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, 2010

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

For the transition period from to .

COMMISSION FILE NUMBER: 0-32453

Inergy, L.P.

(Exact name of registrant as specified in its charter)


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

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

(816) 842-8181

(Registrant’s telephone number, including area code)

(Former name, former address and former fiscal year,

if changed since last report)

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that registrant was required to submit and post such files). Yes x No ¨

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

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

The following units were outstanding at July 30, 2010:

Common units 65,904,536

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, 2010 (unaudited) and September 30, 2009		3
Unaudited Consolidated Statements of Operations for the Three and Nine Months Ended June 30, 2010 and 2009		4
Unaudited Consolidated Statement of Partners’ Capital for the Nine Months Ended June 30, 2010		5
Unaudited Consolidated Statements of Cash Flows for the Nine Months Ended June 30, 2010 and 2009		6
Unaudited Notes to Consolidated Financial Statements		8

Item 2 – Management’s Discussion and Analysis of Financial Condition and Results of Operations		27

Item 3 – Quantitative and Qualitative Disclosures About Market Risk		41

Item 4 – Controls and Procedures		42

Part II – Other Information

Item 1 – Legal Proceedings		43

Item 1A – Risk Factors		43

Item 2 – Unregistered Sales of Equity Securities and Use of Proceeds		43

Item 3 – Defaults Upon Senior Securities		43

Item 4 – Reserved		43

Item 5 – Other Information		43

Item 6 – Exhibits		43

Signature		45

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, 2010			September 30, 2009
	June 30, 2010			September 30, 2009
	*(unaudited)*
Assets
Current assets:
Cash and cash equivalents	$	5.4		$	11.6
Accounts receivable, less allowance for doubtful accounts of $3.6 million and $2.7 million at June 30, 2010 and September 30, 2009, respectively		105.8			94.7
Inventories (Note 3)		89.0			96.5
Assets from price risk management activities		22.7			23.8
Prepaid expenses and other current assets		16.9			20.2

Total current assets		239.8			246.8

Property, plant and equipment (Note 3)		1,720.4			1,555.2
Less: accumulated depreciation		418.4			327.9

Property, plant and equipment, net		1,302.0			1,227.3

Intangible assets (Note 3):
Customer accounts		330.3			277.4
Other intangible assets		153.0			133.0

		483.3			410.4
Less: accumulated amortization		148.6			133.1

Intangible assets, net		334.7			277.3

Goodwill		463.5			374.3
Other assets		5.2			7.4

Total assets	$	2,345.2		$	2,133.1


Liabilities and partners’ capital
Current liabilities:
Accounts payable	$	63.0		$	71.7
Accrued expenses		69.1			74.1
Customer deposits		29.4			60.1
Liabilities from price risk management activities		10.1			29.3
Current portion of long-term debt (Note 8)		8.5			22.0

Total current liabilities		180.1			257.2

Long-term debt, less current portion (Note 8)		1,266.2			1,071.3
Other long-term liabilities		0.9			0.9

Partners’ capital (deficit) (Note 9):
Common unitholders (65,893,536 and 59,807,087 units issued and outstanding as of June 30, 2010 and September 30, 2009, respectively)		898.6			800.0
Non-managing general partner and affiliate		(1.7	)		(0.6	)

Total Inergy, L.P. partners’ capital		896.9			799.4
Interest of non-controlling partners in ASC’s subsidiaries		1.1			4.3

Total partners’ capital		898.0			803.7


Total liabilities and partners’ capital	$	2,345.2		$	2,133.1

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,
	2010			2009			2010			2009
Revenue:
Propane	$	167.8		$	135.5		$	1,091.6		$	988.6
Other		123.8			99.5			392.8			350.5

		291.6			235.0			1,484.4			1,339.1
Cost of product sold (excluding depreciation and amortization as shown below):
Propane		113.3			81.3			733.8			648.1
Other		73.8			56.4			231.2			207.3

		187.1			137.7			965.0			855.4
Gross profit		104.5			97.3			519.4			483.7
Expenses:
Operating and administrative		74.9			66.4			230.2			212.6
Depreciation and amortization		40.5			26.4			117.7			79.3
Loss on disposal of assets		2.1			1.1			5.8			4.1

Operating income (expense)		(13.0	)		3.4			165.7			187.7

Other income (expense):
Interest expense, net		(22.9	)		(17.2	)		(66.9	)		(52.1	)
Other income		0.8			—			0.9			—

Income (loss) before income taxes		(35.1	)		(13.8	)		99.7			135.6

Benefit (provision) for income taxes		0.3			(0.2	)		—			(0.4	)

Net income (loss)		(34.8	)		(14.0	)		99.7			135.2
Net income attributable to non-controlling partners in ASC’s consolidated net income		0.1			0.3			0.7			1.0

Net income (loss) attributable to partners	$	(34.9	)	$	(14.3	)	$	99.0		$	134.2


Partners’ interest information:
Non-managing general partner and affiliate interest in net income	$	17.3		$	12.6		$	51.5		$	37.0

Total limited partners’ interest in net income (loss)	$	(52.2	)	$	(26.9	)	$	47.5		$	97.2


Net income (loss) per limited partner unit (Note 4):
Basic	$	(0.79	)	$	(0.48	)	$	0.75		$	1.84

Diluted	$	(0.79	)	$	(0.48	)	$	0.75		$	1.84


Weighted average limited partners’ units outstanding (in thousands):
Basic		65,880			55,649			63,294			52,740
Dilutive units		—			—			38			25

Diluted		65,880			55,649			63,332			52,765

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			Non- Controlling Partners			Total Partners’ Capital
Balance at September 30, 2009	$	800.0		$	(0.6	)	$	4.3		$	803.7
Net proceeds from the issuance of common units		199.8			—			—			199.8
Net proceeds from common unit options exercised		2.1			—			—			2.1
Unit-based compensation charges		3.6			—			—			3.6
Acquisition of ASC minority interest		(10.8	)		—			(3.4	)		(14.2	)
Distributions		(131.3	)		(49.1	)		(0.6	)		(181.0	)
Comprehensive income:
Net income		50.8			48.1			0.8			99.7
Change in unrealized fair value on cash flow hedges		(15.6	)		(0.1	)		—			(15.7	)

Comprehensive income											84.0

Balance at June 30, 2010	$	898.6		$	(1.7	)	$	1.1		$	898.0

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,
	2010			2009
Operating activities
Net income attributable to partners	$	99.0		$	134.2
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation		94.5			59.4
Amortization		23.2			19.9
Amortization of deferred financing costs and net bond discount		5.4			3.5
Unit-based compensation charges		3.6			2.2
Interest of non-controlling partners in ASC’s consolidated net income		0.7			1.0
Provision for doubtful accounts		2.1			3.2
Loss on disposal of assets		5.8			4.1
Changes in operating assets and liabilities, net of effects from acquisitions:
Accounts receivable		4.9			41.4
Inventories		14.7			21.4
Prepaid expenses and other current assets		4.1			2.7
Other liabilities		(1.5	)		(0.1	)
Accounts payable		(9.6	)		(32.3	)
Accrued expenses		(38.3	)		(5.0	)
Customer deposits		(33.1	)		(47.7	)
Net assets (liabilities) from price risk management activities		(33.9	)		1.3

Net cash provided by operating activities		141.6			209.2

Investing activities
Acquisitions, net of cash acquired		(252.9	)		(12.4	)
Purchases of property, plant and equipment		(71.2	)		(153.7	)
Proceeds from sale of assets		4.8			5.4
Other		—			(0.4	)

Net cash used in investing activities		(319.3	)		(161.1	)

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,
	2010			2009
Financing activities
Proceeds from the issuance of long-term debt	$	784.7		$	717.1
Principal payments on long-term debt		(614.7	)		(721.7	)
Distributions		(180.4	)		(136.8	)
Acquisition of ASC minority interest		(14.2	)		—
Payments for deferred financing costs		(10.4	)		(5.4	)
Net proceeds from issuance of common units		199.8			94.3
Net proceeds from common unit options exercised		2.1			0.8
Proceeds from swap settlement		5.2			—
Distributions paid to non-controlling partners		(0.6	)		(0.7	)

Net cash provided by (used in) financing activities		171.5			(52.4	)

Net decrease in cash		(6.2	)		(4.3	)
Cash at beginning of period		11.6			17.3

Cash at end of period	$	5.4		$	13.0

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	$	6.4		$	4.2

Net change to property, plant and equipment through accounts payable and accrued expenses	$	(7.5	)	$	12.4

Change in the fair value of interest rate swap liability and related long-term debt	$	0.9		$	3.3

Acquisitions, net of cash acquired:
Current assets	$	26.1		$	0.3
Property, plant and equipment		115.2			14.3
Intangible assets, net		74.5			(0.1	)
Goodwill		89.3			5.7
Other assets		0.1			—
Current liabilities		(52.3	)		(1.1	)
Issuance of equity		—			(6.7	)

Total acquisitions, net of cash acquired	$	252.9		$	12.4

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

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Note 1 – Partnership Organization and Basis of Presentation

Organization

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 (“IDRs”) 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 $0.6 million for the three months ended June 30, 2010 and 2009, and $5.3 million and $2.5 million for the nine months ended June 30, 2010 and 2009, respectively, include compensation, bonuses and benefits paid to officers and employees of Inergy GP and its affiliates.

As of June 30, 2010, Holdings owns an aggregate 7.8% 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 0.7% general partnership interest and an approximate 7.1% limited partnership interest.

Nature of Operations

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

Basis of Presentation

The financial information contained herein as of June 30, 2010, and for the three-month and nine-month periods ended June 30, 2010 and 2009, 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, 2010, 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, 2009.

Note 2 – Summary of Significant Accounting Policies

Financial Instruments and Price Risk Management

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

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

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

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 (loss) income was $(4.7) million and $11.0 million at June 30, 2010 and September 30, 2009, respectively. Approximately $(4.1) 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 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 $44.3 million and $32.1 million for the three months ended June 30, 2010 and 2009, respectively, and $133.6 million and $99.3 million for the nine months ended June 30, 2010 and 2009, 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.

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

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. Propane and other liquids inventories being hedged and carried at market value at June 30, 2010 and September 30, 2009, amount to $36.5 million and $53.7 million, respectively. Inventories for midstream operations are stated at the lower of cost or market and are computed predominantly using the average cost method.

Shipping and Handling Costs

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

Property, Plant and Equipment

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


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

Salt deposits are depleted on a unit of production method.

Identifiable Intangible Assets

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

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


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

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

Goodwill

Goodwill is recognized for various acquisitions 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. Goodwill is subject to at least an annual assessment for impairment by applying a fair-value-based test.

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

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

Inergy completed its annual impairment test for each of its reporting units and determined that no impairment existed as of September 30, 2009. No indicators of impairment were identified requiring an interim impairment test during the nine-month period ended June 30, 2010.

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.

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 anti-dilutive for the three months ended June 30, 2010 and 2009, 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 dilutive earnings per unit reflect the same calculation for the three-month periods ended June 30, 2010 and 2009, respectively. Weighted average anti-dilutive unit options outstanding totaled 27,733 and 33,139 for the three months ended June 30, 2010 and 2009, respectively.

Accounting for Unit-Based Compensation

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

The amount of compensation expense recorded by the Company during the nine months ended June 30, 2010 and 2009 was $3.6 million and $2.2 million, respectively. The compensation expense for the nine months ended June 30, 2010 and 2009, includes $1.7 million and $1.0 million of unit-based compensation expense on Inergy Holdings, L.P. units.

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Segment Information

There are certain accounting requirements that establish standards for reporting information about operating segments, as well as related disclosures about products and services, geographic areas and major customers. Further, they define operating segments as components of an enterprise for which separate financial information is available that is evaluated regularly by the chief operating decision maker in deciding how to allocate resources and assessing performance. In determining its reportable segments, Inergy examined the way it organizes its business internally for making operating decisions and assessing business performance. See Note 11 for disclosures related to Inergy’s propane and midstream segments.

Fair Value

Cash and cash equivalents, accounts receivable (net of allowance for doubtful accounts) and payables are carried at cost, which approximates fair value due to their liquid and short-term nature. As of June 30, 2010, the estimated fair value of the fixed-rate Senior Notes, based on available trading information, totaled $1,070.1 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 working capital facility (“Working Capital Facility”) and a $450 million revolving general partnership facility (“General Partnership Facility”). The carrying value at June 30, 2010 of amounts outstanding under the Credit Agreement of $202.0 million approximate fair value due primarily to the floating interest rate associated with the Credit Agreement.

Recently Issued Accounting Pronouncements

FASB Accounting Standards Codification Subtopic 810-10 (“810-10”), originally issued as SFAS No. 160, “Non-controlling Interests in Consolidated Financial Statements—an amendment of ARB No. 51”, was issued in December 2007 and requires that accounting and reporting for minority interests will be recharacterized as non-controlling interests and classified as a component of equity. 810-10 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. 810-10 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. The Company adopted 810-10 on October 1, 2009. The adoption of 810-10 did not have a material impact on the Company’s results of operations or financial position.

FASB Accounting Standards Codification Subtopic 260-10 (“260-10”), originally issued as EITF Issue No. 07-4, “Application of the Two-Class Method under FASB Statement No. 128 to Master Limited Partnerships”, was ratified in March 2008 and 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. 260-10 addresses how the current period earnings of an MLP should be allocated to the general partner, LP’s and, when applicable, IDRs. The Company adopted 260-10 on October 1, 2009, and the impact on its earnings per unit calculation has been retrospectively applied (see Note 4).

FASB Accounting Standards Codification Subtopic 260-10 (“260-10”), originally issued as FSP EITF Issue No. 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions are Participating Securities”, was ratified in June 2008 and applies to the calculation of earnings per share (“EPS”) under FASB Accounting Standards Codification Subtopic 260-10 (“260-10”), originally issued as SFAS 128, “Earnings Per Share”, for share-based payment awards with rights to dividends or dividend equivalents. 260-10 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. The Company adopted 260-10 on October 1, 2009. The adoption of 260-10 did not have a significant impact on the Company’s earnings per unit calculation.

In June 2009, the FASB issued FASB Accounting Standards Codification Subtopic 105-10 (“105-10”), originally issued as SFAS 168, “The FASB Accounting Standards Codification and Hierarchy of Generally Accepted Accounting Principles”, to supersede FASB Statement No. 162, “The Hierarchy of Generally Accepted Accounting Principles”, and reorganize the standards applicable to financial statements of nongovernmental entities that are presented in conformity with GAAP. The purpose of the codification was to provide a single source of authoritative nongovernmental GAAP literature. The codification was not intended to create new accounting standards or guidance. While the codification includes portions of SEC content related to matters within the basic financial statements for user convenience, it does not contain all SEC guidance on accounting topics, and does not replace any SEC rules or regulations. The Company adopted 105-10 on September 30, 2009. The adoption of 105-10 did not impact any amounts comprising the consolidated balance sheets, consolidated statements of operations, consolidated statements of partners’ capital or the consolidated statements of cash flows.

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Note 3 – Certain Balance Sheet Information

Inventories consisted of the following at June 30, 2010 and September 30, 2009, respectively (in millions):


	June 30, 2010		September 30, 2009
Propane gas and other liquids	$	72.1	$	81.3
Appliances, parts, supplies and other		16.9		15.2

Total inventory	$	89.0	$	96.5

Property, plant and equipment consisted of the following at June 30, 2010 and September 30, 2009, respectively (in millions):


	June 30, 2010		September 30, 2009
Tanks and plant equipment	$	1,046.7	$	916.7
Buildings and improvements		379.4		323.6
Vehicles		124.0		107.7
Construction in process		97.4		136.0
Salt deposits		41.6		41.6
Office furniture and equipment		31.3		29.6

		1,720.4		1,555.2
Less: accumulated depreciation		418.4		327.9

Total property, plant and equipment, net	$	1,302.0	$	1,227.3

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. These tanks have a value of $498.5 million with an associated accumulated depreciation balance of $101.7 million at June 30, 2010.

Intangible assets consisted of the following at June 30, 2010 and September 30, 2009, respectively (in millions):


	June 30, 2010		September 30, 2009
Customer accounts	$	330.3	$	277.4
Covenants not to compete		86.7		72.5
Deferred financing and other costs		37.1		34.3
Trademarks		29.2		26.2

		483.3		410.4
Less: accumulated amortization		148.6		133.1

Total intangible assets, net	$	334.7	$	277.3

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Note 4 – Income Per Unit

On October 1, 2009, the Company adopted the provisions of FASB Accounting Standards Codification Subtopic 260-10 (“260-10”), which provides that for master limited partnerships (“MLPs”), current period earnings be reduced by the amount of available cash that will be distributed with respect to that period for purposes of calculating earnings per unit. Any residual amount representing undistributed earnings is assumed to be allocated to the various ownership interests in accordance with the contractual provisions of the partnership agreement. In addition, IDRs, which represent a limited partnership ownership interest, are considered to be participating securities because they have the right to participate in earnings with common equity holders.

Under the Company’s partnership agreement, for any quarterly period, IDRs participate in net income only to the extent of the amount of cash distributions actually declared, thereby excluding the IDRs from participating in undistributed earnings or losses. Accordingly, undistributed net income is assumed to be allocated to the other ownership interests on a pro-rata basis.

The adoption of the provisions of this standard has been retrospectively applied and had the following impact on the earnings per unit for the three-month and nine-month periods ended June 30, 2009:


	Three Months Ended June 30, 2009						Nine Months Ended June 30, 2009
	Basic			Diluted			Basic			Diluted
Original value	$	(0.48	)	$	(0.48	)	$	1.89		$	1.89
Adjustment		—			—			(0.05	)		(0.05	)

Adjusted value	$	(0.48	)	$	(0.48	)	$	1.84		$	1.84

The above adjustment is attributable to the requirement of 260-10 to calculate the general partner’s interest in net income based on the IDRs earned during the period. The IDRs earned for the three month period ended June 30, 2010, will be paid in August 2010. The Company previously calculated the general partner’s interest in net income based on the IDRs paid during the period.

Note 5 – Business Acquisitions

On December 31, 2009, Inergy Propane, LLC entered into an Equity Purchase Agreement with Sterling Capital Partners, L.P., Sterling Capital Partners GmbH & Co. KG and the other parties thereto (collectively, “Sellers”) wherein Inergy Propane, LLC acquired 100% of the capital stock, membership interests, partnership interests, as applicable, of SCP GP Propane Partners I, Inc., SCP LP Propane Partners I, Inc., Liberty Propane GP, LLC, Liberty Propane, LP and Liberty Propane Operations, LLC (collectively, “Liberty”). Liberty is a retail propane company servicing approximately 100,000 customers in the Mid-Atlantic, Northeast and Western regions of the United States.

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

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


	December 31, 2009
Accounts receivable, less allowance for doubtful accounts of $0.5 million	$	15.2
Inventory		6.1
Prepaid expenses and other current assets		0.7
Property, plant and equipment		104.5
Customer accounts		20.0
Covenants not to compete		12.3
Trademarks		3.0

Total identifiable assets acquired		161.8

Current liabilities		15.9
Income tax liability		27.9
Current portion of long-term debt		1.9
Notes payable		6.2

Total liabilities assumed		51.9


Net identifiable assets acquired		109.9
Goodwill		83.4

Net assets acquired	$	193.3

The customer accounts are amortized over a period of 15 years and the covenants not to compete are amortized over a period of approximately 5 years.

The $83.4 million of goodwill has all been assigned to the propane operations segment. The goodwill recognized is attributable primarily to expected synergies and the assembled workforce.

The following represents the pro-forma consolidated statements of operations as if Liberty had been included in the consolidated results of the Company for the three-month period ending June 30, 2009, and the nine-month periods ending June 30, 2010 and 2009, respectively (in millions):


	Pro-Forma Consolidated Statements of Operations
	Three Months Ended June 30,			Nine Months Ended June 30,
	2009			2010		2009
Revenue	$	252.9		$	1,520.6	$	1,444.7
Net income (loss) attributable to partners	$	(16.1	)	$	103.4	$	151.2

These amounts have been calculated after applying the Company’s accounting policies and adjusting the results of Liberty to reflect the depreciation and amortization that would have been charged assuming the preliminary fair value adjustments to property, plant and equipment and intangible assets had been made at the beginning of the respective period.

Revenue and net income generated by Liberty subsequent to the Company’s acquisition on December 31, 2009, amounted to $76.9 million and $9.6 million, respectively.

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

On January 11, 2010, Inergy Midstream, LLC executed a definitive agreement to purchase the Seneca Lake natural gas storage facility (“Seneca Lake”) located in Schuyler County, New York, and two related pipelines. Seneca Lake is an approximate 2.0 billion cubic feet (bcf) underground salt cavern storage facility located on Inergy’s US Salt property outside Watkins Glen, New York, and has a maximum withdrawal capability of 145 MMcf/day and maximum injection capability of 75 MMcf/day. Seneca Lake is connected to the Dominion Transmission System via the 16-inch, 20 mile Seneca West Pipeline and indirectly to the city gate of Binghamton, New York, via the 12-inch, 37.5 mile Seneca East Pipeline, which runs within approximately 4 miles of Inergy’s Stagecoach North Lateral interconnect with the Millennium Pipeline. This transaction is subject to customary closing conditions and regulatory approvals.

On January 12, 2010, Inergy Propane, LLC acquired the propane assets of MGS Corporation (“MGS”), headquartered in Hackensack, New Jersey. MGS currently delivers propane to nearly 6,400 customers from five customer service centers.

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

In January 2010 and April 2010, Inergy acquired an additional 25% and 10% interest in Steuben Gas Storage Company (“Steuben”), respectively. The acquisition of this additional interest increased net income attributable to partners by $0.4 million and $0.7 million in the three-month and nine-month periods ended June 30, 2010, respectively.

Note 6 – Risk Management

The Company is exposed to certain market risks related to its ongoing business operations. These risks include exposure to changing commodity prices as well as fluctuations in interest rates. The Company utilizes derivative instruments to manage its exposure to fluctuations in commodity prices, which is discussed more fully below. The Company also utilizes derivative instruments to manage its exposure to fluctuations in interest rates, which is discussed more fully in Note 8. Additional information related to derivatives is provided in Note 2 and Note 7.

Commodity Derivative Instruments and Price Risk Management

Risk Management Activities

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

Cash Flow Hedging Activity

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

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Fair Value Hedging Activity

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

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

Commodity Price and Credit Risk

Notional Amounts and Terms

The notional amounts and terms of the Company’s derivative financial instruments include the following at June 30, 2010 and September 30, 2009, respectively (in millions):


	June 30, 2010		September 30, 2009
	Fixed Price Payor	Fixed Price Receiver	Fixed Price Payor	Fixed Price Receiver
Propane, crude and heating oil (barrels)	5.7	5.2	6.8	6.5
Natural gas (MMBTU’s)	0.2	—	—	—

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

Fair Value of Derivative Instruments

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


	Amount of Gain (Loss) Recognized in Net Income from Derivatives				Amount of Gain (Loss) Recognized in Net Income on Item Being Hedged
	June 30, 2010				June 30, 2010
	Three Months Ended		Nine Months Ended		Three Months Ended			Nine Months Ended
Derivatives in fair value hedging relationships:
Commodity ^(a)	$	3.2	$	9.2	$	(3.1	)	$	(8.8	)
Debt ^(b)		2.1		1.5		(2.1	)		(1.5	)

Total fair value of derivatives	$	5.3	$	10.7	$	(5.2	)	$	(10.3	)

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)


	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, 2010						June 30, 2010				June 30, 2010
	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)	$	(3.8	)	$	(3.9	)	$	0.5	$	11.8	$	—	$	—


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

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

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

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

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

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, 2010 and September 30, 2009, 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, 2010, is $11.7 million for which the Company has posted collateral of $8.8 million, in the normal course of business. The Company has received collateral of $3.5 million in the normal course of business. All collateral amounts have been netted against the asset or liability with the respective counterparty.

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Note 7 – Fair Value Measurements

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

•

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

•

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

•

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

As of June 30, 2010, 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 include OTC contracts, which are not traded on a public exchange. The fair values of these derivative instruments are determined based on inputs that are readily available in public markets or can be derived from information available in publicly quoted markets. These instruments have been categorized as level 2.

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

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

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

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


	Fair Value of Derivatives
	Level 1		Level 2		Level 3		Total		Designated as Hedges		Not Designated as Hedges		Netting Adjustments ^(a)			Total
Assets
Assets from price risk management	$	0.7	$	24.1	$	2.1	$	26.9	$	4.6	$	22.3	$	(4.2	)	$	22.7
Inventory		—		36.5		—		36.5		—		—		—			36.5
Interest rate swap		—		1.9		—		1.9		1.9		—		—			1.9

Total assets at fair value	$	0.7	$	62.5	$	2.1	$	65.3	$	6.5	$	22.3	$	(4.2	)	$	61.1

Liabilities
Liabilities from price risk management	$	0.9	$	19.4	$	0.7	$	21.0	$	4.6	$	16.4	$	(10.9	)	$	10.1

^(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.

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


	Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
	Nine Months Ended June 30, 2010
Beginning balance	$	(0.2	)
Beginning balance recognized during the period		0.2
Change in value of contracts executed during the period		1.4

Ending balance	$	1.4

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Note 8 – Long-Term Debt

Long-term debt consisted of the following at June 30, 2010 and September 30, 2009, respectively (in millions):


	June 30, 2010			September 30, 2009
Credit agreement	$	202.0		$	27.2
Senior unsecured notes		1,050.0			1,050.0
Fair value hedge adjustment on senior unsecured notes		6.5			5.6
Bond premium		2.9			3.3
Bond discount		(16.9	)		(19.7	)
ASC credit agreement		6.3			8.3
Obligations under noncompetition agreements and notes to former owners of businesses acquired		23.9			18.6

Total debt		1,274.7			1,093.3
Less: current portion		8.5			22.0

Total long-term debt	$	1,266.2		$	1,071.3

On November 24, 2009, Inergy entered into a secured credit facility (“Credit Agreement”) which provides borrowing capacity of up to $525 million in the form of a $450 million revolving general partnership credit facility (“General Partnership Facility”) and a $75 million working capital credit facility (“Working Capital Facility”). This facility replaces its former senior credit facility due 2010. This new facility will mature on November 22, 2013. Borrowings under this new facility are available for working capital needs, future acquisitions, capital expenditures and other general partnership purposes, including the refinancing of existing indebtedness under the former credit facility.

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

•

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

•

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

At June 30, 2010, the balance outstanding under the new Credit Agreement was $202.0 million, including $168.0 million borrowed for acquisitions and growth capital expenditures and $34.0 million borrowed for working capital purposes. At September 30, 2009, the balance outstanding under the previous credit agreement was $27.2 million, with the entire balance borrowed for working capital purposes. The interest rates of these revolvers are based on prime rate and LIBOR plus the applicable spreads, which were 3.35% at June 30, 2010, and between 2.0% and 3.5% at September 30, 2009, for all outstanding debt under the Credit Agreement. Availability under the Credit Agreement amounted to $303.3 million and $381.1 million at June 30, 2010 and September 30, 2009, respectively. Outstanding standby letters of credit under the Credit Agreement amounted to $19.7 million and $16.7 million at June 30, 2010 and September 30, 2009, respectively.

During each fiscal year beginning October 1, the outstanding balance of the Working Capital Facility must be reduced to $10.0 million or less for a minimum of 30 consecutive days during the period commencing March 1 and ending September 30 of each calendar year. Inergy met this requirement on April 30, 2010.

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 portion is based on LIBOR plus the applicable spreads. In July 2010, the Company paid in full the remaining balance on the ASC Credit Agreement.

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Certain counterparties elected to call their respective interest rate swap positions in December 2009 and April 2010. The aggregate notional amount associated with these swaps amounted to $125 million and $25 million, respectively. The Company received $4.3 million and $0.9 million in December 2009 and April 2010, respectively, in consideration for the cancellation of the swaps.

In March 2010, Inergy entered into two interest rates swap agreements scheduled to mature in March 2015. Each is designed to hedge $25 million in underlying fixed rate senior unsecured notes in order to manage interest rate risk exposure. In April 2010, Inergy entered into two additional interest rate swap agreements scheduled to mature in March 2015. The aggregate of these two swaps is designed to hedge $25 million in underlying fixed rate senior unsecured notes in order to manage interest rate risk exposure.

Inergy’s swap agreements, which expire on the same date as the maturity date of the related senior unsecured notes due 2015 and contain call provisions consistent with the underlying senior unsecured notes, require the counterparty to pay Inergy an amount based on the stated fixed interest rate due every six months. In exchange, Inergy is required to make semi-annual floating interest rate payments on the same dates to the counterparty based on an annual interest rate equal to the six-month LIBOR interest rate plus spreads between 5.75% and 5.942% applied to the same aggregate notional amount of $75 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.

At June 30, 2010, the Company was in compliance with the debt covenants in the Credit Agreement and senior unsecured notes.

Note 9 – Partners’ Capital

Common Unit Offering

On January 25, 2010, Inergy issued 5,000,000 common units in a public offering. Inergy also granted the underwriters the option to purchase up to 750,000 additional common units to cover over-allotments. The over-allotment option was exercised on January 28, 2010, for 749,100 common units. Inergy used the net proceeds from this offering to repay outstanding indebtedness under its revolving general partnership credit facility, which was borrowed to fund the acquisitions of Liberty and MGS and to fund other capital expenditures in its midstream business.

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, 2010 and 2009, is presented below:


Nine Months Ended June 30, 2010
Record Date	Payment Date	Per Unit Rate		Distribution Amount *(in millions)*
November 6, 2009	November 13, 2009	$	0.675	$	55.2
February 5, 2010	February 12, 2010	$	0.685		61.9
May 7, 2010	May 14, 2010	$	0.695		63.3

				$	180.4


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

On July 26, 2010, Inergy declared a distribution of $0.705 per limited partner unit to be paid on August 13, 2010, to unitholders of record on August 6, 2010, for a total distribution of $64.6 million with respect to the third fiscal quarter of 2010. On August 14, 2009, a quarterly distribution of $0.665 per limited partner unit was paid to unitholders of record on August 7, 2009, with respect to the third fiscal quarter of 2009, for a total distribution of $50.4 million.

Note 10 – 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, 2010, the total of these firm purchase commitments was $244.2 million of which $234.2 million will occur over the course of the next twelve months with the balance of $10.0 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 primarily related to the North/South Pipeline Compression and Finger Lakes midstream assets. At June 30, 2010, the total of these firm purchase commitments was $16.7 million and the purchases associated with these commitments will occur over the course of the next twelve months.

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

Inergy utilizes third-party insurance subject to varying retention levels of self-insurance, which management considers prudent. Such self-insurance relates to losses and liabilities primarily associated with medical claims, workers’ compensation claims and general, product, vehicle and environmental liability. Losses are accrued based upon management’s estimates of the aggregate liability for claims incurred using certain assumptions followed in the insurance industry and based on past experience. The primary assumption utilized is actuarially determined loss development factors. The loss development factors are based primarily on historical data. Inergy’s self insurance reserves could be affected if future claims development differs from the historical trends. Inergy believes changes in health care costs, trends in health care claims of its employee base, accident frequency and severity and other factors could materially affect the estimate for these liabilities. Inergy continually monitors changes in employee demographics, incident and claim type and evaluates its insurance accruals and adjusts its accruals based on its evaluation of these qualitative data points. At June 30, 2010 and September 30, 2009, Inergy’s self-insurance reserves were $21.2 million and $19.3 million, respectively.

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Note 11 – Segments

Inergy’s financial statements reflect two operating and reportable segments: propane operations and midstream operations. Inergy’s propane operations include propane sales to end users, the sale of propane-related appliances and service work for propane-related equipment, the sale of distillate products and wholesale distribution of propane and marketing and price risk management services to other users, retailers and resellers of propane. Inergy’s midstream operations include storage 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 Liberty and MGS 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, 2010
	Propane Operations		Midstream Operations		Intersegment Operations			Corporate Assets		Total
Retail propane revenues	$	104.3	$	—	$	—		$	—	$	104.3
Wholesale propane revenues		57.5		6.0		—			—		63.5
Storage, fractionation and other midstream revenues		—		82.6		(0.2	)		—		82.4
Transportation revenues		5.0		3.1		—			—		8.1
Propane-related appliance sales revenues		4.9		—		—			—		4.9
Retail service revenues		3.9		—		—			—		3.9
Rental service and other revenues		6.4		—		—			—		6.4
Distillate revenues		18.1		—		—			—		18.1
Gross profit		71.5		33.2		(0.2	)		—		104.5
Identifiable assets		141.5		53.3		—			—		194.8
Goodwill		367.1		96.4		—			—		463.5
Property, plant and equipment		809.9		898.9		—			11.6		1,720.4
Additions to property, plant and equipment		3.6		8.4		—			0.7		12.7

	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
Additions to property, plant and equipment		2.8		62.0		—			0.1		64.9

INERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)


	Nine Months Ended June 30, 2010
	Propane Operations		Midstream Operations		Intersegment Operations			Corporate Assets		Total
Retail propane revenues	$	697.1	$	—	$	—		$	—	$	697.1
Wholesale propane revenues		372.5		22.1		(0.1	)		—		394.5
Storage, fractionation and other midstream revenues		—		218.7		(0.9	)		—		217.8
Transportation revenues		13.7		13.3		—			—		27.0
Propane-related appliance sales revenues		17.2		—		—			—		17.2
Retail service revenues		13.2		—		—			—		13.2
Rental service and other revenues		20.6		—		—			—		20.6
Distillate revenues		97.0		—		—			—		97.0
Gross profit		423.4		96.9		(0.9	)		—		519.4
Identifiable assets		141.5		53.3		—			—		194.8
Goodwill		367.1		96.4		—			—		463.5
Property, plant and equipment		809.9		898.9		—			11.6		1,720.4
Additions to property, plant and equipment		10.7		51.9		—			1.1		63.7

	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
Additions to property, plant and equipment		8.9		156.5		—			0.7		166.1

Note 12 – Subsequent Events

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

In July 2010, the Company paid in full the remaining balance on the ASC Credit Agreement.

In July 2010, the Company purchased an additional 10% interest in Steuben. This acquisition gives the Company 100% ownership of Steuben.

On August 9, 2010, Inergy and Holdings entered into an Agreement and Plan of Merger (the “Merger Agreement”). Pursuant to the terms of the Merger Agreement and the other transactions contemplated thereby, (a) the incentive distribution rights in Inergy owned by Holdings will be transformed into Inergy common units, (b) Holdings will contribute to Inergy all of Holdings’ ownership interests in two of its wholly owned subsidiaries (including Inergy’s non-managing general partner) in exchange for Inergy common units (the “Holdings Subsidiary Contribution”), and concurrent with the Holdings Subsidiary Contribution, Inergy common units owned by such entities will be converted into Class A Units, and (c) a wholly owned subsidiary of Holdings’ general partner will merge with and into Holdings, with Holdings surviving (the “Merger”), such that following the Merger, the public ownership of Holdings will cease to exist and Holdings GP will remain as the sole general partner of Holdings. Subject to the terms and conditions of the Merger Agreement, which was unanimously approved by the boards of directors of Inergy GP and the general partner of Holdings, if the merger is completed, each outstanding Holdings common unit held by public unitholders will be converted into the right to receive 0.770 Inergy common units.

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, 2009.

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 three natural gas storage facilities (“Stagecoach”, “Thomas Corners” and “Steuben”), a liquefied petroleum gas (“LPG”) storage facility (“Finger Lakes LPG”), a natural gas liquids (“NGL”) business and a solution-mining and salt production company (“US Salt”). We further intend to pursue our growth objectives in the propane 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. Since the inception of our predecessor in November 1996 through June 30, 2010, we have acquired 86 companies, including 80 retail propane companies and 6 midstream businesses, for an aggregate purchase price of approximately $2.1 billion, including working capital, assumed liabilities and acquisition costs.

On December 31, 2009, we acquired the partnership interests of Liberty Propane, LP (“Liberty”) headquartered in Overland Park, Kansas. Liberty delivers propane to nearly 100,000 customers from 38 customer service centers in the Northeast, Mid-Atlantic and Western regions of the United States. On January 12, 2010, we acquired the propane assets of MGS Corporation (“MGS”), headquartered in Hackensack, New Jersey. MGS currently delivers propane to nearly 6,400 customers from five customer service centers. The purchase price allocations for these acquisitions have been prepared on a preliminary basis pending final asset valuation and asset rationalization, and changes are expected when additional information becomes available. Changes to final asset valuation of prior fiscal year acquisitions have been included in our consolidated financial statements but are not material.

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

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

The retail propane business is a “margin-based” business where the level of profitability is largely dependent on the difference between sales prices and product costs. Propane prices continued to be volatile during 2010. At the main pricing hub of Mount Belvieu Texas during the nine-month period ended June 30, 2010, propane prices ranged from a low of $0.93 per gallon to a high of $1.44 per gallon and a price of $0.99 per gallon at June 30, 2010. Our ability to pass on price increases to our customers and our hedging program limits the impact that such volatility has had on our results from 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. Propane is a by-product of both crude oil refining and natural gas processing and thus typically follows the same pricing pattern as these two commodities with crude oil pricing being the more influential of the two historically. The prices of crude oil and natural gas had maintained historically high costs in calendar years 2007 and 2008 before both began to fall rather dramatically in late 2008 and throughout the 2008-2009 winter season. While natural gas pricing has remained at historically low levels since this decline, crude oil costs leveled off in the spring of 2009 before beginning another increase that persisted through the 2009-2010 winter season with propane prices following a similar pattern for the majority of this time. As such, our selling prices of propane have been at higher levels in order to attempt to maintain our historical gross margin per gallon. 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 economic downturn. In addition, although we believe the economic downturn has not currently had a material impact on our cash collections, it is possible that a prolonged economic downturn could have a negative impact on our future cash collections.

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

•

forward contracts involving the physical delivery of propane;

•

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

•

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

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

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

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 and conversion from petroleum based fuels. 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 Finger Lakes LPG storage expansion. 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 spring 2011.

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, 2010, of $16.7 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.

Recent Developments

Results of Operations

Three Months Ended June 30, 2010 Compared to Three Months Ended June 30, 2009

The following table summarizes the consolidated statement of operations components for the three months ended June 30, 2010 and 2009, respectively (in millions):


	Three Months Ended June 30,						Change
	2010			2009			In Dollars			Percentage
Revenue	$	291.6		$	235.0		$	56.6		24.1	%
Cost of product sold		187.1			137.7			49.4		35.9

Gross profit		104.5			97.3			7.2		7.4
Operating and administrative expenses		74.9			66.4			8.5		12.8
Depreciation and amortization		40.5			26.4			14.1		53.4
Loss on disposal of assets		2.1			1.1			1.0		90.9

Operating income (expense)		(13.0	)		3.4			(16.4	)	(482.4	)
Interest expense, net		(22.9	)		(17.2	)		(5.7	)	(33.1	)
Other income		0.8			—			0.8		*

Loss before income taxes		(35.1	)		(13.8	)		(21.3	)	(154.3	)
Benefit (provision) for income taxes		0.3			(0.2	)		0.5		250.0

Net loss		(34.8	)		(14.0	)		(20.8	)	(148.6	)
Net income attributable to non-controlling partners in ASC’s consolidated net income		0.1			0.3			(0.2	)	(66.7	)

Net loss attributable to partners	$	(34.9	)	$	(14.3	)	$	(20.6	)	(144.1	)%

*	Not meaningful

The following table summarizes revenues, including associated volume of gallons sold, for the three months ended June 30, 2010 and 2009, respectively (in millions):


	Revenues								Gallons
	Three Months Ended June 30,				Change				Three Months Ended June 30,		Change
	2010		2009		In Dollars		Percent		2010	2009	In Units		Percent
Retail propane	$	104.3	$	87.5	$	16.8	19.2	%	45.0	41.9	3.1		7.4	%
Wholesale propane		63.5		48.0		15.5	32.3		57.1	60.7	(3.6	)	(5.9	)
Other retail		38.3		36.9		1.4	3.8		—	—	—		—
Storage, fractionation and midstream		85.5		62.6		22.9	36.6		—	—	—		—

Total	$	291.6	$	235.0	$	56.6	24.1	%	102.1	102.6	(0.5	)	(0.5	)%

Volume. During the three months ended June 30, 2010, we sold 45.0 million retail gallons of propane, an increase of 3.1 million gallons or 7.4% from the 41.9 million retail gallons sold during the same three-month period in 2009. Gallons sold during the three months ended June 30, 2010 increased as compared to the same prior year period as a result of acquisition-related volume of 10.9 million gallons partially offset by lower volumes sold at our existing locations of 7.8 million gallons. The primary cause of the declining volumes at existing locations was (1) continued customer conservation, which we believe has resulted from the overall weak United States economic environment and to a lesser extent the lingering effects of higher propane costs, which have been at record high prices the past several years, (2) an abrupt end to the 2009/2010 winter heating season whereby the weather for our areas of operations was 24% warmer than last year’s period and 26% warmer than normal and (3) volume declines from net customer losses, including low margin and less profitable customers.

Wholesale gallons delivered decreased 3.6 million gallons, or 5.9%, to 57.1 million gallons in the three months ended June 30, 2010, from 60.7 million gallons in the three months ended June 30, 2009. The decrease was due primarily to lower demand and volumes sold to existing customers.

The total natural gas liquid gallons sold or processed by our West Coast NGL operations increased 10.9 million gallons, or 14.6%, to 85.7 million gallons during the three months ended June 30, 2010, from 74.8 million gallons during the same three-month period in 2009. This increase was primarily attributable to the Butamer addition in July 2009, and new terminalling contracts.

During the three months ended June 30, 2010 and 2009, our Northeast natural gas and LPG storage facilities were 100% contracted.

Revenues. Revenues for the three months ended June 30, 2010, were $291.6 million, an increase of $56.6 million, or 24.1%, from $235.0 million during the same three-month period in 2009.

Revenues from retail propane sales were $104.3 million for the three months ended June 30, 2010, compared to $87.5 million during the same three-month period in 2009. This $16.8 million, or 19.2%, increase was due to acquisition-related sales and a higher overall average selling price of propane, which resulted in higher retail propane revenues of $24.0 million and $9.0 million, respectively. The overall average selling price of propane increased due to an increase in the wholesale cost of propane. These factors were partially offset by a $16.2 million revenue decline arising from a decrease in gallons sold to existing customers as described above.

Revenues from wholesale propane sales were $63.5 million in the three months ended June 30, 2010, an increase of $15.5 million or 32.3%, from $48.0 million in the three months ended June 30, 2009. This increase resulted from the higher average sales price of propane which contributed $18.3 million to the increase in revenue, partially offset by $2.8 million due to lower volumes sold to existing and new customers.

Revenues from other retail sales, which primarily includes distillates, service, rental, appliance sales and transportation services, were $38.3 million for the three months ended June 30, 2010, an increase of $1.4 million, or 3.8%, from $36.9 million during the same three-month period in 2009. Revenue from other retail sales increased mostly as a result of acquisition related-sales of $2.6 million partially offset by a $1.2 million decline in distillate revenues at existing locations. Distillate revenues from existing locations declined as a result of lower volume sold, partially offset by an increase in the comparable average selling price of distillates resulting from a higher wholesale cost.

Revenues from storage, fractionation and other midstream activities were $85.5 million for the three months ended June 30, 2010, an increase of $22.9 million or 36.6% from $62.6 million during the same three-month period in 2009. Revenues from our West Coast NGL operations increased $19.5 million primarily as a result of increased commodity sales and processing fees associated with the Butamer addition. Higher average selling prices of natural gas liquids also contributed to the revenue increase. Additionally, the in-servicing of our Thomas Corners facility and the related firm storage contracts resulted in an increase of $3.1 million.

Cost of Product Sold. Cost of product sold for the three months ended June 30, 2010, was $187.1 million, an increase of $49.4 million, or 35.9%, from $137.7 million during the same three-month period in 2009.

Retail propane cost of product sold was $56.5 million for the three months ended June 30, 2010, an increase of $18.6 million, or 49.1%, when compared to $37.9 million for the same three-month period in 2009. This higher retail cost of product sold was driven by a $13.7 increase associated with acquisition-related sales and an $11.5 million increase arising from a higher average per gallon cost of propane. Also contributing to a higher cost of product sold was a $0.4 million increase due to changes in non-cash charges on derivative contracts associated with retail propane fixed price sales contracts. These factors were partially offset by a $7.0 million decline in cost of product sold resulting from lower volume sales at our existing locations as discussed above.

Wholesale propane cost of product sold in the three months ended June 30, 2010, was $56.8 million, an increase of $13.4 million or 30.9%, from wholesale cost of product sold of $43.4 million in the three months ended June 30, 2009. This increase resulted from the higher average purchase price of propane which contributed to $15.9 million of the increase, partially offset by $2.5 million due to the lower volumes sold to existing and new customers.

Other retail cost of product sold was $21.1 million for the three months ended June 30, 2010, compared to $19.6 million during the same three-month period in 2009. This $1.5 million, or 7.7%, increase was primarily due to a $1.2 million increase in the cost of product sold associated with acquisition-related sales and a $0.3 million increase in the cost for distillates. The increase in the cost of product sold for distillates was driven by a $2.9 million increase due to a higher overall commodity cost, mostly offset by a $2.6 million decline due to lower volumes sold at existing locations.

Storage, fractionation and other midstream cost of product sold was $52.7 million for the three months ended June 30, 2010, an increase of $15.9 million, or 43.2%, from $36.8 million during the same three-month period in 2009. Costs from our West Coast NGL operations were $16.8 million higher primarily as a result of increased commodity sales associated with the Butamer addition. Increases in the cost of natural gas liquids also contributed to the West Coast cost of products sold increase. This increase was partially offset by lower costs attributable to operational efficiencies at our US Salt, Finger Lakes LPG and Steuben facilities.

Our retail and wholesale cost of product sold consists primarily of tangible products sold including all propane, distillates and other natural gas liquids sold and all propane-related appliances sold. Other costs incurred in conjunction with the distribution of these products are included in operating and administrative expenses and consist primarily of wages to delivery personnel, delivery vehicle costs consisting of fuel costs, repair and maintenance and lease expense. Costs associated with delivery vehicles approximated $16.6 million and $14.4 million for the three months ended June 30, 2010 and 2009, respectively. In addition, the depreciation expense associated with the delivery vehicles and customer tanks is reported within depreciation and amortization expense and amounted to $8.3 million and $9.1 million for the three months ended June 30, 2010 and 2009, 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 $18.7 million and $7.7 million for the three months ended June 30, 2010 and 2009, respectively. Vehicle costs and wages for personnel directly involved in providing midstream services amounted to $0.7 million and $0.9 million for the three months ended June 30, 2010 and 2009, respectively. Since we include these costs in our operating and administrative expense and depreciation and amortization expense rather than in cost of product sold, our results may not be comparable to other entities in our lines of business if they include these costs in cost of product sold.

Gross Profit. Gross profit for the three months ended June 30, 2010, was $104.5 million, an increase of $7.2 million, or 7.4%, from $97.3 million during the same three-month period in 2009.

Retail propane gross profit was $47.8 million for the three months ended June 30, 2010, compared to $49.6 million in the same three-month period in 2009. This $1.8 million, or 3.6%, decline was mostly attributable to lower retail gallon sales at existing locations as discussed above coupled with a slightly lower cash margin per gallon, which resulted in a $9.2 million and $2.5 million reduction in retail propane gross profit, respectively. The lower cash margin per gallon in the current period is primarily attributable to the higher overall average cost of propane compared to the prior year period. In addition, we tend to earn a higher margin per gallon in periods of declining propane costs and the cost of propane declined at a greater rate in last year’s period as compared to this year’s period. Gross profit also decreased by $0.4 million related to changes in non-cash charges on derivative contracts associated with retail propane fixed price sales contracts as discussed above. These declines in retail propane gross profit were partially offset by a $10.3 million increase associated with acquisitions.

Wholesale propane gross profit was $6.7 million in the three months ended June 30, 2010, compared to $4.6 million in the three months ended June 30, 2009, an increase of $2.1 million or 45.7%. The increase in gross profit was primarily the result of the favorable market conditions in which higher sales prices and margins were able to be achieved which contributed $2.4 million to the increase, partially offset by $0.3 million due to the lower volumes sold to existing and new customers.

Other retail gross profit was $17.2 million for the three months ended June 30, 2010, compared to $17.3 million for the same three-month period in 2009. This $0.1 million, or 0.6%, decrease was due primarily to lower gross profit on distillates of $1.5 million, partially offset by a $1.4 million increase in gross profit from acquisitions.

Storage, fractionation and other midstream gross profit was $32.8 million in the three months ended June 30, 2010, compared to $25.8 million in the same three-month period in 2009, an increase of $7.0 million, or 27.1%. This increase is primarily attributable to additional West Coast NGL contracts due to the Butamer addition in July 2009 and margin improvements as a result of changes in the variety of natural gas liquids sold, resulting in a $2.7 million increase. The remaining increase was attributable to operational efficiencies at our US Salt and Finger Lakes LPG facilities, our Thomas Corners facility being placed in service and the related firm storage contracts as well as a price increase at Finger Lakes LPG.

Operating and Administrative Expenses. Operating and administrative expenses were $74.9 million for the three months ended June 30, 2010, compared to $66.4 million in the same three-month period in 2009, an increase of $8.5 million or 12.8%. Operating expenses increased $9.4 million from the operations of the acquisitions in addition to $1.4 million of transaction expenses primarily from those acquisitions. Offsetting these increases were lower personnel costs from existing operations which decreased $2.2 million.

Depreciation and Amortization. Depreciation and amortization was $40.5 million for the three months ended June 30, 2010, compared to $26.4 million during the same three-month period in 2009. This $14.1 million, or 53.4%, increase resulted primarily from the expansion projects completed in our midstream segment and acquisitions.

Interest Expense. Interest expense was $22.9 million for the three months ended June 30, 2010, compared to $17.2 million during the same three-month period in 2009. This $5.7 million, or 33.1%, increase was due to both an increase in the average interest rate incurred on our borrowings and an increase in the average outstanding borrowings during the period. Additionally, during the three months ended June 30, 2010 and 2009, we capitalized $1.5 million and $5.1 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 Loss Attributable to Partners. Net loss was $(34.9) million for the three months ended June 30, 2010, compared to a net loss of $(14.3) million for the same three-month period in 2009. The $20.6 million, or 144.1%, increase in net loss was primarily attributable to increased depreciation and amortization, operating and administrative expenses and interest expense in the 2010 period, partially offset by a higher gross profit.

EBITDA and Adjusted EBITDA. The following table summarizes EBITDA and Adjusted EBITDA for the three months ended June 30, 2010 and 2009, respectively (in millions):


	Three Months Ended June 30,
	2010			2009
EBITDA:
Net loss attributable to partners	$	(34.9	)	$	(14.3	)
Interest of non-controlling partners in ASC’s consolidated ITDA ^(a)		—			(0.1	)
Interest expense, net		22.9			17.2
(Benefit) provision for income taxes		(0.3	)		0.2
Depreciation and amortization		40.5			26.4

EBITDA		28.2			29.4

Non-cash loss on derivative contracts		0.4			—
Long-term incentive and equity compensation expense		1.4			0.8
Loss on disposal of assets		2.1			1.1
Transaction costs		1.4			—

Adjusted EBITDA	$	33.5		$	31.3

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


	Three Months Ended June 30,
	2010			2009
EBITDA:
Net cash provided by operating activities	$	1.3		$	67.6
Net changes in working capital balances		12.0			(49.2	)
Provision for doubtful accounts		(2.4	)		(2.4	)
Amortization of deferred financing costs and net bond discount		(1.7	)		(1.7	)
Unit-based compensation charges		(1.4	)		(0.8	)
Loss on disposal of assets		(2.1	)		(1.1	)
Interest of non-controlling partners in ASC’s consolidated EBITDA		(0.1	)		(0.4	)
Interest expense, net		22.9			17.2
(Benefit) provision for income taxes		(0.3	)		0.2

EBITDA		28.2			29.4

Non-cash loss on derivative contracts		0.4			—
Long-term incentive and equity compensation expense		1.4			0.8
Loss on disposal of assets		2.1			1.1
Transaction costs		1.4			—

Adjusted EBITDA	$	33.5		$	31.3

EBITDA is defined as income (loss) before income taxes, plus net interest expense and depreciation and amortization expense. For the three months ended June 30, 2010 and 2009, EBITDA was $28.2 million and $29.4 million, respectively. As indicated in the table, Adjusted EBITDA represents EBITDA excluding the gain or loss on derivative contracts associated with retail propane fixed price sales contracts, the gain or loss on the disposal of assets, long-term incentive and equity compensation expenses and transaction costs. Transaction costs are third party professional fees and other costs that are incurred in conjunction with closing a transaction. Adjusted EBITDA was $33.5 million for the three months ended June 30, 2010, compared to $31.3 million in the same three-month period in 2009. EBITDA and Adjusted EBITDA should not be considered an alternative to net income, income before income taxes, cash flows from operating activities, or any other measure of financial performance calculated in accordance with generally accepted accounting principles as those items are used to measure operating performance, liquidity or the ability to service debt obligations. We believe that EBITDA provides additional information for evaluating our ability to make the minimum quarterly distribution and is presented solely as a supplemental measure. We believe that Adjusted EBITDA provides additional information for evaluating our financial performance without regard to our financing methods, capital structure and historical cost basis. EBITDA and Adjusted EBITDA, as we define them, may not be comparable to EBITDA and Adjusted EBITDA or similarly titled measures used by other corporations or partnerships.

Nine Months Ended June 30, 2010 Compared to Nine Months Ended June 30, 2009

The following table summarizes the consolidated statement of operations components for the nine months ended June 30, 2010 and 2009, respectively (in millions):


	Nine Months Ended June 30,						Change
	2010			2009			In Dollars			Percentage
Revenue	$	1,484.4		$	1,339.1		$	145.3		10.9	%
Cost of product sold		965.0			855.4			109.6		12.8

Gross profit		519.4			483.7			35.7		7.4
Operating and administrative expenses		230.2			212.6			17.6		8.3
Depreciation and amortization		117.7			79.3			38.4		48.4
Loss on disposal of assets		5.8			4.1			1.7		41.5

Operating income		165.7			187.7			(22.0	)	(11.7	)
Interest expense, net		(66.9	)		(52.1	)		(14.8	)	(28.4	)
Other income		0.9			—			0.9		*

Income before income taxes		99.7			135.6			(35.9	)	(26.5	)
Provision for income taxes		—			0.4			(0.4	)	(100.0	)

Net income		99.7			135.2			(35.5	)	(26.3	)
Net income attributable to non-controlling partners in ASC’s consolidated net income		0.7			1.0			(0.3	)	(30.0	)

Net income attributable to partners	$	99.0		$	134.2		$	(35.2	)	(26.2	)%

*	Not meaningful

The following table summarizes revenues, including associated volume of gallons sold, for the nine months ended June 30, 2010 and 2009, respectively (in millions):


	Revenues									Gallons
	Nine Months Ended June 30,				Change					Nine Months Ended June 30,		Change
	2010		2009		In Dollars			Percent		2010	2009	In Units	Percent
Retail propane	$	697.1	$	659.3	$	37.8		5.7	%	294.7	271.0	23.7	8.7	%
Wholesale propane		394.5		329.3		65.2		19.8		341.3	310.6	30.7	9.9
Other retail		161.7		179.0		(17.3	)	(9.7	)	—	—	—	—
Storage, fractionation and midstream		231.1		171.5		59.6		34.8		—	—	—	—

Total	$	1,484.4	$	1,339.1	$	145.3		10.9	%	636.0	581.6	54.4	9.4	%

Volume. During the nine months ended June 30, 2010, we sold 294.7 million retail gallons of propane, an increase of 23.7 million gallons or 8.7% from the 271.0 million retail gallons sold during the same nine-month period in 2009. Gallons sold during the nine months ended June 30, 2010, increased as compared to the same prior year period as a result of acquisition-related volume of 39.4 million gallons partially offset by a 15.7 million gallon decline from lower volumes sold at our existing locations. The primary cause of the declining volumes at existing locations was (1) continued customer conservation, which we believe has resulted from the overall weak United States economic environment and to a lesser extent the lingering effects of higher propane costs, which have been at record high prices the past several years, (2) an abrupt end to the 2009/2010 winter heating season and (3) volume declines from net customer losses, including low margin and less profitable customers. Also impacting volumes sold during the nine months ended June 30, 2010, compared to the same prior year period was the weather in certain areas of our operations. Based on our calculations using degree day data provided by NOAA, the Southern and Southeast areas of the United States were significantly colder than the prior year period; however gallon gains realized in these areas were somewhat offset by degree day losses in the Eastern and certain Northern parts of our areas of operations.

Wholesale gallons delivered increased 30.7 million gallons, or 9.9%, to 341.3 million gallons in the nine months ended June 30, 2010, from 310.6 million gallons in the nine months ended June 30, 2009. The increase was due primarily to greater volumes sold to existing customers and the addition of new customers.

The total natural gas liquid gallons sold or processed by our West Coast NGL operations increased 64.0 million gallons, or 31.8%, to 265.0 million gallons during the nine months ended June 30, 2010, from 201.0 million gallons during the same nine-month period in 2009. This increase was primarily attributable to the Butamer addition in July 2009 and new terminalling contracts.

During the nine months ended June 30, 2010 and 2009, our Northeast natural gas and LPG storage facilities were 100% contracted.

Revenues. Revenues for the nine months ended June 30, 2010, were $1,484.4 million, an increase of $145.3 million, or 10.9%, from $1,339.1 million during the same nine-month period in 2009.

Revenues from retail propane sales were $697.1 million for the nine months ended June 30, 2010, compared to $659.3 million during the same nine-month period in 2009. This $37.8 million, or 5.7%, increase was primarily due to acquisition-related sales, which resulted in higher retail propane revenues of $95.5 million, partially offset by a combination of a lower overall average retail selling price of propane on a year to date basis as a result of a lower cost of propane and a decline in gallons sold to existing customers as described above, which contributed a revenue decline of $19.5 million and $38.2 million, respectively.

Revenues from wholesale propane sales were $394.5 million in the nine months ended June 30, 2010, an increase of $65.2 million or 19.8%, from $329.3 million in the nine months ended June 30, 2009. This increase resulted from the greater volumes of propane sold which contributed $32.5 million to the increase in revenues and the higher average wholesale sales price of propane which contributed to $32.7 million of the increase as a result of higher product costs.

Revenues from other retail sales, which primarily includes distillates, service, rental, appliance sales and transportation services, were $161.7 million for the nine months ended June 30, 2010, a decrease of $17.3 million, or 9.7%, from $179.0 million during the same nine-month period in 2009. Revenue from other retail sales declined as a result of lower distillate revenues at existing locations of $18.8 million and a $5.4 million decline in revenues from other products and services, partially offset by a $6.9 million increase from acquisition-related sales. Distillate revenues from existing locations decreased primarily as a result of lower volumes sold.

Revenues from storage, fractionation and other midstream activities were $231.1 million for the nine months ended June 30, 2010, an increase of $59.6 million or 34.8% from $171.5 million during the same nine-month period in 2009. Revenues from our West Coast NGL operations increased $52.3 million primarily as a result of increased commodity sales and processing fees associated with the Butamer addition. Higher average selling prices of natural gas liquids also contributed to the revenue increase. Revenues resulting from the in-servicing of our Thomas Corners facility and the related firm storage contracts resulted in an increase of $3.5 million. Additionally, revenues from our US Salt operations increased $3.1 million due to price increases and product mix management.

Cost of Product Sold. Cost of product sold for the nine months ended June 30, 2010, was $965.0 million, an increase of $109.6 million, or 12.8%, from $855.4 million during the same nine-month period in 2009.

Retail propane cost of product sold was $359.8 million for the nine months ended June 30, 2010, compared to $337.7 million for the same nine-month period in 2009. This $22.1 million, or 6.5%, increase was primarily due to a $55.4 million increase associated with acquisition-related volume, partially offset by a reduction of retail propane cost of product sold from existing locations of $31.1 million. The decline in retail propane cost of product sold from existing locations resulted from lower volume sales as discussed above coupled with a decline in the average per gallon cost of retail propane, which reduced costs by $19.5 million and $11.6 million, respectively. Also contributing to the decline in retail propane cost of product sold was a $2.2 million decrease due to changes in non-cash charges on derivative contracts associated with retail propane fixed price sales contracts.

Wholesale propane cost of product sold in the nine months ended June 30, 2010, was $374.0 million, an increase of $63.6 million or 20.5%, from wholesale cost of product sold of $310.4 million in the nine months ended June 30, 2009. This increase resulted from the greater volumes of propane purchased which contributed $30.7 million to the increase in cost and the higher average purchase price of wholesale propane sold which contributed $32.9 million of the increase as a result of higher commodity prices.

Other retail cost of product sold was $95.4 million for the nine months ended June 30, 2010, compared to $108.6 million during the same nine-month period in 2009. This $13.2 million, or 12.2%, decrease was primarily due to lower costs from distillate sales at existing locations of $15.5 million and a decline in costs for other products and services of $0.9 million, partially offset by a $3.2 million increase in the cost of product sold associated with acquisition-related sales. The cost of product sold for distillates declined primarily as a result of lower volumes sold at existing locations.

Storage, fractionation and other midstream cost of product sold was $135.8 million for the nine months ended June 30, 2010, an increase of $37.1 million, or 37.6%, from $98.7 million during the same nine-month period in 2009. Costs from our West Coast NGL operations were $41.5 million higher primarily as a result of increased commodity sales associated with the Butamer addition. Increases in the cost of natural gas liquids also contributed to the West Coast cost of products sold increase. This increase was partially offset by lower costs of storage and operational efficiencies at our Stagecoach, US Salt and Finger Lakes LPG facilities.

Our retail and wholesale cost of product sold consists primarily of tangible products sold including all propane, distillates and other natural gas liquids sold and all propane-related appliances sold. Other costs incurred in conjunction with the distribution of these products are included in operating and administrative expenses and consist primarily of wages to delivery personnel, delivery vehicle costs consisting of fuel costs, repair and maintenance and lease expense. Costs associated with delivery vehicles approximated $51.9 million and $48.5 million for the nine months ended June 30, 2010 and 2009, respectively. In addition, the depreciation expense associated with the delivery vehicles and customer tanks is reported within depreciation and amortization expense and amounted to $24.5 million and $25.5 million for the nine months ended June 30, 2010 and 2009, 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 $55.1 million and $22.9 million for the nine months ended June 30, 2010 and 2009, respectively. Vehicle costs and wages for personnel directly involved in providing midstream services amounted to $2.1 million and $2.4 million for the nine months ended June 30, 2010 and 2009, 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, 2010, was $519.4 million, an increase of $35.7 million, or 7.4%, from $483.7 million during the same nine-month period in 2009.

Retail propane gross profit was $337.3 million for the nine months ended June 30, 2010, compared to $321.6 million in the same nine-month period in 2009. This $15.7 million, or 4.9%, increase in retail propane gross profit was attributable to a $40.1 million increase from acquisitions and a $2.2 million increase related to changes in non-cash charges on derivative contracts associated with retail propane fixed price sales contracts as discussed above. These factors, which increased retail propane gross profit, were partially offset by an $18.7 million decline resulting from lower retail gallon sales at existing locations as discussed above and a $7.9 million decline arising from a lower cash margin per gallon. The decline in cash margin per gallon was primarily the result of a steep escalation in propane costs during the winter heating season contrasted with a period of falling propane costs in the prior year winter.

Wholesale propane gross profit was $20.5 million in the nine months ended June 30, 2010, compared to $18.9 million in the nine months ended June 30, 2009, an increase of $1.6 million or 8.5%. The increase in gross profit was primarily the result of greater volumes sold to existing customers and the addition of new customers.

Other retail gross profit was $66.3 million for the nine months ended June 30, 2010, compared to $70.4 million for the same nine-month period in 2009. This $4.1 million, or 5.8%, decrease was due primarily to lower gross profit on other products and services and distillates of $4.5 million and $3.3 million, respectively, partially offset by a $3.7 million increase in gross profit from acquisitions.

Storage, fractionation and other midstream gross profit was $95.3 million in the nine months ended June 30, 2010, compared to $72.8 million in the same nine-month period in 2009, an increase of $22.5 million, or 30.9%. This increase is primarily attributable to additional West Coast NGL contracts due to the Butamer addition in July 2009 and margin improvements as a result of changes in the variety of natural gas liquids sold, resulting in a $10.8 million increase. The remaining increase was attributable to operational efficiencies at our US Salt and Stagecoach facilities, our Thomas Corners facility being placed in service and the beginning of the relating firm storage contracts and a price increase at Finger Lakes LPG.

Operating and Administrative Expenses. Operating and administrative expenses were $230.2 million for the nine months ended June 30, 2010, compared to $212.6 million in the same nine-month period in 2009. This $17.6 million, or 8.3%, increase in operating expenses was due primarily to operations of acquisitions of $21.5 million in addition to $2.5 million of transaction expenses primarily from those acquisitions. Partially offsetting these increases were lower operating expenses from existing operations including $7.1 million lesser personnel costs.

Depreciation and Amortization. Depreciation and amortization was $117.7 million for the nine months ended June 30, 2010, compared to $79.3 million during the same nine-month period in 2009. This $38.4 million, or 48.4%, increase resulted primarily from the expansion projects completed in our midstream segment and acquisitions.

Interest Expense. Interest expense was $66.9 million for the nine months ended June 30, 2010, compared to $52.1 million during the same nine-month period in 2009. This $14.8 million, or 28.4%, increase was primarily attributable to higher average interest rates incurred on our borrowings and to a lesser extent an increase in the average outstanding borrowings during the period. Additionally, during the nine months ended June 30, 2010 and 2009, we capitalized $4.9 million and $10.5 million, respectively, of interest related to certain capital improvement projects in our midstream segment as further described below in the “Liquidity and Sources of Capital” section.

Net Income Attributable to Partners. Net income was $99.0 million for the nine months ended June 30, 2010, compared to net income of $134.2 million for the same nine-month period in 2009. The $35.2 million, or 26.2%, decrease in net income was primarily attributable to increased depreciation and amortization, operating and administrative expenses and interest expense in the 2010 period, partially offset by a higher gross profit.

EBITDA and Adjusted EBITDA. The following table summarizes EBITDA and Adjusted EBITDA for the nine months ended June 30, 2010 and 2009, respectively (in millions):


	Nine Months Ended June 30,
	2010			2009
EBITDA:
Net income attributable to partners	$	99.0		$	134.2
Interest of non-controlling partners in ASC’s consolidated ITDA ^(a)		(0.2	)		(0.4	)
Interest expense, net		66.9			52.1
Provision for income taxes		—			0.4
Depreciation and amortization		117.7			79.3

EBITDA		283.4			265.6

Non-cash (gain) loss on derivative contracts		(0.7	)		1.5
Long-term incentive and equity compensation expense		4.9			2.2
Loss on disposal of assets		5.8			4.1
Transaction costs		2.1			—

Adjusted EBITDA	$	295.5		$	273.4

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


	Nine Months Ended June 30,
	2010			2009
EBITDA:
Net cash provided by operating activities	$	141.6		$	209.2
Net changes in working capital balances		92.7			18.3
Provision for doubtful accounts		(2.1	)		(3.2	)
Amortization of deferred financing costs and net bond discount		(5.4	)		(3.5	)
Unit-based compensation charges		(3.6	)		(2.2	)
Loss on disposal of assets		(5.8	)		(4.1	)
Interest of non-controlling partners in ASC’s consolidated EBITDA		(0.9	)		(1.4	)
Interest expense, net		66.9			52.1
Provision for income taxes		—			0.4

EBITDA		283.4			265.6

Non-cash (gain) loss on derivative contracts		(0.7	)		1.5
Long-term incentive and equity compensation expense		4.9			2.2
Loss on disposal of assets		5.8			4.1
Transaction costs		2.1			—

Adjusted EBITDA	$	295.5		$	273.4

EBITDA is defined as income before income taxes, plus net interest expense and depreciation and amortization expense. For the nine months ended June 30, 2010 and 2009, EBITDA was $283.4 million and $265.6 million, respectively. As indicated in the table, Adjusted EBITDA represents EBITDA excluding the gain or loss on derivative contracts associated with retail propane fixed price sales contracts, the gain or loss on the disposal of assets, long-term incentive and equity compensation expenses and transaction costs. Transaction costs are third party professional fees and other costs that are incurred in conjunction with closing a transaction. Adjusted EBITDA was $295.5 million for the nine months ended June 30, 2010, compared to $273.4 million in the same nine-month period in 2009. EBITDA and Adjusted EBITDA should not be considered an alternative to net income, income before income taxes, cash flows from operating activities, or any other measure of financial performance calculated in accordance with generally accepted accounting principles as those items are used to measure operating performance, liquidity or the ability to service debt obligations. We believe that EBITDA provides additional information for evaluating our ability to make the minimum quarterly distribution and is presented solely as a supplemental measure. We believe that Adjusted EBITDA provides additional information for evaluating our financial performance without regard to our financing methods, capital structure and historical cost basis. EBITDA and Adjusted EBITDA, as we define them, may not be comparable to EBITDA and Adjusted EBITDA or similarly titled measures used by other corporations or partnerships.

Seasonality

The retail market for propane is seasonal because it is used primarily for heating in residential and commercial buildings. Approximately three-quarters of our retail propane volume is sold during the peak heating season from October through March. Consequently, sales and operating profits are generated mostly in the first and fourth calendar quarters of each year.

Liquidity and Sources of Capital

Cash Flows and Contractual Obligations

Net operating cash inflows were $141.6 million and $209.2 million for the nine-month periods ending June 30, 2010 and 2009, respectively. The $67.6 million decrease in operating cash flows was attributable to net decreases in cash components of net income attributable to partners and changes in working capital balances.

Net investing cash outflows were $319.3 million and $161.1 million for the nine-month periods ending June 30, 2010 and 2009, respectively. Net cash outflows were primarily impacted by a $240.5 million increase in cash outlays related to acquisitions, partially offset by an $82.5 million decrease in capital expenditures.

Net financing cash inflows (outflows) were $171.5 million and $(52.4) million for the nine-month periods ending June 30, 2010 and 2009, respectively. The net change was primarily impacted by a $174.6 million increase in proceeds related to the issuance of long-term debt, net of payments on long-term debt, and a $105.5 million increase in proceeds from the issuance of common units, partially offset by a $43.6 million increase in total distributions paid, an acquisition of minority interest of $14.2 million and a $5.0 million increase in payments for deferred financing costs.

We believe that anticipated cash from operations and borrowing capacity under our Credit Agreement described below will be sufficient to meet our liquidity needs for the foreseeable future. If our plans or assumptions change or are inaccurate, or we make acquisitions, we may need to raise additional capital. While global financial markets and economic conditions have been disrupted and volatile in the past, the conditions have improved more recently. However, we give no assurance that we can raise additional capital to meet these needs. As of June 30, 2010, we have firm purchase commitments totaling approximately $16.7 million related to certain of these projects. Additional commitments or expenditures, if any, we may make toward any one or more of these projects are at the discretion of the Partnership. Any discontinuation of the construction of these projects will likely result in less future cash flow and earnings than we have previously indicated.

Description of Credit Facility

On November 24, 2009, we entered into a secured credit facility (“Credit Agreement”) which provides borrowing capacity of up to $525 million in the form of a $450 million revolving general partnership credit facility (“General Partnership Facility”) and a $75 million working capital credit facility (“Working Capital Facility”). This facility replaces our former senior credit facility due 2010. This new facility will mature on November 22, 2013. The Credit Agreement accrues interest at either prime rate or LIBOR plus applicable spreads, resulting in an interest rate of 3.35% at June 30, 2010. At June 30, 2010, borrowings outstanding under the Credit Agreement were $202.0 million, including $168.0 million borrowed for acquisitions and growth capital expenditures and $34.0 million borrowed for working capital purposes. The Credit Agreement is guaranteed by each of our wholly-owned domestic subsidiaries.

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, 2010, we had floating rate obligations totaling $279.3 million including amounts borrowed under our Credit Agreement, the ASC Credit Agreement and our interest rate swaps, which convert a portion of our fixed rate senior unsecured notes due 2015 to floating, with aggregate notional amounts of $75 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 2010 levels, our interest expense would change by a total of approximately $2.8 million per year.

Commodity Price, Market and Credit Risk

Inherent in our contractual portfolio are certain business risks, including market risk and credit risk. Market risk is the risk that the value of the portfolio will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by suppliers, customers or financial counterparties to a contract. We 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, 2010 and 2009, 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, 2010 and September 30, 2009, was assets of $22.7 million and $23.8 million, respectively, and liabilities of $10.1 million and $29.3 million, respectively.

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

Sensitivity Analysis

A theoretical change of 10% in the underlying commodity value would result in a negligible change in the market value of the contracts as there were 0.2 million gallons of net unbalanced positions at June 30, 2010.

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, 2010, 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, 2010, that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

Changes in Internal Control over Financial Reporting

On December 31, 2009, we completed our acquisition of Liberty. See Note 5 “Business Acquisitions” to the Consolidated Financial Statements included in Item 1 for discussion of the acquisition and related financial data.

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

Except for the Liberty acquisition, there were no other material changes in our internal control over financial reporting during the first three quarters of fiscal 2010 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 10 to the Consolidated Financial Statements, of this Form 10-Q is hereby incorporated herein by reference.

Item 1A.

Risk Factors

There have been no material changes to the risk factors disclosed in “Item 1A, Risk Factors” in the Company’s Annual Report on Form 10-K for the fiscal year ended September 30, 2009.

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

None.

Item 3.

Defaults Upon Senior Securities

None.

Item 4.

Reserved

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.

*101.INS		XBRL Instance Document

*101.SCH		XBRL Taxonomy Extension Schema Document

*101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document

*101.LAB		XBRL Taxonomy Extension Label Linkbase Document

*101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document

*101.DEF		XBRL Taxonomy Extension Definition Linkbase Document

*	Filed herewith

SIGNATURE

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


	INERGY, L.P.

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

Date: August 9, 2010	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)