adoption of SFAS 161 required certain additional disclosures (Note 5), however, it did not impact any amounts comprising the Balance Sheet, Statement of Operations, Statement of Partners’ Capital, or the Statement of Cash Flows.

In December 2007, the FASB issued SFAS No. 141 (revised 2007), “Business Combinations” (“SFAS 141R”), which replaces FASB Statement No. 141. SFAS 141R establishes principles and requirements for how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, any non- controlling interest in the acquiree and the goodwill acquired. The Statement also establishes disclosure requirements designed to enable users to evaluate the nature and financial effects of the business combination. SFAS 141R is required to be adopted by the Company for business combinations for which the acquisition date is on or after October 1, 2009.

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

In December 2007, the FASB issued SFAS No. 160, “Non-controlling Interests in Consolidated Financial Statements—an amendment of ARB No. 51” (“SFAS 160”). SFAS 160 requires that accounting and reporting for minority interests will be recharacterized as non-controlling interests and classified as a component of equity. SFAS 160 also establishes reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the non-controlling owners. SFAS 160 applies to all entities that prepare consolidated financial statements, except not-for-profit organizations, but will affect only those entities that have an outstanding non-controlling interest in one or more subsidiaries or that deconsolidate a subsidiary. SFAS 160 is required to be adopted by the Company for the fiscal year ended September 30, 2010. The Company is evaluating the potential financial statement impact of SFAS 160 to its consolidated financial statements.

In March 2008, the FASB ratified EITF Issue No. 07-4, “Application of the Two-Class Method under FASB Statement No. 128 to Master Limited Partnerships” (“EITF 07-4”). EITF 07-4 applies to Master Limited Partnerships (“MLP”) that are required to make incentive distributions when certain thresholds have been met regardless of whether the IDR is a separate limited partner (“LP”) interest or embedded in the general partner interest. EITF 07-4 addresses how the current period earnings of an MLP should be allocated to the general partner, LP’s and, when applicable, IDR’s. EITF 07-4 is required to be adopted by the Company for the fiscal year ended September 30, 2010. The Company is evaluating the potential financial statement impact of EITF 07-4 to its consolidated financial statements.

In June 2008, the FASB ratified FSP EITF Issue No. 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions are Participating Securities” (“FSP EITF 03-6-1”). FSP EITF 03-6-1 applies to the calculation of earnings per share (“EPS”) under SFAS 128, “Earnings Per Share” for share-based payment awards with rights to dividends or dividend equivalents. FSP EITF 03-6-1 states that unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents are participating securities and shall be included in the computation of EPS pursuant to the two-class method. FSP EITF 03-6-1 is required to be adopted by the Company for the fiscal year ended September 30, 2010. The Company is evaluating the potential financial statement impact of FSP EITF 03-6-1 to its consolidated financial statements.

In May 2009, the FASB issued FASB Statement No. 165, “Subsequent Events” (“SFAS 165”). SFAS 165 establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. The Company adopted SFAS 165 on June 30, 2009. The adoption of SFAS 165 required the Company to disclose the date through which subsequent events have been evaluated and the basis for that date (Note 11). The adoption of SFAS 165 did not impact any amounts comprising the Balance Sheet, Statement of Operations, Statement of Partners’ Capital, or the Statement of Cash Flows.

Note 3 – Certain Balance Sheet Information

Inventories consist of the following at June 30, 2009 and September 30, 2008, respectively (in millions):


	June 30, 2009		September 30, 2008
Propane gas and other liquids	$	62.7	$	83.9
Appliances, parts and supplies		15.5		15.3
Salt finished goods		0.4		0.7

Total inventory	$	78.6	$	99.9

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Property, plant and equipment consists of the following at June 30, 2009 and September 30, 2008, respectively (in millions):


	June 30, 2009		September 30, 2008
Tanks and plant equipment	$	722.2	$	713.8
Buildings and improvements		298.8		265.6
Vehicles		106.9		104.5
Construction in process		289.6		166.5
Office furniture and equipment		25.7		24.6

		1,443.2		1,275.0
Less: accumulated depreciation		301.4		244.7

Total property, plant and equipment, net	$	1,141.8	$	1,030.3

The Tanks and plant equipment balances above include tanks owned by the Company that reside at customer locations. The leases associated with these tanks are accounted for as operating leases in accordance with Statement of Financial Accounting Standard 13 “Accounting for Leases”. The value of tanks available for lease as of June 30, 2009 was approximately $431.9 million, substantially all of which are being leased, with an associated accumulated depreciation balance of approximately $85.6 million.

Intangible assets consist of the following at June 30, 2009 and September 30, 2008, respectively (in millions):


	June 30, 2009		September 30, 2008
Customer accounts	$	268.5	$	266.7
Covenants not to compete		72.5		72.2
Deferred financing and other costs		34.1		28.5
Trademarks		26.2		26.3

		401.3		393.7
Less: accumulated amortization		125.1		105.5

Total intangible assets, net	$	276.2	$	288.2

Note 4 – Business Acquisitions

In October 2008, the Company acquired the assets of the Blu-Gas group of companies (“Blu-Gas”) headquartered in Denver, North Carolina. Blu-Gas delivers propane to approximately 9,300 customers. In conjunction with the acquisition, the Company issued 309,194 common units to Blu-Gas in a private placement as a portion of the purchase price.

On April 9, 2009, the Company acquired the assets of Newton’s Gas Service, Inc. (“Newton’s Gas”) and on June 30, 2009, the Company acquired the assets of F.G. White Company, Inc. (“F.G. White”). Newton’s Gas is headquartered in Colchester, Vermont and delivers propane to approximately 4,400 customers. F.G. White is headquartered in Waitsfield, Vermont and delivers propane to approximately 3,600 customers.

The purchase price allocation for these acquisitions as well as the acquisition of US Salt, LLC in August 2008 have been prepared on a preliminary basis pending final asset valuation and asset rationalization, and changes are expected when additional information becomes available. Changes to reflect final asset valuation of prior fiscal year acquisitions have been included in the Company’s consolidated financial statements but are not material.

US GAAP requires that for any material business combination or disposition of assets, pro-forma information must be disclosed. The fiscal 2009 acquisitions were not considered material.

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

The operating results for these acquisitions are included in the consolidated results of operations from the dates of acquisition through June 30, 2009.

Note 5 – Risk Management

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

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 in accordance with SFAS 133. These instruments are marked to market with the changes in the market value reflected in cost of product sold. Inergy attempts to balance its contractual portfolio in terms of notional amounts and timing of performance and delivery obligations. This balance in the contractual portfolio significantly reduces the volatility in cost of product sold related to these instruments. However, immaterial net unbalanced positions can exist or are established based on assessment of anticipated short-term needs or market conditions.

Cash Flow Hedging Activity

Inergy sells propane and heating oil to retail customers at fixed prices. Inergy will enter into derivative instruments to hedge a significant portion of its exposure to fluctuations in commodity prices as a result of selling the fixed price contracts. These instruments are identified and qualify to be treated as cash flow hedges in accordance with SFAS 133. 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 in accordance with SFAS 133. 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.

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

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, 2009 and September 30, 2008 (in millions):


	June 30, 2009		September 30, 2008
	Fixed Price Payor	Fixed Price Receiver	Fixed Price Payor	Fixed Price Receiver
Propane, crude and heating oil (barrels)	6.8	6.6	8.9	7.5
Natural gas (MMBTU’s)	0.3	—	0.7	—

Notional amounts reflect the volume of transactions, but do not represent the amounts exchanged by the parties to the financial instruments. Accordingly, notional amounts do not reflect the Company’s monetary exposure to market or credit risks.

Fair Value of Derivative Instruments

The following tables detail the amount and location on the Company’s Balance Sheet and Statement of Operations related to all of its commodity derivatives (in millions):


	Amount of Gain (Loss) Recognized in Net Income from Derivatives						Amount of Gain (Loss) Recognized in Net Income on Item Being Hedged
	June 30, 2009						June 30, 2009
	Three Months Ended			Nine Months Ended			Three Months Ended		Nine Months Ended
Derivatives in fair value hedging relationships:
Commodity ^(a)	$	(12.1	)	$	(5.3	)	$	12.1	$	5.6
Debt ^(b)		(2.5	)		3.3			2.5		(3.3	)

Total fair value of derivatives	$	(14.6	)	$	(2.0	)	$	14.6	$	2.3


	Amount of Gain (Loss) Recognized in OCI on Effective Portion of Derivatives				Amount of Gain (Loss) Reclassified from OCI to Net Income						Amount of Gain (Loss) Recognized in Net Income on Ineffective Portion of Derivatives & Amount Excluded from Testing
	June 30, 2009				June 30, 2009						June 30, 2009
	Three Months Ended		Nine Months Ended		Three Months Ended			Nine Months Ended			Three Months Ended		Nine Months Ended
Derivatives in cash flow hedging relationships:
Commodity ^(c)	$	8.2	$	4.8	$	(5.9	)	$	(23.9	)	$	—	$	0.1

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)


	Amount of Gain (Loss) Recognized in Net Income from Derivatives
	June 30, 2009
	Three Months Ended		Nine Months Ended
Derivatives not designated as hedging instruments:
Commodity ^(d)	$	3.6	$	10.7

^(a)	The gain (loss) on both the derivative and the item being hedged are located in cost of goods sold in the Statement of Operations.

^(b)	The gain (loss) on both the derivative and the item being hedged are located in interest expense in the Statement 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 goods sold.

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

The following table summarizes the change in the unrealized fair value of energy derivative contracts related to risk management activities for the nine months ended June 30, 2009 and 2008 where settlement has not yet occurred (in millions):


	Nine Months Ended June 30,
	2009			2008
Net fair value gain (loss) of contracts outstanding at beginning of period	$	(23.7	)	$	0.7
Net change in physical exchange contracts		1.5			0.4
Net changes in cash paid against outstanding positions		4.5			5.5
Change in fair value of contracts attributable to market movement during the period		6.6			16.6
Realized gains (losses)		14.8			(12.6	)

Net fair value of contracts outstanding at end of period	$	3.7		$	10.6

All contracts subject to price risk had a maturity of thirty-two months or less, however, the majority of contracts expire within eighteen 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, 2009 and September 30, 2008 were propane retailers, resellers, energy marketers 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, 2009, is $16.5 million for which the Company has posted collateral of $9.0 million, which includes $2.0 million of NYMEX margin deposit, in the normal course of business. The Company has received collateral of $8.0 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 6 – Fair Value Measurements

SFAS 157 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 defined by SFAS 157 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, 2009, 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, 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 consist of 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.

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, 2009, (in millions). As required by FAS 157, 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.

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)


	Fair Value of Derivatives												Netting Agreements^(a)			Total
	Level 1		Level 2		Level 3		Total		Designated as Hedges		Not Designated as Hedges		Netting Agreements^(a)			Total
Assets
Assets from price risk management	$	1.3	$	62.8	$	0.8	$	64.9	$	9.3	$	55.6	$	(38.4	)	$	26.5
Inventory		—		35.7		—		35.7		—		—		—			35.7
Interest rate swap		—		5.2		—		5.2		5.2		—		—			5.2

Total assets at fair value	$	1.3	$	103.7	$	0.8	$	105.8	$	14.5	$	55.6	$	(38.4	)	$	67.4


Liabilities
Liabilities from price risk management	$	8.3	$	51.7	$	0.5	$	60.5	$	10.2	$	50.3	$	(37.7	)	$	22.8

^(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.

Note 7 – Long-Term Debt

Long-term debt consisted of the following at June 30, 2009 and September 30, 2008, respectively (in millions):


	June 30, 2009			September 30, 2008
Credit agreement	$	43.5		$	247.0
Senior unsecured notes		1,050.0			825.0
Fair value hedge adjustment on senior unsecured notes		5.2			1.9
Bond premium		3.4			3.8
Bond discount		(20.5	)		—
ASC credit agreement		9.1			10.9
Obligations under noncompetition agreements and notes to former owners of businesses acquired		19.9			18.0

Total debt		1,110.6			1,106.6
Less: current portion		22.9			60.5

Total long-term debt	$	1,087.7		$	1,046.1

In February 2009, Inergy closed on a $225 million offering of senior notes under Rule 144A to eligible purchasers. The 8.75% notes mature on March 1, 2015, and were issued at 90.191% of the principal amount to yield 11%. Inergy used the net proceeds from the private placement to repay borrowings under its existing revolving acquisition credit facility.

The Company’s Credit Agreement consists of a $75 million revolving Working Capital Facility and a $350 million revolving Acquisition Facility. The effective amount of working capital borrowing capacity available to the Company under the two facilities is $200 million utilizing capacity under the acquisition credit facility for working capital needed during the winter heating season. The Credit Agreement is guaranteed by each of Inergy’s wholly-owned domestic subsidiaries. This Credit Agreement matures on November 10, 2010.

At June 30, 2009, the balance outstanding under the Credit Agreement was $43.5 million, including $15.5 million borrowed for acquisitions and growth capital expenditures and $28.0 million borrowed for working capital purposes. At September 30, 2008, the balance outstanding under the Credit Agreement was $247.0 million, including $182.0 million borrowed for acquisitions and growth capital expenditures and $65.0 million borrowed for working capital purposes. Lehman Commercial Paper, Inc. (“Lehman CP”), a subsidiary of Lehman Brothers Holdings, Inc., holds a $25 million lender commitment within the Company’s Credit Agreement and filed for Chapter 11 Bankruptcy on October 5, 2008. Inergy does not plan for the Lehman lender commitment to be available for the

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

remainder of the term of the Credit Agreement. The interest rates of these revolvers are based on prime rate and LIBOR plus the applicable spreads, which were between 2.07% and 3.50% at June 30, 2009, and between 4.24% and 5.46% at September 30, 2008, for all outstanding debt under the Credit Agreement. Unused borrowings under the Credit Agreement amounted to $361.1 million and $154.3 million at June 30, 2009 and September 30, 2008, respectively. Outstanding standby letters of credit under the Credit Agreement amounted to $20.4 million and $23.6 million at June 30, 2009 and September 30, 2008, respectively.

Steuben Gas Storage Company, a majority-owned subsidiary of Arlington Storage Company (“ASC”), had a debt agreement in place at the time of the Company’s acquisition of ASC (“ASC Credit Agreement”). The ASC Credit Agreement is secured by the assets of Steuben and has no recourse against the assets of the Company. The ASC Credit Agreement is scheduled to mature in December 2015. The interest rate on approximately half of the ASC Credit Agreement is at a fixed rate, while the other half is based on LIBOR plus the applicable spreads.

Inergy is party to six interest rate swap agreements scheduled to mature in December 2014, each designed to hedge $25 million in underlying fixed rate senior unsecured notes in order to manage interest rate risk exposure. These swap agreements, which expire on the same date as the maturity date of the related senior unsecured notes due 2014 and contain call provisions consistent with the underlying senior unsecured notes, require the counterparty to pay the Company an amount based on the stated fixed interest rate due every nine months. In exchange, Inergy is required to make semi-annual floating interest rate payments on the same dates to the counterparty based on an annual interest rate equal to the 6-month LIBOR interest rate plus spreads between 0.92% and 2.20% applied to the same aggregate notional amount of $150 million. The swap agreements have been accounted for as fair value hedges. Amounts to be received or paid under the agreements are accrued and recognized over the life of the agreements as an adjustment to interest expense. The change in the market value of the interest rate swaps for the nine months ended June 30, 2009 was recorded as a $3.3 million decrease to interest expense. This amount was offset by a $3.3 million increase to interest expense that was recorded as a result of a change in the fair value of the hedged fixed rate debt.

At June 30, 2009, the Company was in compliance with all of its debt covenants.

Note 8 – Partners’ Capital

Common Unit Offering

In March 2009, Inergy issued 4,000,000 common units representing limited partner interests, and in April 2009, the underwriters exercised their option to purchase 418,000 additional Inergy common units. Net proceeds from the aforementioned issuances amounted to approximately $94.3 million.

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Quarterly Distributions of Available Cash

A summary of Inergy’s limited partner quarterly distributions for the nine months ended June 30, 2009 and 2008 is presented below:


Nine Months Ended June 30, 2009
Record Date	Payment Date	Per Unit Rate		Distribution Amount *(in millions)*
November 7, 2008	November 14, 2008	$	0.635	$	43.2
February 6, 2009	February 13, 2009	$	0.645		44.4
May 8, 2009	May 15, 2009	$	0.655		49.2

				$	136.8


Nine Months Ended June 30, 2008
Record Date	Payment Date	Per Unit Rate		Distribution Amount *(in millions)*
November 7, 2007	November 14, 2007	$	0.595	$	38.2
February 7, 2008	February 14, 2008	$	0.605		39.3
May 8, 2008	May 15, 2008	$	0.615		40.2

				$	117.7

On July 27, 2009, Inergy declared a distribution of $0.665 per limited partner unit to be paid on August 14, 2009 to unitholders of record on August 7, 2009 for a total distribution of $50.4 million with respect to the third fiscal quarter of 2009. On August 14, 2008, a quarterly distribution of $0.625 per limited partner unit was paid to unitholders of record on August 7, 2008 with respect to the third fiscal quarter of 2008, for a total distribution of $41.2 million.

Note 9 – Commitments and Contingencies

Inergy periodically enters into agreements with suppliers to purchase fixed quantities of propane, distillates, natural gas and liquids at fixed prices. At June 30, 2009, the total of these firm purchase commitments was approximately $244.5 million of which $239.1 million will occur over the course of the next twelve months with the balance of $5.4 million occurring over the following twelve months. The Company also enters into non-binding agreements with suppliers to purchase quantities of propane, distillates, natural gas and liquids at variable prices at future dates at the then prevailing market prices.

Inergy has entered into certain purchase commitments in connection with the identified growth projects related to the Thomas Corners and West Coast NGL midstream assets. At June 30, 2009, the total of these firm purchase commitments was approximately $30.6 million and the purchases associated with these commitments will occur over the course of the next year.

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

Inergy utilizes third-party insurance subject to varying retention levels of self-insurance, which management considers prudent. Such self-insurance relates to losses and liabilities primarily associated with medical claims, workers’ compensation claims and general, product, vehicle, and environmental liability. Losses are accrued based upon management’s estimates of the aggregate liability for claims incurred using certain assumptions followed in the insurance industry and based on past experience. At June 30, 2009 and September 30, 2008, Inergy’s self-insurance reserves were $16.4 million and $17.4 million, respectively.

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Note 10 – Segments

Inergy’s financial statements reflect two operating and reportable segments: propane operations and midstream operations. Inergy’s propane operations include propane sales to end users, the sale of propane-related appliances and service work for propane-related equipment, the sale of distillate products and wholesale distribution of propane and marketing and price risk management services to other users, retailers and resellers of propane. Inergy’s midstream operations include storage of natural gas for third parties, fractionation of natural gas liquids, processing of natural gas, distribution of natural gas liquids and the production and sale of salt. Results of operations for the acquisitions that occurred during the nine months ended June 30, 2009, 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.

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, 2009
	Propane Operations		Midstream Operations		Intersegment Operations			Corporate Assets		Total
Retail propane revenues	$	87.5	$	—	$	—		$	—	$	87.5
Wholesale propane revenues		44.7		3.3		—			—		48.0
Storage, fractionation and other midstream revenues		—		59.3		—			—		59.3
Transportation revenues		3.8		3.3		—			—		7.1
Propane-related appliance sales revenues		4.9		—		—			—		4.9
Retail service revenues		3.6		—		—			—		3.6
Rental service and other revenues		6.2		—		—			—		6.2
Distillate revenues		18.4		—		—			—		18.4
Gross profit		71.2		26.1		—			—		97.3
Identifiable assets		128.6		34.3		—			—		162.9
Goodwill		279.2		169.5		—			—		448.7
Property, plant and equipment		701.5		730.9		—			10.8		1,443.2
Expenditures for property, plant and equipment		2.8		62.0		—			0.1		64.9

	Three Months Ended June 30, 2008
	Propane Operations		Midstream Operations		Intersegment Operations			Corporate Assets		Total
Retail propane revenues	$	121.7	$	—	$	—		$	—	$	121.7
Wholesale propane revenues		86.4		12.8		—			—		99.2
Storage, fractionation and other midstream revenues		—		93.6		(0.1	)		—		93.5
Transportation revenues		4.6		4.5		—			—		9.1
Propane-related appliance sales revenues		5.1		—		—			—		5.1
Retail service revenues		4.2		—		—			—		4.2
Rental service and other revenues		7.1		—		—			—		7.1
Distillate revenues		35.3		—		—			—		35.3
Gross profit		65.2		23.6		(0.1	)		—		88.7
Identifiable assets		186.1		27.8		—			—		213.9
Goodwill		275.3		88.5		—			—		363.8
Property, plant and equipment		700.3		480.2		—			9.6		1,190.1
Expenditures for property, plant and equipment		3.2		38.6		—			0.5		42.3

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)


	Nine Months Ended June 30, 2009
	Propane Operations		Midstream Operations		Intersegment Operations			Corporate Assets		Total
Retail propane revenues	$	659.3	$	—	$	—		$	—	$	659.3
Wholesale propane revenues		313.3		16.1		(0.1	)		—		329.3
Storage, fractionation and other midstream revenues		—		159.9		(0.6	)		—		159.3
Transportation revenues		13.0		12.2		—			—		25.2
Propane-related appliance sales revenues		16.5		—		—			—		16.5
Retail service revenues		14.2		—		—			—		14.2
Rental service and other revenues		22.3		—		—			—		22.3
Distillate revenues		113.0		—		—			—		113.0
Gross profit		410.5		73.8		(0.6	)		—		483.7
Identifiable assets		128.6		34.3		—			—		162.9
Goodwill		279.2		169.5		—			—		448.7
Property, plant and equipment		701.5		730.9		—			10.8		1,443.2
Expenditures for property, plant and equipment		8.9		156.5		—			0.7		166.1

	Nine Months Ended June 30, 2008
	Propane Operations		Midstream Operations		Intersegment Operations			Corporate Assets		Total
Retail propane revenues	$	724.5	$	—	$	—		$	—	$	724.5
Wholesale propane revenues		398.8		26.3		—			—		425.1
Storage, fractionation and other midstream revenues		—		198.2		(0.4	)		—		197.8
Transportation revenues		12.3		13.6		—			—		25.9
Propane-related appliance sales revenues		17.1		—		—			—		17.1
Retail service revenues		13.3		—		—			—		13.3
Rental service and other revenues		21.7		—		—			—		21.7
Distillate revenues		112.6		—		—			—		112.6
Gross profit		347.7		67.2		(0.4	)		—		414.5
Identifiable assets		186.1		27.8		—			—		213.9
Goodwill		275.3		88.5		—			—		363.8
Property, plant and equipment		700.3		480.2		—			9.6		1,190.1
Expenditures for property, plant and equipment		10.4		136.8		—			0.9		148.1

Note 11 – Subsequent Events

The Company has identified subsequent events requiring disclosure through August 4, 2009, the date of the filing of this Form 10-Q.

On July 29, 2009, the Company filed a Registration Statement on Form S-4 offering to exchange up to $225 million of 8.75% senior notes due 2015, which have been registered under the Securities Act of 1933 for its outstanding unregistered 8.75% senior notes due 2015, which were issued on February 2, 2009. This transaction did not impact the Company’s financial statements.

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, 2008.

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

Overview

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

Both of our operating segments, propane and midstream, are supported by business development personnel groups employed by the Partnership. 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 and to a lesser extent through organic expansion projects. Since the inception of our predecessor in November 1996 through June 30, 2009, we have acquired 84 companies, including 78 retail propane companies and 6 midstream businesses, for an aggregate purchase price of approximately $1.8 billion, including working capital, assumed liabilities and acquisition costs.

In October 2008, we acquired the assets of the Blu-Gas group of companies (“Blu-Gas”) headquartered in Denver, North Carolina, in April 2009, we acquired the assets of Newton’s Gas Service, Inc. (“Newton’s Gas”) and on June 30, 2009, we acquired the assets of F.G.White Company, Inc. (“F.G. White”). The purchase price allocation for these acquisitions has been prepared on a preliminary basis pending final asset valuation and asset rationalization, and changes are expected when additional information becomes available. Changes to final asset valuation of prior fiscal year acquisitions have been included in our consolidated financial statements but are not material.

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

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

The retail propane business is a “margin-based” business where the level of profitability is largely dependent on the difference between sales prices and product costs. Propane prices have continued to be volatile during 2009. At the main pricing hub of Mount Belvieu Texas during the nine-month period ended June 30, 2009, propane prices ranged from a low of $0.53 per gallon to a high of $1.41 per gallon and a price of $0.82 per gallon at June 30, 2009. Our hedging program and ability to pass on price increases to our customers limits the impact that volatility has had on our operations. In the future, we will continue to hedge virtually 100% of our exposure from fixed price sales. While we have historically been successful in passing on any price increases to our customers, there can be no guarantees that this trend will continue in the future. In periods of increasing 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 which has resulted in a decline in gross profit. In periods of decreasing costs, we have experienced an increase in our gross profit as a percentage of revenues. There is no assurance that because propane prices decline customers will use more propane and thus historical gallon sales declines we’ve attributed to customer conservation will reverse. The prices of crude oil and natural gas have maintained historically high costs in 2007, 2008 and in the first half of 2009 and, since propane is a by-product of these commodities, it too has been at historically high levels over this same time frame. As such, our selling prices of propane have been at higher levels in order to attempt to maintain our historical gross margin per gallon. We do not attempt to predict or control the underlying commodity prices; however, we monitor these prices daily and adjust our operations and retail prices to maintain expected margins by passing on the wholesale costs to end users of our product. We believe that volatility in commodity prices will continue, and our ability to adjust to and manage our operations in response to this volatility may impact our operations and financial results.

We believe that the economic downturn that began in the second half of 2008 has caused certain of our retail propane customers to conserve and thereby purchase less propane. This trend is expected to continue throughout the life of the recession. In addition, although we believe the recession has not currently had a material impact on our cash collections, it is possible that a prolonged recession could have a negative impact on our future cash collections.

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

•

forward contracts involving the physical delivery of propane;

•

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

•

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

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

Our midstream operations primarily include the storage, processing, fractionation, and sale of natural gas and NGLs and, to a lesser extent, the wholesale distribution of salt from solution mining operations of US Salt, which was acquired in August 2008. 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.

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.

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. The natural gas industry is currently experiencing a significant shift in the sources of supply, and this dramatic change could affect our operations. Traditionally, supply to our markets has come from the Gulf Coast region, onshore and offshore, as well as from Canada. The national supply profile is shifting to new sources of natural gas from basins in the Rockies, Mid-Continent, Appalachia and East Texas. In addition, the natural gas supply outlook includes new LNG regasification facilities under various stages of development in multiple locations. LNG can be a new source of potential supply, but the timing and extent of incremental supply ultimately realized from LNG is yet to be determined and, at present, LNG remains a small percentage of the overall supply to the markets we serve. These supply shifts and other changes to the natural gas market may have an impact on our storage operations and our development plans in the northeastern United States and may ultimately drive the need for more domestic capacity for natural gas storage. Currently, we have committed to capital expansion projects at our Thomas Corners natural gas storage development and our Finger Lakes LPG storage expansion. The rights to the Thomas Corners development were obtained when we acquired ASC in October 2007. Thomas Corners is located in Steuben County, NY and is expected to have working gas capacity of approximately 7 bcf when complete. This project is expected to be completed in 2010. The Finger Lakes LPG storage expansion project relates to the development of certain caverns acquired in the acquisition of US Salt in August 2008. The solution mining process creates caverns that can be developed into LPG or Natural Gas storage after the salt has been extracted. The Finger Lakes LPG expansion project is expected to convert certain of the caverns at US Salt into LPG storage with a capacity of up to 5 million barrels. This project is expected to be completed in 2010.

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, 2009 of approximately $30.6 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 storage industry 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, 2009 Compared to Three Months Ended June 30, 2008

The following table summarizes the consolidated income statement components for the three months ended June 30, 2009 and 2008, respectively (in millions):


	Three Months Ended June 30,						Change
	2009			2008			In Dollars			Percentage
Revenue	$	235.0		$	375.2		$	(140.2	)	(37.4	)%
Cost of product sold		137.7			286.5			(148.8	)	(51.9	)

Gross profit		97.3			88.7			8.6		9.7
Operating and administrative expenses		66.4			67.1			(0.7	)	(1.0	)
Depreciation and amortization		26.4			26.1			0.3		1.1
Loss on disposal of assets		(1.1	)		(0.4	)		(0.7	)	(175.0	)

Operating income (loss)		3.4			(4.9	)		8.3		169.4
Interest expense, net		(17.2	)		(15.2	)		(2.0	)	(13.2	)

Loss before income taxes and interest of non-controlling partners in ASC		(13.8	)		(20.1	)		6.3		31.3
Provision for income taxes		(0.2	)		(0.2	)		—		—
Interest of non-controlling partners in ASC’s consolidated net income		(0.3	)		(0.4	)		0.1		25.0

Net loss	$	(14.3	)	$	(20.7	)	$	6.4		30.9	%

The following table summarizes revenues, including associated volume of gallons sold, for the three months ended June 30, 2009 and 2008, respectively (in millions):


	Revenues									Gallons
	Three Months Ended June 30,				Change					Three Months Ended June 30,		Change
	2009		2008		In Dollars			Percent		2009	2008	In Units		Percent
Retail propane	$	87.5	$	121.7	$	(34.2	)	(28.1	)%	41.9	46.7	(4.8	)	(10.3	)%
Wholesale propane		48.0		99.2		(51.2	)	(51.6	)	60.7	59.8	0.9		1.5
Other retail		36.9		56.3		(19.4	)	(34.5	)	—	—	—		—
Storage, fractionation and midstream		62.6		98.0		(35.4	)	(36.1	)	—	—	—		—

Total	$	235.0	$	375.2	$	(140.2	)	(37.4	)%	102.6	106.5	(3.9	)	(3.7	)%

Volume. During the three months ended June 30, 2009, we sold approximately 41.9 million retail gallons of propane, a decrease of 4.8 million gallons or 10.3% from the 46.7 million retail gallons sold during the same three-month period in 2008. Gallons sold during the three months ended June 30, 2009 declined as compared to the same prior year period as a result of lower volumes sold at our existing locations of 5.8 million gallons partially offset by a 1.0 million gallon increase from acquisition-related volume. We believe the decline in volumes at existing locations resulted from (1) continued customer conservation due to the current overall weak United States economic environment and to a lesser extent the lingering effects of propane cost, which had been at record high prices the past several years, and (2) volume declines from net customer losses during earlier periods of relatively high propane costs, including low margin and less profitable customers.

Wholesale gallons delivered increased 0.9 million gallons, or 1.5%, to 60.7 million gallons in the three months ended June 30, 2009 from 59.8 million gallons in the three months ended June 30, 2008. The increase was due primarily to greater volumes sold to existing customers and addition of new customers.

The total natural gas liquid gallons sold or processed by our West Coast NGL operations decreased 16.3 million gallons, or 17.9%, to 74.8 million gallons during the three months ended June 30, 2009 from 91.1 million gallons during the same three-month period in 2008. This decrease was partially attributed to the non-renewal of certain customer contracts.

During the three months ended June 30, 2009 and 2008, our Northeast natural gas and LPG storage facilities were 100% contracted. The total volume available for storage was the same during each of these periods.

Revenues. Revenues for the three months ended June 30, 2009 were $235.0 million, a decrease of $140.2 million, or 37.4%, from $375.2 million during the same three-month period in 2008.

Revenues from retail propane sales were $87.5 million for the three months ended June 30, 2009 compared to $121.7 million during the same three-month period in 2008. This $34.2 million, or 28.1%, decrease resulted primarily from a combination of a lower overall average selling price of propane due to a reduction in the wholesale cost of propane and a decline in gallons sold to existing customers as described above, which together contributed to a $36.6 million revenue decline, partially offset by acquisition-related sales, which resulted in higher revenues of $2.4 million.

Revenues from wholesale propane sales were $48.0 million in the three months ended June 30, 2009, a decrease of $51.2 million or 51.6%, from $99.2 million in the three months ended June 30, 2008. This decrease resulted primarily from the lower average selling price of propane, which contributed $52.7 million to the decrease in revenues. The lower selling price for our wholesale propane sales in 2009 compared to 2008 was the result of the lower cost of propane. This decrease was partially offset by increases in volume sold to existing and new customers.

Revenues from other retail sales, which primarily includes distillates, service, rental, appliance sales and transportation services, were $36.9 million for the three months ended June 30, 2009, a decrease of $19.4 million, or 34.5%, from $56.3 million during the same three-month period in 2008. Revenue from other retail sales declined $17.0 million as a result of lower average selling prices of distillates at existing locations and $2.8 million due to a decline in revenues from other products and services, partially offset by a $0.4 million increase from acquisition-related sales. Distillate revenues from existing locations decreased as a result of lower volume sold coupled with a decline in the comparable average selling price of the distillates resulting from a lower wholesale cost.

Revenues from storage, fractionation and other midstream activities were $62.6 million for the three months ended June 30, 2009, a decrease of $35.4 million or 36.1% from $98.0 million during the same three-month period in 2008. Revenues from our West Coast NGL operations decreased $48.8 million primarily as a result of decreases in commodity cost and expected changes in the variety of natural gas liquid products sold. Partially offsetting this decrease was a $12.8 million increase due to the acquisition of US Salt. In addition, revenues at our Stagecoach Storage Facility increased due to the commencement of operations on the North Lateral connecting to Millennium Pipeline in December 2008.

Cost of Product Sold. Cost of product sold for the three months ended June 30, 2009 was $137.7 million, a decrease of $148.8 million, or 51.9%, from $286.5 million during the same three-month period in 2008.

Retail propane cost of product sold was $37.9 million for the three months ended June 30, 2009 compared to $78.2 million for the same three-month period in 2008. This $40.3 million, or 51.5%, decrease in retail cost of product sold was driven by an approximate 46.0% decline in the average per gallon cost of propane along with lower volume sales at our existing locations as discussed above, which together reduced costs by approximately $40.6 million. Also contributing to the decline in retail propane cost of product sold was a $0.6 million decrease due to changes in non-cash charges on derivative contracts associated with retail propane fixed price sales contracts. These factors were partially offset by a $0.9 million increase in retail propane cost of product sold associated with acquisition-related volume.

Wholesale propane cost of product sold in the three months ended June 30, 2009 was $43.4 million, a decrease of $51.5 million or 54.3%, from wholesale cost of product sold of $94.9 million in 2008. These lower costs were primarily a result of an approximate $52.9 million decrease due to the lower average cost of propane, partially offset by a $1.4 million increase in volume sold to existing and new customers.

Other retail cost of product sold was $19.6 million for the three months ended June 30, 2009 compared to $38.8 million during the same three-month period in 2008. This $19.2 million, or 49.5%, decrease was primarily due to lower costs from distillate sales at existing locations of $18.3 million and a decline in costs for other products and services of $1.0 million, partially offset by a $0.1

million increase in the cost of product sold associated with acquisition-related volume. The cost of product sold for distillates declined as a result of lower volume sales at existing locations coupled with an approximate 47.3% decline in the average cost per gallon of distillates.

Storage, fractionation and other midstream cost of product sold was $36.8 million for the three months ended June 30, 2009, a decrease of $37.8 million, or 50.7%, from $74.6 million during the same three-month period in 2008. Costs from our West Coast NGL operations were $45.7 million lower primarily as a result of decreases in commodity cost and expected changes in the variety of natural gas liquid products sold due to additional contracts. Partially offsetting this decrease was a $7.7 million increase in cost due to the acquisition of US Salt.

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, and depreciation on tanks being rented to customers. Costs associated with delivery vehicles approximated $14.4 million and $16.2 million for the three months ended June 30, 2009 and 2008, respectively. In addition, the depreciation expense associated with the delivery vehicles and customer tanks is reported within depreciation and amortization expense and amounted to $8.5 million and $8.4 million for the three months ended June 30, 2009 and 2008, respectively. Since we include these costs in our operating and administrative expense and depreciation and amortization expense rather than in cost of product sold, our results may not be comparable to other entities in our lines of business if they include these costs in cost of product sold.

Our storage, fractionation and other midstream cost of product sold consists primarily of commodity and transportation costs. Other costs incurred in conjunction with these services are included in operating and administrative expense and depreciation and amortization expense and consist primarily of depreciation, vehicle costs consisting of fuel costs and repair and maintenance and wages. Depreciation expense for storage, fractionation and other midstream amounted to $7.7 million and $7.3 million for the three months ended June 30, 2009 and 2008, respectively. Vehicle costs and wages for personnel directly involved in providing midstream services amounted to $0.9 million for the three months ended June 30, 2009 and 2008. Since we include these costs in our operating and administrative expense and depreciation and amortization expense rather than in cost of product sold, our results may not be comparable to other entities in our lines of business if they include these costs in cost of product sold.

Gross Profit. Gross profit for the three months ended June 30, 2009 was $97.3 million, an increase of $8.6 million, or 9.7%, from $88.7 million during the same three-month period in 2008.

Retail propane gross profit was $49.6 million for the three months ended June 30, 2009 compared to $43.5 million in the same three-month period in 2008. This $6.1 million, or 14.0%, increase in retail propane gross profit was mostly attributable to a higher cash margin per gallon, which contributed to a $9.4 million increase, a $1.5 million increase associated with acquisitions, and a $0.6 million increase related to changes in non-cash charges on derivative contracts associated with retail propane fixed price sales contracts as discussed above. These increases to retail propane gross profit were partially offset by a $5.4 million decline resulting from lower retail gallon sales at existing locations as discussed above. The increase in cash margin per gallon was primarily the result of maintaining higher selling prices in certain markets while cost of propane declined.

Wholesale propane gross profit was $4.6 million in the three months ended June 30, 2009 compared to $4.3 million in the three months ended June 30, 2008, an increase of $0.3 million or 7.0%. This increase was primarily the result of both increased volumes sold and higher margins that we were able to attain in a period of regional supply disruption.

Other retail gross profit was $17.3 million for the three months ended June 30, 2009 compared to $17.5 million for the same three-month period in 2008. This $0.2 million, or 1.1%, decrease was due primarily to lower gross profit on other products and services of $1.8 million, partially offset by a $1.3 million increase in gross profit from distillate sales and a $0.3 million increase from acquisitions.

Storage, fractionation and other midstream gross profit was $25.8 million in the three months ended June 30, 2009 compared to $23.4 million in the same three-month period in 2008, an increase of $2.4 million, or 10.3%. Approximately $5.1 million of this increase was due to the acquisition of US Salt, which was partially offset by a decrease in gross profit from our West Coast NGL operations. The decrease in West Coast gross profit is attributable to the factors discussed in the decline in volumes.

Operating and Administrative Expenses. Operating and administrative expenses were $66.4 million for the three months ended June 30, 2009 compared to $67.1 million in the same three-month period in 2008. This $0.7 million, or 1.0%, decrease in operating expenses was due primarily to lower operating expenses from existing operations of approximately $2.6 million comprised predominantly of lower vehicle expenses and other operating expenses. Partially offsetting these decreases was an increase of approximately $1.9 million due to acquisitions.

Depreciation and Amortization. Depreciation and amortization was $26.4 million for the three months ended June 30, 2009 compared to $26.1 million during the same three-month period in 2008. This $0.3 million, or 1.1%, increase resulted primarily from acquisitions and the expansion projects completed in our midstream segment.

Interest Expense. Interest expense was $17.2 million for the three months ended June 30, 2009 compared to $15.2 million during the same three-month period in 2008. This $2.0 million, or 13.2%, increase was due to an increase in the average debt outstanding associated with acquisitions, capital improvement projects and working capital needs, partially offset by lower average interest rates associated with our floating rate debt. Additionally, during the three months ended June 30, 2009 and 2008, we capitalized $5.1 million and $1.6 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.

Net Income (loss). Net loss was $(14.3) million for the three months ended June 30, 2009 compared to a net loss of $(20.7) million for the same three-month period in 2008. The $6.4 million, or 30.9%, improvement was primarily attributable to a higher gross profit, partially offset by higher depreciation and amortization and interest expense in the 2009 period.

EBITDA and Adjusted EBITDA. The following table summarizes EBITDA and Adjusted EBITDA for the three months ended June 30, 2009 and 2008, respectively (in millions):


	Three Months Ended June 30,
	2009			2008
EBITDA:
Net loss	$	(14.3	)	$	(20.7	)
Interest of non-controlling partners in ASC’s consolidated ITDA ^(a)		(0.1	)		(0.2	)
Interest expense, net		17.2			15.2
Provision for income taxes		0.2			0.2
Depreciation and amortization		26.4			26.1

EBITDA	$	29.4		$	20.6

Non-cash loss on derivative contracts		—			0.6
Non-cash compensation expense		0.8			0.4
Loss on disposal of assets		1.1			0.4

Adjusted EBITDA	$	31.3		$	22.0

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


	Three Months Ended June 30,
	2009			2008
EBITDA:
Net cash provided by operating activities	$	67.6		$	85.4
Net changes in working capital balances		(49.2	)		(74.3	)
Provision for doubtful accounts		(2.4	)		(3.8	)
Amortization of deferred financing costs and net bond discount		(1.7	)		(0.7	)
Non-cash compensation expense		(0.8	)		(0.4	)
Gain (loss) on disposal of assets		(1.1	)		(0.4	)
Interest of non-controlling partners in ASC’s consolidated EBITDA		(0.4	)		(0.6	)
Interest expense, net		17.2			15.2
Provision for income taxes		0.2			0.2

EBITDA	$	29.4		$	20.6

Non-cash loss on derivative contracts		—			0.6
Non-cash compensation expense		0.8			0.4
Loss on disposal of assets		1.1			0.4

Adjusted EBITDA	$	31.3		$	22.0

EBITDA is defined as income before taxes, plus net interest expense and depreciation and amortization expense. For the three months ended June 30, 2009 and 2008, EBITDA was $29.4 million and $20.6 million, respectively. This $8.8 million improvement in EBITDA was primarily attributable to higher gross profit offset in part by higher operating expenses during the three months ended June 30, 2009. 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 and non-cash compensation expenses. Adjusted EBITDA was $31.3 million for the three months ended June 30, 2009 compared to $22.0 million in the same three-month period in 2008. EBITDA and Adjusted EBITDA should not be considered an alternative to net income, income before income taxes, cash flows from operating activities, or any other measure of financial performance calculated in accordance with generally accepted accounting principles as those items are used to measure operating performance, liquidity or the ability to service debt obligations. We believe that EBITDA and Adjusted EBITDA provide additional information for evaluating our financial performance without regard to our financing methods, capital structure, and historical cost basis. Further, we believe that EBITDA and Adjusted EBITDA provide additional information for evaluating our ability to make the minimum quarterly distribution and are presented solely as supplemental measures. EBITDA and Adjusted EBITDA, as we define them, may not be comparable to EBITDA and Adjusted EBITDA or similarly titled measures used by other corporations or partnerships.

Nine Months Ended June 30, 2009 Compared to Nine Months Ended June 30, 2008

The following table summarizes the consolidated income statement components for the nine months ended June 30, 2009 and 2008, respectively (in millions):


	Nine Months Ended June 30,						Change
	2009			2008			In Dollars			Percentage
Revenue	$	1,339.1		$	1,538.0		$	(198.9	)	(12.9	)%
Cost of product sold		855.4			1,123.5			(268.1	)	(23.9	)

Gross profit		483.7			414.5			69.2		16.7
Operating and administrative expenses		212.6			198.6			14.0		7.0
Depreciation and amortization		79.3			72.1			7.2		10.0
Gain (loss) on disposal of assets		(4.1	)		0.8			(4.9	)	(612.5	)

Operating income		187.7			144.6			43.1		29.8
Interest expense, net		(52.1	)		(45.0	)		(7.1	)	(15.8	)
Other income		—			0.1			(0.1	)	(100.0	)

Income before income taxes and interest of non-controlling partners in ASC		135.6			99.7			35.9		36.0
Provision for income taxes		(0.4	)		(0.6	)		0.2		33.3
Interest of non-controlling partners in ASC’s consolidated net income		(1.0	)		(0.9	)		(0.1	)	(11.1	)

Net income	$	134.2		$	98.2		$	36.0		36.7	%

The following table summarizes revenues, including associated volume of gallons sold, for the nine months ended June 30, 2009 and 2008, respectively (in millions):


	Revenues									Gallons
	Nine Months Ended June 30,				Change					Nine Months Ended June 30,		Change
	2009		2008		In Dollars			Percent		2009	2008	In Units		Percent
Retail propane	$	659.3	$	724.5	$	(65.2	)	(9.0	)%	271.0	289.7	(18.7	)	(6.5	)%
Wholesale propane		329.3		425.1		(95.8	)	(22.5	)	310.6	285.7	24.9		8.7
Other retail		179.0		177.0		2.0		1.1		—	—	—		—
Storage, fractionation and midstream		171.5		211.4		(39.9	)	(18.9	)	—	—	—		—

Total	$	1,339.1	$	1,538.0	$	(198.9	)	(12.9	)%	581.6	575.4	6.2		1.1	%

Volume. During the nine months ended June 30, 2009, we sold approximately 271.0 million retail gallons of propane, a decrease of 18.7 million gallons, or 6.5%, from the 289.7 million retail gallons sold during the same nine-month period in 2008. This decline in gallons sold during the nine months ended June 30, 2009 compared to the same prior year period resulted from a decline in volume sold at our exiting locations of 30.9 million gallons partially offset by a 12.2 million gallon increase arising from acquisition-related volume. Although the weather in our areas of operations was approximately 7% colder than the prior year period and approximately normal when compared to our calculations using degree day data provided by NOAA, the increase in gallon sales associated with this colder weather was more than offset by (1) continued customer conservation, which we believe resulted primarily from the lingering effects of the higher cost of propane that existed at the end of our fiscal year 2008 and into the early part of our first fiscal quarter of 2009 before costs declined substantially, as well as the overall weak United States economic environment, and (2) volume declines from net customer losses during these periods of high propane costs, including low margin and less profitable customers.

Wholesale gallons delivered increased 24.9 million gallons, or 8.7%, to 310.6 million gallons in the nine months ended June 30, 2009 from 285.7 million gallons in the nine months ended June 30, 2008. The increase was due primarily to greater volumes sold to existing customers and addition of new customers.

The total natural gas liquid gallons sold or processed by our West Coast NGL operations decreased 1.1 million gallons, or 0.5%, to 201.0 million gallons during the nine months ended June 30, 2009 from 202.1 million gallons during the same nine-month period in 2008.

During the nine months ended June 30, 2009 and 2008, our Northeast natural gas and LPG storage facilities were 100% contracted. The total volume available for storage was the same during each of these periods.

Revenues. Revenues for the nine months ended June 30, 2009 were $1,339.1 million, a decrease of $198.9 million, or 12.9%, from $1,538.0 million during the same nine-month period in 2008.

Revenues from retail propane sales were $659.3 million for the nine months ended June 30, 2009 compared to $724.5 million during the same nine-month period in 2008. This $65.2 million, or 9.0%, decrease resulted primarily from a combination of a lower overall average selling price of propane due to a reduction in the wholesale cost of propane and lower volume sales to existing customers as described above, which together contributed to a $95.4 million revenue decline, partially offset by acquisition-related sales, which resulted in higher revenues of $30.2 million.

Revenues from wholesale propane sales were $329.3 million in the nine months ended June 30, 2009, a decrease of $95.8 million or 22.5%, from $425.1 million in the nine months ended June 30, 2008. This decrease resulted primarily from the lower average selling price of propane, which contributed $132.9 million to the decrease in revenues. The lower selling price for our wholesale propane sales in 2009 compared to 2008 was the result of the lower cost of propane. This decrease was partially offset by increases in volume sold to existing and new customers.

Revenues from other retail sales, which primarily includes distillates, service, rental, appliance sales and transportation services, were $179.0 million for the nine months ended June 30, 2009, an increase of $2.0 million, or 1.1%, from $177.0 million during the same nine-month period in 2008. Revenues from other retail sales increased approximately $47.5 million due to acquisition-related sales, partially offset by a decline in distillate revenues from existing locations of approximately $41.9 million and a decline in other revenues of $3.6 million. The decrease in distillate revenues at existing locations was the result of lower volume sold coupled with a decline in the comparable average selling price of the distillates resulting from a lower wholesale cost.

Revenues from storage, fractionation and other midstream activities were $171.5 million for the nine months ended June 30, 2009, a decrease of $39.9 million or 18.9% from $211.4 million during the same nine-month period in 2008. Revenues from our West Coast NGL operations decreased $78.6 million primarily as a result of decreases in commodity cost and expected changes in the variety of natural gas liquid products sold. Partially offsetting this decrease was a $36.2 million increase due to the acquisition of US Salt. In addition, revenues at our Bath LPG Storage Facility and Stagecoach Storage Facility increased due to an increase in contractual rates and the commencement of operations on the North Lateral connecting to Millennium Pipeline in December 2008, respectively.

Cost of Product Sold. Cost of product sold for the nine months ended June 30, 2009 was $855.4 million, a decrease of $268.1 million, or 23.9%, from $1,123.5 million during the same nine-month period in 2008.

Retail propane cost of product sold was $337.7 million for the nine months ended June 30, 2009 compared to $451.5 million for the same nine-month period in 2008. This $113.8 million, or 25.2%, decrease in retail cost of product sold was driven by an approximate 20.1% decline in the average per gallon cost of propane along with lower volume sales at our existing locations as discussed above, which together reduced costs by approximately $127.7 million. These factors were partially offset by a $13.1 million increase in the cost of product sold associated with acquisition-related volume and a $0.8 million increase in cost of product sold related 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, 2009 was $310.4 million, a decrease of $100.1 million or 24.4%, from wholesale cost of product sold of $410.5 million in 2008. These lower costs were primarily a result of an approximate $135.9 million decrease due to the lower average cost of propane, partially offset by a $35.8 million increase in volume sold to existing and new customers.

Other retail cost of product sold was $108.6 million for the nine months ended June 30, 2009 compared to $116.6 million during the same nine-month period in 2008. This $8.0 million, or 6.9%, decrease was primarily due to a $44.4 million reduction in cost of product sold related to distillate sales at existing locations due to both declines in volumes sold and the average cost of product. Also contributing to the decline in other retail cost of product sold was a reduction in costs related to other products and services of $0.6 million. These factors were partially offset by higher costs associated with acquisitions of $37.0 million.

Storage, fractionation and other midstream cost of product sold was $98.7 million for the nine months ended June 30, 2009, a decrease of $46.2 million, or 31.9%, from $144.9 million during the same nine-month period in 2008. Costs from our West Coast NGL operations were $72.8 million lower primarily as a result of decreases in commodity cost and expected changes in the variety of natural gas liquid products sold due to additional contracts. Partially offsetting this decrease was a $23.6 million increase in cost due to the acquisition of US Salt.

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, and depreciation on tanks being rented to customers. Costs associated with delivery vehicles approximated $48.5 million and $52.1 million for the nine months ended June 30, 2009 and 2008, respectively. In addition, the depreciation expense associated with the delivery vehicles and customer tanks is reported within depreciation and amortization expense and amounted to $24.9 million and $24.6 million for the nine months ended June 30, 2009 and 2008, respectively. Since we include these costs in our operating and administrative expense and depreciation and amortization expense rather than in cost of product sold, our results may not be comparable to other entities in our lines of business if they include these costs in cost of product sold.

Our storage, fractionation and other midstream cost of product sold consists primarily of commodity and transportation costs. Other costs incurred in conjunction with these services are included in operating and administrative expense and depreciation and amortization expense and consist primarily of depreciation, vehicle costs consisting of fuel costs and repair and maintenance and wages. Depreciation expense for storage, fractionation and other midstream amounted to $22.9 million and $20.3 million for the nine months ended June 30, 2009 and 2008, respectively. Vehicle costs and wages for personnel directly involved in providing midstream services amounted to $2.4 million and $2.2 million for the nine months ended June 30, 2009 and 2008, respectively. Since we include these costs in our operating and administrative expense and depreciation and amortization expense rather than in cost of product sold, our results may not be comparable to other entities in our lines of business if they include these costs in cost of product sold.

Gross Profit. Gross profit for the nine months ended June 30, 2009 was $483.7 million, an increase of $69.2 million, or 16.7%, from $414.5 million during the same nine-month period in 2008.

Retail propane gross profit was $321.6 million for the nine months ended June 30, 2009 compared to $273.0 million in the same nine-month period in 2008. This $48.6 million, or 17.8%, increase in retail propane gross profit was mostly attributable to a higher cash margin per gallon, which contributed an increase to gross profit of approximately $61.5 million, and an increase of $17.1 million associated with acquisitions, partially offset by a $29.2 million decline in gross profit resulting from lower retail gallon sales at existing locations as discussed above and a $0.8 million decline related to changes in non-cash charges on derivative contracts associated with retail propane fixed price sales contracts. The increase in cash margin per gallon was primarily the result of maintaining higher selling prices in certain markets while the cost of propane declined.

Wholesale propane gross profit was $18.9 million in the nine months ended June 30, 2009 compared to $14.6 million in the nine months ended June 30, 2008, an increase of $4.3 million or 29.5%. This increase was primarily the result of both increased volumes sold and higher margins that we were able to attain in a period of regional supply disruption.

Other retail gross profit was $70.4 million for the nine months ended June 30, 2009 compared to $60.4 million for the same nine-month period in 2008. This $10.0 million, or 16.6%, increase was due primarily to a $10.5 million increase from acquisitions and a $2.5 million increase in distillate gross profit, partially offset by a $3.0 million decline in gross profit for other products and services.

Storage, fractionation and other midstream gross profit was $72.8 million in the nine months ended June 30, 2009 compared to $66.5 million in the same nine-month period in 2008, an increase of $6.3 million, or 9.5%. Approximately $12.6 million of this increase was due to the acquisition of US Salt, which was partially offset by a decrease in gross profit from our West Coast NGL operations. The decrease in West Coast gross profit is partially attributable to losses taken on certain commodity contracts due to a brief delay in our butane isomerization unit being placed in service. The aforementioned isomerization unit has been placed in service in July 2009. The decrease is also attributable to the non-renewal of certain customer contracts.

Operating and Administrative Expenses. Operating and administrative expenses were $212.6 million for the nine months ended June 30, 2009 compared to $198.6 million in the same nine-month period in 2008. This $14.0 million, or 7.0%, increase in operating expenses was due primarily to acquisitions and incentive compensation, which increased $14.3 million and $8.3 million, respectively. Offsetting these increases were lower operating expenses from existing operations of approximately $8.6 million comprised predominantly of lower salaries, vehicle expenses and other operating expenses.

Depreciation and Amortization. Depreciation and amortization was $79.3 million for the nine months ended June 30, 2009 compared to $72.1 million during the same nine-month period in 2008. This $7.2 million, or 10.0%, increase resulted primarily from acquisitions and the expansion projects in our midstream segment.

Interest Expense. Interest expense was $52.1 million for the nine months ended June 30, 2009 compared to $45.0 million during the same nine-month period in 2008. This $7.1 million, or 15.8%, increase was due to an increase in the average debt outstanding associated with acquisitions, capital improvement projects and working capital needs, partially offset by lower average interest rates associated with our floating rate debt. Additionally, during the nine months ended June 30, 2009 and 2008, we capitalized $10.5 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.

Net Income. Net income was $134.2 million for the nine months ended June 30, 2009 compared to net income of $98.2 million for the same nine-month period in 2008. The $36.0 million, or 36.7%, increase in net income was primarily attributable to a higher gross profit, partially offset by higher operating expenses, depreciation and amortization and interest expense in the 2009 period.

EBITDA and Adjusted EBITDA. The following tables summarize EBITDA and Adjusted EBITDA for the nine months ended June 30, 2009 and 2008, respectively (in millions):


	Nine Months Ended June 30,
	2009			2008
EBITDA:
Net income	$	134.2		$	98.2
Interest of non-controlling partners in ASC’s consolidated ITDA ^(a)		(0.4	)		(0.7	)
Interest expense, net		52.1			45.0
Provision for income taxes		0.4			0.6
Depreciation and amortization		79.3			72.1

EBITDA	$	265.6		$	215.2

Non-cash loss on derivative contracts		1.5			0.7
Non-cash compensation expense		2.2			1.2
(Gain) loss on disposal of assets		4.1			(0.8	)

Adjusted EBITDA	$	273.4		$	216.3

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


	Nine Months Ended June 30,
	2009			2008
EBITDA:
Net cash provided by operating activities	$	209.2		$	151.0
Net changes in working capital balances		18.3			27.4
Provision for doubtful accounts		(3.2	)		(5.0	)
Amortization of deferred financing costs and net bond discount		(3.5	)		(1.8	)
Non-cash compensation expense		(2.2	)		(1.2	)
Gain (loss) on disposal of assets		(4.1	)		0.8
Interest of non-controlling partners in ASC’s consolidated EBITDA		(1.4	)		(1.6	)
Interest expense, net		52.1			45.0
Provision for income taxes		0.4			0.6

EBITDA	$	265.6		$	215.2

Non-cash loss on derivative contracts		1.5			0.7
Non-cash compensation expense		2.2			1.2
(Gain) loss on disposal of assets		4.1			(0.8	)

Adjusted EBITDA	$	273.4		$	216.3

EBITDA is defined as income before taxes, plus net interest expense and depreciation and amortization expense. For the nine months ended June 30, 2009 and 2008, EBITDA was $265.6 million and $215.2 million, respectively. This $50.4 million improvement in EBITDA was primarily attributable to higher gross profit offset in part by higher operating expenses during the nine months ended June 30, 2009. 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 and non-cash compensation expenses. Adjusted EBITDA was $273.4 million for the nine months ended June 30, 2009 compared to $216.3 million in the same nine-month period in 2008. EBITDA and Adjusted EBITDA should not be considered an alternative to net income, income before income taxes, cash flows from operating activities, or any other measure of financial performance calculated in accordance with generally accepted accounting principles as those items are used to measure operating performance, liquidity or the ability to service debt obligations. We believe that EBITDA and Adjusted EBITDA provide additional information for evaluating our financial performance without regard to our financing methods, capital structure, and historical cost basis. Further, we believe that EBITDA and Adjusted EBITDA provide additional information for evaluating our ability to make the minimum quarterly distribution and are presented solely as supplemental measures. EBITDA and Adjusted EBITDA, as we define them, may not be comparable to EBITDA and Adjusted EBITDA or similarly titled measures used by other corporations or partnerships.

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 $209.2 million and $151.0 million for the nine-month periods ending June 30, 2009 and 2008, respectively. The $58.2 million increase in operating cash flows was primarily attributable to increases in cash components of net income as well as net changes in working capital balances.

Net investing cash outflows were $161.1 million and $222.6 million for the nine-month periods ending June 30, 2009 and 2008, respectively. Net cash outflows were primarily impacted by an $89.3 million decrease in cash outlays related to acquisitions, partially offset by a $21.9 million decrease in proceeds from the sale of assets and a $5.8 million increase in capital expenditures.

Net financing cash (outflows) inflows were $(52.4) million and $74.6 million for the nine-month periods ending June 30, 2009 and 2008, respectively. The net change was primarily impacted by a $196.3 million decrease in proceeds related to the issuance of long-term debt, net of payments on long-term debt, and a $19.1 million increase in total distributions paid, partially offset by a $94.3 million increase in proceeds from the issuance of common units.

We believe that anticipated cash from operations and borrowing capacity under our Credit Agreement described below will be sufficient to meet our liquidity needs for the foreseeable future. If our plans or assumptions change or are inaccurate, or we make acquisitions, we may need to raise additional capital. We give no assurance that we can raise additional capital to meet these needs. Global financial markets and economic conditions have been, and continue to be, disrupted and volatile. The debt and equity capital markets have been distressed. These issues, along with significant write-offs in the financial services sector, the re-pricing of credit risk and the current weak economic conditions, may make it difficult to obtain necessary funding. We have identified capital expansion project opportunities in our midstream operations. As of June 30, 2009, we have firm purchase commitments totaling approximately $30.6 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.

In February 2009, we closed on a $225 million offering of senior notes under Rule 144A to eligible purchasers. The 8 .75% notes mature on March 1, 2015, and were issued at 90.191% of the principal amount to yield 11%. We used the net proceeds from the private placement to repay borrowings under our existing revolving acquisition credit facility.

On July 29, 2009, we filed a Registration Statement on Form S-4 offering to exchange up to $225 million of 8.75% senior notes due 2015, which have been registered under the Securities Act of 1933 for our outstanding unregistered 8.75% senior notes due 2015, which were issued on February 2, 2009. This transaction did not impact our financial statements.

Description of Credit Facility

We maintain borrowing capacity under a credit facility (“Credit Agreement”), which consists of a $75 million revolving working capital facility (“Working Capital Facility”) and a $350 million revolving acquisition facility (“Acquisition Facility”). The effective amount of working capital borrowing capacity available to us under the two facilities is $200 million utilizing capacity under the acquisition credit facility for working capital needed during the winter heating season. Lehman Commercial Paper, Inc. (“Lehman CP”), a subsidiary of Lehman Brothers Holdings, Inc., holds a $25 million lender commitment within our Credit Agreement and filed for Chapter 11 Bankruptcy on October 5, 2008. We do not plan for the Lehman lender commitment to be available for the remainder of the term of the Credit Agreement. The Credit Agreement accrues interest at either prime rate or LIBOR plus applicable spreads, resulting in interest rates between 2.07% and 3.50% at June 30, 2009. At June 30, 2009, borrowings outstanding under the Credit Agreement were $43.5 million, including $15.5 million borrowed for acquisitions and growth capital expenditures and $28.0 million borrowed for working capital purposes. The Credit Agreement is guaranteed by each of our wholly-owned domestic subsidiaries.

During each fiscal year beginning October 1, the outstanding balance of the Working Capital Facility must be reduced to $10.0 million or less for a minimum of 30 consecutive days during the period commencing March 1 and ending September 30 of each calendar year. We met this provision of our Credit Agreement in May 2009.

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

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

Interest Rate Risk

We have long-term debt and a revolving line of credit subject to the risk of loss associated with movements in interest rates. At June 30, 2009, we had floating rate obligations totaling approximately $198.1 million including amounts borrowed under our Credit Agreement, the ASC Credit Agreement and interest rate swaps, which convert a portion of our fixed rate senior unsecured notes due 2014 to floating, with aggregate notional amounts of $150 million. The floating rate obligations expose us to the risk of increased interest expense in the event of increases in short-term interest rates.

If the floating rate were to fluctuate by 100 basis points from June 2009 levels, our interest expense would change by a total of approximately $2.0 million per year.

Commodity Price, Market and Credit Risk

Inherent in our contractual portfolio are certain business risks, including market risk and credit risk. Market risk is the risk that the value of the portfolio will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by suppliers, customers or financial counterparties to a contract. We take an active role in managing and controlling market and credit risk and have established control procedures, which are reviewed on an ongoing basis. We monitor market risk through a variety of techniques, including daily reporting of the portfolio’s position to senior management. 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, 2009 and 2008 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, 2009 and September 30, 2008 was assets of $26.5 million and $33.3 million, respectively, and liabilities of $22.8 million and $57.0 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.

All contracts subject to price risk had a maturity of thirty-two months or less, however, the majority of contracts expire within eighteen months.

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 approximately 1.1 million gallons of net unbalanced positions at June 30, 2009.

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, 2009 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, 2009 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

PART II – OTHER INFORMATION

Item 1.

Legal Proceedings

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

Item 1A.

Risk Factors

The Company has identified one 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 30, 2008.

The adoption of Climate Change legislation by Congress could result in increased operating costs and reduced demand for the products and services we provide.

On June 26, 2009, the U.S. House of Representatives approved adoption of the “American Clean Energy and Security Act of 2009,” also known as the “Waxman-Markey cap-and-trade legislation” or “ACESA.” The purpose of ACESA is to control and reduce emissions of “greenhouse gases,” or “GHGs” in the United States. GHGs are certain gases, including carbon dioxide and methane, that may contribute to the warming of the Earth’s atmosphere and other climatic changes. ACESA would establish an economy-wide cap on emissions of GHGs in the United States and would require certain regulated entities to obtain GHG emission “allowances” corresponding to the annual emission of GHGs attributable to their products or operations. Regulated entities under ACESA include producers of NGLs (i.e., natural gas fractionators), local natural gas distribution companies, and certain industrial facilities. Under ACESA, the number of authorized emission allowances would decline each year, resulting in an expected and progressive increase in the cost or value of the allowances. The net effect of maintaining emission allowances under ACESA would be to increase the costs associated with the combusting of carbon-based fuels such as natural gas, NGLs (including propane), and refined petroleum products.

The U.S. Senate has begun work on its own legislation for controlling and reducing domestic GHG emissions, and President Obama has indicated his support of legislation to reduce GHG emissions through an emission allowance system. Although it is not possible at this time to predict if or when the Senate may act on climate change legislation or how any Senate bill would be reconciled with ACESA, any adopted laws or regulations that restrict or reduce GHG emissions could require us to incur increased operating costs and could adversely affect demand for the natural gas and NGL products and services we provide.

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

On October 1, 2008, Inergy issued 309,194 common units to Blu-Gas in a private placement as a portion of the purchase price.

Item 3.

Defaults Upon Senior Securities

None.

Item 4.

Submission of Matters to a Vote of Security Holders

None.

Item 5.

Other Information

None.

Item 6.

Exhibits


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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


	INERGY, L.P.

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

Date: August 4, 2009	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)