SEC Comment Response

-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, BeqHFPR3o3L1g+4VPWBk5Qz9FTBqA5deEGYzAq7qDJ/TXvmSIOTVTJVf5RURB/v5 K3neXhF2qPtR2cKmLpCtaQ== 0001193125-09-105612.txt : 20091026 0001193125-09-105612.hdr.sgml : 20091026 20090508172318 ACCESSION NUMBER: 0001193125-09-105612 CONFORMED SUBMISSION TYPE: CORRESP PUBLIC DOCUMENT COUNT: 1 FILED AS OF DATE: 20090508 FILER: COMPANY DATA: COMPANY CONFORMED NAME: INERGY L P CENTRAL INDEX KEY: 0001136352 STANDARD INDUSTRIAL CLASSIFICATION: RETAIL-NONSTORE RETAILERS [5960] IRS NUMBER: 431918951 STATE OF INCORPORATION: DE FISCAL YEAR END: 0930 FILING VALUES: FORM TYPE: CORRESP BUSINESS ADDRESS: STREET 1: TWO BRUSH CREEK STREET 2: SUITE 200 CITY: KANSAS CITY STATE: MO ZIP: 64112 BUSINESS PHONE: 8168428181 FILER: COMPANY DATA: COMPANY CONFORMED NAME: INERGY HOLDINGS, L.P. CENTRAL INDEX KEY: 0001228068 STANDARD INDUSTRIAL CLASSIFICATION: RETAIL-NONSTORE RETAILERS [5960] IRS NUMBER: 000000000 FISCAL YEAR END: 0930 FILING VALUES: FORM TYPE: CORRESP BUSINESS ADDRESS: STREET 1: TWO BRUSH CREEK BLVD. STREET 2: SUITE 200 CITY: KANSAS CITY STATE: MO ZIP: 64112 BUSINESS PHONE: 816-842-8181 MAIL ADDRESS: STREET 1: TWO BRUSH CREEK BLVD. STREET 2: SUITE 200 CITY: KANSAS CITY STATE: MO ZIP: 64112 FORMER COMPANY: FORMER CONFORMED NAME: INERGY HOLDINGS LLC DATE OF NAME CHANGE: 20030418 CORRESP 1 filename1.htm SEC Comment Response

Inergy, L.P.

Inergy Holdings, L.P.

Two Brush Creek Boulevard, Suite 200

Kansas City, Missouri 64112

May 8, 2009

VIA EDGAR AND OVERNIGHT MAIL

H. Christopher Owings

Assistant Director

Securities and Exchange Commission

Division of Corporation Finance

100 F Street, N.E., Mail Stop 3561

Washington, D.C. 20549-3561

Re:	Inergy, L.P., and co-registrants

•

Registration Statement on Form S-3

Filed March 17, 2009

File No. 333-158066

•

Form 10-K for Year Ended September 30, 2008

Filed December 1, 2008

•

Form 10-Q for the Period Ended December 31, 2008

Filed February 6, 2009

File No. 0-32453

Inergy Holdings, L.P.

•

Form 10-K for Year Ended September 30, 2008

Filed December 1, 2008

•

Form 10-Q for the Period Ended December 31, 2008

Filed February 6, 2009

File No. 0-51304

Dear Mr. Owings:

Set forth below are the responses of Inergy, L.P., a Delaware limited partnership (“Inergy”), and Inergy Holdings, L.P., a Delaware limited partnership (“Inergy Holdings”), to comments received from the staff of the Division of Corporation Finance (the “Staff”) of the Securities and Exchange Commission (the “Commission”) by letter dated April 16, 2009, with respect to: (a) Inergy’s (1) Registration Statement on Form S-3, filed with the Commission on March 17, 2009, File No. 333-158066 (the “Registration Statement”), (2) Form 10-K for the year ended September 30, 2008, filed with the Commission on December 1, 2008 (the “2008 Form 10-K”) and (3) Form 10-Q for the period ended December 31, 2008, filed with the Commission

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on February 6, 2009, File No. 0-32453; and (b) Inergy Holdings’ (1) Form 10-K for the year ended September 30, 2008, filed with the Commission on December 1, 2008 and (2) Form 10-Q for the period ended December 31, 2008, filed with the Commission on February 6, 2009, File No. 0-51304.

For your convenience, each response is prefaced by the exact text of the Staff’s corresponding comment in bold text.

Inergy, L.P.

We note that the registration statement on Form S-3, with the File No. 333-131742, you filed on February 10, 2006 and amended on August 1, 2006 has not been declared effective or withdrawn. Please withdraw this registration statement in accordance with Rule 477 under the Securities Act of 1933 or tell us why it is not appropriate for you to do so.

Response: Inergy respectfully submits that it intends to file Amendment No. 2 to the registration statement on Form S-3, with the File No. 333-131742, on or about May 15, 2009 and seek effectiveness of the registration statement as soon as possible thereafter.

Form S-3

Exhibit 5.1

We note that counsel’s opinion is limited to federal laws and the laws of the states of New York and Delaware. However, it appears that at least one of the guarantors of the guarantees of the debt securities you are registering is a Pennsylvania limited liability company. Therefore, please have counsel revise its opinion to opine on the laws of Pennsylvania or, in the alternative, remove any limitation as to the laws of any jurisdiction.

Response: Inergy respectfully acknowledges the Staff’s comment. However, upon receipt of board approval on May 14, 2009, Inergy intends to merge Farm & Home Retail Oil Company LLC, the Pennsylvania subsidiary, into Inergy Propane, LLC, a Delaware limited liability company, with Inergy Propane, LLC being the sole surviving entity. Accordingly, counsel’s opinion will not need to address the laws of Pennsylvania.

3.	We note that counsel’s opinion contains certain assumptions regarding the future issuance of the securities being registered. Please confirm that you will file an unqualified opinion each time a takedown occurs that omits all these assumptions.

Response: Inergy respectfully acknowledges the Staff’s comment and confirms that an unqualified opinion of counsel, which omits the referenced assumptions, will be filed each time a takedown occurs.

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May 8, 2009

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Form 10-K for the Year Ended September 30, 2008

Item 6. Selected Financial Data, page 35

We note your presentation of EBITDA and Adjusted EBITDA. Since you state that you are presenting these measures to provide additional information for evaluating your ability to make the minimum quarterly distribution to your partners, these appear to be measures of your liquidity as opposed to measures of your operating performance. As such, it is unclear to us that net income is the most directly comparable GAAP financial measure to which these non-GAAP measures should be reconciled. With reference to our Release No. 33-8176, please tell us how you determined that reconciliation to net income was appropriate and how you considered whether cash flows from operating activities was a more directly comparable GAAP financial measure. With reference to Instruction 2 to Item 2.02 of Form 8-K, please also apply this comment to your presentation of these non-GAAP measures in your quarterly earnings releases.

Response: We believe that EBITDA and Adjusted EBITDA are both performance and liquidity measures. The most directly comparable GAAP financial measure for performance is net income, while the most directly comparable GAAP financial measure for liquidity is cash provided by operations. In future filings, we will reconcile EBITDA and Adjusted EBITDA to both net income and cash provided by operations. We will also add language to explain why we believe EBITDA and Adjusted EBITDA provide additional information to those evaluating our financial statements.

Set forth below is revised and expanded disclosure of that contained in Inergy’s 2008 Form 10-K in order to provide the Staff with an example of how Inergy proposes to prospectively comply with the Staff’s comment in its Form 10-K for the fiscal year ended September 30, 2009. Modified language is presented in italics. In addition, we have presented similar information in our Item 2.02 Form 8-K filed on May 6, 2009 and in our Form 10-Q filed on May 7, 2009.

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	Year Ended September 30,
	2008			2007
EBITDA:
Net income	$	65.1		$	67.0
Interest of non-controlling partners in ASC’s consolidated ITDA^(a)		(0.8	)		—
Interest expense, net		60.9			52.0
Provision for income taxes		0.7			0.7
Depreciation and amortization		98.0			83.4

EBITDA	$	223.9		$	203.1

Non-cash (gain) loss on derivative contracts		0.1			(0.6	)
Long-term incentive and equity compensation expense		3.5			0.7
Loss on disposal of assets		11.5			8.0

Adjusted EBITDA	$	239.0		$	211.2

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


	Year Ended September 30,
	*2008*			*2007*
EBITDA:
Net Cash Provided by Operating Activities	$	183.8		$	167.9
Net changes in working capital balances		3.7			(3.1	)
Provision for doubtful accounts		(5.7	)		(3.3	)
Amortization of debt costs		(2.3	)		(2.4	)
Unit-based compensation charges		(3.5	)		(.7	)
Loss on sale of equipment		(11.5	)		(8.0	)
Interest of non-controlling partners in ASC’s consolidated EBITDA		(2.2	)		—
Interest expense, net		60.9			52.0
Provision for income taxes		.7			.7

EBITDA	$	223.9		$	203.1
Non-cash (gain) loss on derivative contracts		.1			(.6	)
Long-term incentive and equity compensation expense		3.5			.7
Loss on disposal of assets		11.5			8.0

Adjusted EBITDA	$	239.0		$	211.2

EBITDA is defined as income before taxes, plus net interest expense and depreciation and amortization expense. For the years ended September 30, 2008 and 2007, EBITDA was $223.9 million and $203.1 million, respectively. This $20.8 million improvement in EBITDA was primarily attributable to net higher gross profit, which more than offset the increase in cash operating expenses in 2008. As indicated in the table, Adjusted EBITDA represents EBITDA excluding the gain or loss on derivative contracts associated with retail propane fixed price sales contracts, the gain or loss on the disposal of assets and long-term incentive and equity

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compensation expenses. Adjusted EBITDA was $239.0 million for fiscal 2008 compared to $211.2 million in fiscal 2007. EBITDA and Adjusted EBITDA should not be considered an alternative to net income, income before income taxes, cash flows from operating activities or any other measure of financial performance calculated in accordance with generally accepted accounting principles as those items are used to measure operating performance, liquidity or the ability to service debt obligations. We believe that EBITDA and adjusted EBITDA provide additional information for evaluating our financial performance without regard to our financing methods, capital structure and historical cost basis. Further, we believe that EBITDA and Adjusted EBITDA provide additional information for evaluating our ability to make the minimum quarterly distribution and are presented solely as supplemental measures. EBITDA and Adjusted EBITDA, as we define them, may not be comparable to EBITDA and Adjusted EBITDA or similarly titled measures used by other corporations or partnerships.

Item 7. Management’s Discussion and Analysis of Financial Condition and . . ., page 38

Please expand this section to discuss known material trends, demands, commitments, events, or uncertainties that will have, or are reasonably likely to have, a material impact on your financial condition, operating performance, revenues, or income, or result in your liquidity decreasing or increasing in any material way. See Item 303 of Regulation S-K and SEC Release No. 33-8350. As examples only, and not an exhaustive list, please address the following:

•

In the subsection under the heading “General,” you include a discussion of your propane segment, but it does not appear that you provide a similar discussion regarding your midstream segment. Please discuss your midstream segment in a manner similar to that of your propane segment or tell us why it is not appropriate for you to do so.

Response: Inergy respectfully acknowledges the Staff’s comment. Set forth below is an example of how Inergy proposes to prospectively comply with the Staff’s comment in its Form 10-K for the fiscal year ended September 30, 2009.

Significant Economic Factors for Our Midstream Operations.

Our midstream operations primarily include the storage, processing, fractionation, and sale of natural gas and NGLs and, to a lesser extent, the sale of salt from solution mining operations of U.S. Salt, which was acquired in August 2008. The cash flows from these operations are predominantly fee-based under one to ten year contracts with substantial, creditworthy counterparties and, therefore, are generally economically stable and not significantly affected in the short term by changing commodity prices, seasonality or weather fluctuations.

We believe our midstream operations could be negatively affected in the long term by sustained downturns or sluggishness in the economy, which could affect long-term demand and market prices for natural gas and NGLs, all of which are beyond our control and could

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impair our ability to meet our long-term goals. However, we also believe that the contractual fee-based nature of our midstream operations may serve to mitigate this potential risk.

The majority of our operating cash flows in our midstream operations are generated by our natural gas storage operations. Most of our natural gas storage revenues are based on regulated market-based tariff rates, which are driven in large part by competition and demand for our storage capacity and deliverability. Demand for storage in our key midstream market in the northeastern United States is projected to continue to be strong, driven by a shortage in storage capacity and a higher than average annual growth in natural gas demand. This demand growth is primarily driven by the natural gas-fired electric generation sector. The natural gas industry is currently experiencing a significant shift in the sources of supply, and this dramatic change could affect our operations. Traditionally, supply to our markets has come from the Gulf Coast region, onshore and offshore, as well as from Canada. The national supply profile is shifting to new sources of natural gas from basins in the Rockies, Mid-Continent, Appalachia and East Texas. In addition, the natural gas supply outlook includes new LNG re-gasification facilities being built. LNG will clearly be an important new source of supply, but the timing and extent of incremental supply 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. Currently, we have committed to capital expansion projects at our Thomas Corners natural gas storage development and our Finger Lakes LPG storage expansion.

As we execute on our strategic objectives, capital expansion projects will continue to be an important part of our growth plan. We currently have committed capital and investment expenditures in 2009 of approximately $41.7 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.

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May 8, 2009

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•

Please discuss how the recent volatility in certain commodity prices and the recent downturn in the economy contribute to your overall financial position and affect your operations now and in future periods.

Response: Inergy respectfully acknowledges the Staff’s comment and will add the following discussion to the end of the section under the “General” heading:

In the second half of 2008, natural gas, NGL and crude oil prices dropped significantly compared to prices in 2007 and the first two quarters of 2008. For example, during calendar year 2008, at the main pricing hub of Mount Belvieu, Texas, propane prices ranged from a low of $0.54 per gallon to a high of $1.98 per gallon. At December 31, 2008 and March 31, 2009, propane prices were $0.64 per gallon. Commodity prices are impacted by demand, which has been negatively impacted by the current recessionary environment. Specifically, we believe that the economic downturn has caused certain of our retail propane customers to conserve and thereby purchase less propane. The trend is expected to continue throughout the life of the recession. However, our hedging program and ability to pass on price increases to our customers limits the impact that volatility has had on our operations. In the future, we will continue to hedge virtually 100% of our exposure from fixed price sales. While we have historically been successful in passing on any price increases to our customers, there can be no guarantees that this trend will continue in the future. In addition, although the recession has not currently impacted our cash collections, it is possible that a prolonged recession could have a negative impact on our future cash collections.

We do not believe that the economic downturn has had nor will have a significant impact on our midstream operations due to the long-term contractual cash flows that make up the majority of this segment and the creditworthiness of our customers in this segment.

•

In this regard, on page 40, you state that the “price of crude oil has maintained historically high costs in 2006, 2007, and 2008, and propane has also been at historically high costs.” Please discuss whether you believe this trend will continue and how you will adjust your operations in response to that belief.

Response: Inergy respectfully acknowledges the Staff’s comment and will include such disclosure in future filings with the Commission. Set forth below is revised and expanded disclosure of that contained in Inergy’s 2008 Form 10-K in order to provide the Staff with an example of how Inergy proposes to prospectively comply with the Staff’s comment in its Form 10-K for the fiscal year ended September 30, 2009. Modified language is presented in italics.

The prices of crude oil and natural gas have maintained historically high costs in 2006, 2007 and in the first half of 2008 before dropping sharply in the latter half of 2008, and, since propane is a by-product of these commodities, it too has been at historically high levels over this same time frame. As such, our selling prices of propane have been at higher levels in order to attempt to maintain our historical gross margin per gallon. We do not attempt to predict or control

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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. 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 the first paragraph on page 39 of this document, and on page 22 of your quarterly report on Form 10-Q for the period ended December 31, 2008, you state that you intend to pursue growth objectives through future acquisitions, maintaining a high percentage of retail sales to residential customers, operating in attractive markets, and focusing on operations under established and locally recognized trade names. Please discuss in greater detail the manner in which you plan to undertake these growth objectives in future operations and whether you have any established plans or procedures in place to do so currently. If so, please discuss those plans or procedures. If not, please state.

We are a Delaware limited partnership formed to own and operate a growing retail and wholesale propane supply, marketing and distribution business. We also own and operate a growing midstream operation. 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, operate 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 we employ. Their 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 insure the appropriate growth opportunities are pursued. During fiscal 2008, they evaluated approximately 90 potential acquisitions.

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Liquidity and Sources of Capital, page 50

Cash Flows and Contractual Obligations, page 51

6.	In future filings, please provide a discussion of the underlying reasons for changes in cash flows as presented in the statements of cash flows for the full three year period covered by the financial statements. Refer to Item 303 of Regulation S-K.

Net operating cash inflows were $183.8 million and $167.9 million for fiscal years ending September 30, 2008 and 2007, respectively. The $15.9 million increase in operating cash flows was primarily attributable to increases in cash components of net income as well as net changes in working capital balances.

Net investing cash outflows were $386.7 million and $187.8 million for the fiscal years ending September 30, 2008 and 2007, respectively. Net cash outflows were primarily impacted by a $115.5 million increase in cash outlays related to acquisitions and a $99.2 million increase in capital expenditures, partially offset by a $16.2 million increase in proceeds from the sale of assets.

Net financing cash inflows were $212.5 million and $15.6 million for the fiscal years ending September 30, 2008 and 2007, respectively. Net cash inflows were primarily impacted by a $330.4 million increase in proceeds related to the issuance of long-term debt, net of payments on long-term debt, a $104.5 million decrease in the proceeds from issuance of common units, a $3.5 million increase in payments for deferred financing costs, a $2.6 million decrease in proceeds from unit option exercises and a $22.9 million increase in total distributions paid.

Net operating cash inflows were $167.9 million and $104.4 million for fiscal years ending September 30, 2007 and 2006, respectively. The $63.5 million increase in operating cash flows was primarily attributable to increases in net income and net assets from price risk management activities, partially offset by a decrease in working capital balances.

Net investing cash outflows were $187.8 million and $210.9 million for the fiscal years ending September 30, 2007 and 2006, respectively. We funded acquisitions of $99.6 million in 2007 compared to $187.2 million in 2006, a decrease of $87.6 million. Additionally, deferred acquisition costs decreased $0.3 million in fiscal year 2007 compared to fiscal year 2006 and proceeds from sale of assets increased $1.6 million. These reductions in net investing cash outflows were partially offset by an increase of $66.4 million in capital expenditures.

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Net financing cash inflows were $15.6 million and $109.0 million for the fiscal years ending September 30, 2007 and 2006, respectively. Net financing cash inflows were primarily impacted by $99.6 million and $187.2 million of acquisitions financed in 2007 and 2006, respectively. The lesser amount used to finance acquisitions in 2007 versus 2006 was the primary reason for a $46.2 million period to period decrease in proceeds from the issuance of long-term debt, net of payments on long-term debt, and a $22.9 million decrease in proceeds from the issuance of common units. Net financing cash outflows were also impacted by a $29.2 million period to period increase in distributions and a $5.0 million decrease in the payments for deferred financing costs.

Description of Credit Facility, page 52

We note that you have provided a detailed discussion of debt covenants related to your Credit Agreement. However, you do not appear to have described any significant debt covenants related to your Senior Unsecured Notes, which represent the majority of your total debt. If the Senior Unsecured Notes contain significant debt covenants, please tell us how you considered disclosing them similar to your disclosures for your Credit Agreement. To the extent that you have not disclosed them because they are less restrictive than the covenants for the Credit Agreement, please consider clarifying this to your readers. Additionally, as the two financial covenants listed in the second to last section on page 53 appear to be material, please consider quantifying not only the ratios specified in your debt agreement but also your calculated ratios as of the end of the period to provide your readers with better insight into the likelihood of continuing to remain in compliance with these covenants.

Response: Inergy respectfully acknowledges the Staff’s comment and will provide a brief explanation of the covenants contained in our senior note indentures and disclose the significant debt covenant ratios under our credit agreement in future filings with the Commission.

As we disclose in the credit agreement description on page 53 of our 2008 Form 10-K, the credit agreement contains two financial covenants that require us to:

maintain the ratio of our total funded debt (as defined in the Credit Agreement) to consolidated EBITDA (as defined in the Credit Agreement) for the four fiscal quarters most recently ended must be no greater than 5.25 to 1.0 for any period of two consecutive fiscal quarters immediately following an acquisition with a purchase price in excess of $100 million and 4.75 to 1.0 at all other times, and

maintain the ratio of our consolidated EBITDA to consolidated interest expense (as defined in the Credit Agreement), for the four fiscal quarters then most recently ended, must not be less than 2.5 to 1.0

Our senior note indentures require us to maintain a fixed charge coverage ratio for the four fiscal quarters most recently ended of 2.0 to 1.0 in order for us to incur more indebtedness, and the

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indentures require us to maintain a fixed charge coverage ratio for the four fiscal quarters most recently ended of 1.75 to 1.0 in order for us to make restricted payments, including distributions to our unitholders. The calculations of the interest coverage ratio as defined in our Credit Agreement and the fixed charge coverage ratio as defined in our senior notes indentures are substantially similar. Because (1) the Credit Agreement covenants are more restrictive than the covenants contained in the senior notes indentures and (2) the Credit Agreement and the senior notes indentures contain cross default provisions, we have not disclosed the fixed charge coverage ratio in our 2008 Form 10-K.

Inserted on page 53:

The Credit Agreement contains the following financial covenants:

the ratio of our total funded debt (as defined in the Credit Agreement) to consolidated EBITDA (as defined in the Credit Agreement) for the four fiscal quarters most recently ended must be no greater than 5.25 to 1.0 for any period of two consecutive fiscal quarters immediately following an acquisition with a purchase price in excess of $100 million and 4.75 to 1.0 at all other times.

the ratio of our consolidated EBITDA to consolidated interest expense (as defined in the Credit Agreement), for the four fiscal quarters then most recently ended, must not be less than 2.5 to 1.0.

At September 30, 2008, our ratio of total funded debt to consolidated EBITDA was 3.97x, and our ratio of consolidated EBITDA to consolidated interest expense was 3.75x.

Inserted on page 55 after the 2014 Senior Notes section:

The indentures governing our senior unsecured notes discussed above are substantially similar and contain covenants that, among other things, will limit our ability and the ability of our restricted subsidiaries to:

sell assets;

pay distributions on, redeem or repurchase our units or redeem or repurchase our subordinated debt;

make investments;

incur or guarantee additional indebtedness or issue preferred units;

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create or incur certain liens;

enter into agreements that restrict distributions or other payments from our restricted subsidiaries to us;

consolidate, merge or transfer all or substantially all of our assets;

engage in transactions with affiliates; and

create unrestricted subsidiaries.

These covenants are subject to important exceptions and qualifications, and if the notes achieve an investment grade rating from either Moody’s or Standard & Poor’s, many of these covenants will terminate.

In addition, the indentures governing our senior notes restrict our ability to pay cash distributions. Before we can pay a distribution to our unitholders, we must demonstrate that the fixed charge coverage ratio (as defined in the senior notes indentures) is at least 1.75x.

Critical Accounting Policies, page 57

We note that your Critical Accounting Policies are substantially the same as the related Significant Accounting Policies contained in Note 2 to your financial statements. We remind you that your Critical Accounting Policies disclosure should supplement, not duplicate, the description of accounting policies that are already disclosed in the notes to the financial statements. The disclosure should provide greater insight into the quality and variability of information regarding financial condition and operating performance. While accounting policy notes in the financial statements generally describe the method used to apply an accounting principle, the discussion in Critical Accounting Policies should present a company’s analysis of the uncertainties involved in applying a principle at a given time or the variability that is reasonably likely to result from its application over time. For example, given the current struggling economy, your estimates of impairment for long-lived assets and goodwill, and your estimates of fair values for your derivative contracts, may involve more uncertainty than usual, and if so, you should address these uncertainties and the sensitivity of these estimates to change based on other outcomes that are reasonably likely to occur. Refer to Section V of our Release 33-8350, available on our website at www.sec.gov/rules/interp/33-8350.htm. Please revise as appropriate.

Response: Inergy respectfully acknowledges the Staff’s comment and will include additional language to address uncertainties and the potential volatility in applying an accounting principles in future filings with the Commission. Set forth below is revised and expanded disclosure of that contained in Inergy’s 2008 Form 10-K in order to provide the Staff with an example of how

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Inergy proposes to prospectively comply with the Staff’s comment in its Form 10-K for the fiscal year ended September 30, 2009. Modified language is presented in italics.

Critical Accounting Policies

Accounting for Price Risk Management. We utilize certain derivative financial instruments to (i) manage our 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 propane and heating oil will be available; and (iii) manage our exposure to interest rate risk. We record all derivative instruments on the balance sheet as either assets or liabilities measured at estimated fair value under the provisions of Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”), as amended.

We determine fair value of our derivative financial instruments according to the following hierarchy: (1) first, comparable market prices to the extent available; (2) second, internal valuation models that utilize market data (observable inputs) as input variables; and lastly, (3) internal valuation models that use management’s assumptions about the assumptions that market participants would use in pricing the instruments (unobservable inputs) to the extent (1) and (2) are unavailable. Because the majority of the instruments we enter into are traded in liquid markets, we value these instruments based on prices indicative of exiting the position. As a consequence, the majority of the values of our derivative financial instruments are based upon actual prices of like kind trades that are obtained from on-line trading systems and verified with broker quotes. Changes in the fair value of these derivative financial instruments, primarily resulting from variability in supply and demand, are recorded either through current earnings or as other comprehensive income, depending on the type of transaction.

On the date the derivative contract is entered into, we generally designate specific derivatives as either a hedge of the fair value of a recognized asset or liability (fair value hedge), or a hedge of a forecasted transaction (cash flow hedge). We document all relationships between hedging instruments and hedged items, as well as our risk-management objective and strategy for undertaking various hedge transactions. We use regression analysis or the dollar offset method to assess, both at the hedge’s inception and on an ongoing basis, whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in fair value or cash flows of hedged items. When it is determined that a derivative is not highly effective as a hedge or that is has ceased to be a highly effective hedge, we discontinue hedge accounting prospectively. When hedge accounting is discontinued because it is determined that the derivative no longer qualifies as an effective hedge, we continue to carry the derivative on the balance sheet at fair value, and recognize changes in the fair value of the derivative through current-period earnings.

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We are party to certain commodity derivative financial instruments that are designated as hedges of selected inventory positions, and qualify as fair value hedges, as defined in SFAS 133. Our overall objective for entering into fair value hedges is to manage our exposure to fluctuations in commodity prices and changes in the fair market value of our inventories. These derivatives are recorded at fair value on the balance sheets as price risk management assets or liabilities and the related change in fair value is recorded to earnings in the current period as cost of product sold. Any ineffective portion of the fair value hedges is recognized as cost of product sold in the current period. We recognized an immaterial net gain in the year ended September 30, 2008, related to the ineffective portion of our fair value hedging instruments. In addition, for the year ended September 30, 2008, we recognized a net gain of $0.1 million related to the portion of fair value hedging instruments that we excluded from our assessment of hedge effectiveness.

We also enter 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 in the same period in which the hedge transaction affects earnings. Any ineffective portion of the gain or loss is recognized as cost of product sold in the current period. Accumulated other comprehensive income (loss) was $(25.3) million and $9.2 million at September 30, 2008 and 2007, respectively.

The cash flow impact of derivative financial instruments is reflected as cash flows from operating activities in the consolidated statements of cash flows.

If management’s assumptions related to unobservable inputs used in the pricing models for certain of our financial instruments, which include swaps, forwards, futures and options, are inaccurate or if we had used an alternative valuation methodology, the estimated fair value may have been different, and we may be exposed to unrealized losses or gains. A hypothetical 10% difference in the assumptions made for our unobservable inputs would have impacted our estimated fair value of these derivatives at September 30, 2008 and would have affected net income by approximately $0.1 million for the year ended September 30, 2008.

Revenue Recognition. Sales of propane, other liquids and salt, are recognized at the time the 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.

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Impairment of Long-Lived Assets. Pursuant to SFAS No. 142, “Goodwill and Other Intangible Assets,” (“SFAS 142”) goodwill is subject to at least an annual assessment for impairment by applying a fair-value-based test. 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.

Under the provisions of SFAS 142, we completed the valuation of each of our reporting units and determined no impairment existed as of September 30, 2008. The valuation of our reporting units requires us to make certain assumptions as it relates to future operating performance. When considering operating performance, various factors are considered such as current and changing economic conditions and the commodity price environment, among others. Due to the economic uncertainty, we adjusted our assumptions underlying our discounted cash flow approach to valuing enterprise value. Projected cash flows for 2009 reflect the deteriorating economic conditions that began in the latter half of 2008. The discount rate used in the current year reflects an increase in our cost of capital due to the dislocation of worldwide credit markets. If the growth assumptions embodied in the current year impairment testing prove inaccurate, we could incur an impairment charge. A 10% decrease in the estimated future cash flows and a 1% increase in the discount rate used in our impairment analysis would not have indicated a potential impairment of any of our intangible assets. To date, we have not recognized any impairment on assets we have acquired.

Statement of Financial Accounting Standards No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets”
(“SFAS 144”) modifies the financial accounting and reporting for long-lived assets to be disposed of by sale and it broadens the presentation of discontinued operations to include more disposal transactions. The value of the assets to be disposed of is estimated at the date a commitment to dispose the asset is made. Our estimate of any loss associated with an asset sale is dependent on certain assumptions we make with respect to the net realizable value of the particular asset. A 10% decrease in the estimated net realizable value would have resulted in an additional loss of $0.4 million.

Self-Insurance. We are insured by third parties, 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, general, product and vehicle liability, and environmental exposures. Self insurance reserves 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. Our self insurance reserves could be affected if future claims development differs from the historical trends. We believe changes in health care costs, trends in health care

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claims of our employee base, accident frequency and severity and other factors could materially affect the estimate for these liabilities. We continually monitor changes in employee demographics, incident and claim type and evaluate our insurance accruals and adjust our accruals based on our evaluation of these qualitative data points. To date, our payments have not exceeded the amount of our insurance accruals. At September 30, 2008 and 2007, our self-insurance reserves were $17.4 million and $13.2 million, respectively.

Item 11. Executive Compensation, page 66

Compensation Discussion and Analysis, page 66

We note your discussion under the heading “Compensation Philosophy and Objectives” in which you state that the primary measure of your performance is your ability to increase sustainable quarterly cash distributions to your unitholders and related unitholder value realized. Also, we note the objectives of your total compensation program under this heading and your discussion regarding the separate elements of compensation under the heading “Elements of Compensation.” In addition to these disclosures, please provide greater detail about how you determine the amount of each compensation element to pay and your policies for allocating between long-term and currently paid out compensation. For example, please discuss the manner in which your compensation program and policies balance short and long-term performance. See Item 402(b)(1)(v) and 402(b)(2)(i) of Regulation S-K. Further, in this regard, please consider including a discussion of any of the remaining factors in Item 402(b)(2) of Regulation S-K that are necessary to provide investors material information to understand your compensation policies and decisions regarding the named executive officers.

Response: Inergy respectfully acknowledges the Staff’s comment and will include such disclosure in future filings with the Commission. Set forth below on Exhibit A is revised and expanded disclosure of that contained in Inergy’s 2008 Form 10-K in order to provide the Staff with an example of how Inergy proposes to prospectively comply with the Staff’s comment in its Form 10-K for the fiscal year ended September 30, 2009.

Benchmarking, page 67

10.

In this subsection, you state that you utilize benchmarking data from similar peer and regional companies to assist you in assessing executive compensation levels. Please elaborate upon and provide greater detail regarding the benchmarking data from these companies that you consider in your compensation program and, if applicable, identify their components. See Item 402(b)(2)(xiv) of Regulation S-K and the Division of Corporation Finance’s Compliance and Disclosure Interpretation 118.05 under Regulation S-K (July 3, 2008).

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Elements of Compensation, page 68

Base Salary, page 68

11.

You state that your executives’ base salaries are designed to compensate them for their responsibility level and their “sustained individual performance.” Also, you state that based on the “financial results [you] have achieved,” combined with certain benchmarking data, you determined that the annual base salaries for your named executive officers will remain unchanged in 2009. Therefore, it is unclear whether the base salaries are established or changed by obtaining certain objective financial results or whether each executive’s salary determination is completely subjective. If certain financial results are quantified to establish or change base salaries, please specify these results. See Item 402 (b)(2)(v) of Regulation S-K. If financial results are not quantified, please state.

12.

Further, regardless of whether or not certain financial results are quantified, please clarify the manner in which you use the metrics you discuss in this subsection, including experience, scope of responsibility, results achieved, and future potential, in determining your named executive officers’ base salaries.

Long-Term Incentives Plan, page 69

13.

Please move the section entitled “Inergy Long Term Incentive Plan,” beginning on page 73, and the section entitled “Inergy Holdings Long Term Incentive Plan,” beginning on page 74, so that they appear in your Compensation Discussion and Analysis section and before the compensation tables. See Section II.B.1 of SEC Release 33-8732A.

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Response: Inergy respectfully acknowledges the Staff’s comment. However, rather than move each section in its entirety so that it appears in our Compensation Discussion and Analysis section and before the compensation tables, Inergy respectfully submits that it will move the portions of such disclosure that provide meaningful analysis to the discussion in future filings with the Commission. Set forth below on Exhibit A is revised and expanded disclosure of that contained in Inergy’s 2008 Form 10-K in order to provide the Staff with an example of how Inergy proposes to prospectively comply with the Staff’s comment in its Form 10-K for the fiscal year ended September 30, 2009.

14.

You state that you grant long-term incentive awards “to promote achievement of [y]our long-term strategic business objective of increasing distributable cash flow and increasing unitholder value,” to “furnish additional compensation,” to provide a “visable, reachable reward for the executive officers,” and to align executives’ “economic interests with those of common unitholders.” Presumably, based on these objectives, on October 1, 2007 you awarded restricted units of Inergy Holdings, L.P. to R. Brooks Sherman, Phillip L. Elbert, Laura L. Ozenberger, and William R. Moler. Please discuss the manner in which you determined that each executive officer earned the specific amount of restricted units he or she received. Also, please explain why the executive officers received restricted units instead of unit options, or a combination of restricted units and unit options, as your long- term incentive plan and the Inergy Holdings Long Term Incentive Plan appear to allow.

Item 13. Certain Relationships, Related Transactions and Director Independence, page 81

Related Party Transactions, page 81

15.

Please disclose whether the terms in the transactions and agreements you disclose regarding related parties were comparable to terms you could have obtained from unaffiliated third parties.

In connection with our acquisition of assets from United Propane, Inc. on July 31, 2003, we entered into ten leases of real property formerly used by United Propane (now known as Bonavita, Inc.) in its business. We entered into five of these leases with United

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Propane, three of these leases with Pascal Enterprises, Inc. and two of these leases with Robert A. Pascal. Each of these leases provided for an initial five-year term, and was renewable by us for up to two additional terms of five years each. During the initial term of these leases we were required to make monthly rental payments totaling $59,167, of which $17,167 was payable to United Propane, $16,800 was payable to Pascal Enterprises, and $25,200 was payable to Mr. Pascal. During fiscal 2008, we exercised our renewal option on six of these leases for an additional five-year term each. Three of these leases are with United Propane, two of these leases are with Mr. Pascal and one is with Pascal Enterprises. We are now required to make monthly rental payments totaling $45,697, of which $8,400 is payable to United Propane, $25,747 is payable to Mr. Pascal, and $11,550 is payable to Pascal Enterprises. We believe that the monthly rental payments on the above described leases are consistent with the terms that could have been negotiated with an unrelated third party.

On May 1, 2004, we entered into a lease agreement with United Leasing, Inc. to lease a propane rail terminal known as the Curtis Bay Terminal for the base monthly rent of $15,000. On May 1, 2005 this lease was renewed and the monthly base rent was reduced to $12,500. During fiscal 2008, this lease expired and was not renewed.

Robert A. Pascal is the sole shareholder of Bonavita, Inc., Pascal Enterprises and United Leasing and is on our managing general partner’s board of directors.

16.

Please disclose the expenses for which Inergy Holdings, L.P. reimbursed you that you discuss in the last paragraph of this subsection.

On occasion, Inergy Holdings reimburses us for expenses paid on behalf of Inergy Holdings. The expenses that are reimbursed predominantly include insurance and professional fees. These expenses for the years ended September 30, 2008, 2007 and 2006 amounted to $0.2 million, $0.4 million and $0.3 million, respectively. When we have a receivable from Inergy Holdings, it is included in prepaid expenses and other current assets on our consolidated balance sheet. At September 30, 2008, we had $0.2 million due from Inergy Holdings. At September 30, 2007, we had $0.1 million due from Inergy Holdings.

Review, Approval or Ratification of Transactions with Related Persons, page 81

17.

You state that, based on your Related Person Transactions Policy, related person transactions that, in the discretion of your managing general partner, require the approval of the conflicts committee in accordance with your Partnership Agreement

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may be approved only by the conflicts committee. Please discuss the criteria that the managing general partner uses to determine if the related party transaction requires the approval of the conflicts committee. Also, please discuss the types of transactions that are covered by your Related Person Transactions Policy and the standards to be applied pursuant to that policy so that you discuss specifically the manner in which you review and approve related party transactions based upon the specific facts and circumstances presented as required by Item 404(b) of Regulation S-K. The policy required by Item 404(b) should be specific to transactions subject to Item 404(a) of Regulation S-K.

Response: Our Related Person Transactions Policy applies to any transaction since the beginning of our fiscal year (or currently proposed transaction) in which we or any of our subsidiaries was or is to be a participant, the amount involved exceeds $120,000 and any director, director nominee, executive officer, 5% or greater unitholder (or their immediate family members) had, has or will have a direct or indirect material interest. A transaction that would be covered by this policy would include, but not be limited to, any financial transaction, arrangement or relationship (including any indebtedness or guarantee of indebtedness) or any series of similar transactions, arrangements or relationships.

Under our Related Person Transactions Policy, related person transactions may be entered into or continue only if the transaction is deemed to be “fair and reasonable” to Inergy, in accordance with the terms of our Partnership Agreement. Under our Partnership Agreement, transactions that represent a “conflict of interest” may be approved in one of three ways and, if approved in any of those ways, will be considered “fair and reasonable” to Inergy and the holders of common units. The three ways enumerated in our Related Person Transactions Policy for reaching this conclusion include:

(i)

approval by the Conflicts Committee of the Board (the “Conflicts Committee”) under Section 7.9 of the Partnership Agreement (“Special Approval”);

(ii)

approval by our Chief Executive Officer applying the criteria specified in Section 7.9 of the Partnership Agreement if the transaction is in the normal course of the Partnership’s business and is (a) on terms no less favorable to the Partnership than those generally being provided to or available from unrelated third parties or (b) fair to the Partnership, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to the Partnership); and

(iii)

approval by an independent committee of the Board (either the Audit Committee or a Special Committee) applying the criteria in Section 7.9 of the Partnership Agreement.

Once a transaction is approved in any of these ways, it is “fair and reasonable” and accordingly deemed (i) approved by all of our partners and (ii) not to be a breach of any fiduciary duties of general partner.

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Our managing general partner determines in its discretion which method of approval is required depending on the circumstances.

Under our Related Person Transactions Policy, as well as under our Partnership Agreement, there is no obligation to take any particular conflict to the Conflicts Committee – empaneling that committee is entirely at the discretion of the managing general partner. In many ways, the decision to engage the Conflicts Committee can be analogized to the kinds of transactions for which a Delaware corporation might establish a special committee of independent directors. The managing general partner considers the specific facts and circumstances involved. Relevant facts would include:

•

the nature and size of the transaction (e.g., transaction with a controlling unitholder, magnitude of consideration to be paid or received, impact of proposed transaction on the general partners and holders of common units);

•

the related person’s interest in the transaction;

•

whether the transaction is on terms no less favorable than terms generally available to an unaffiliated third-party under the same or similar circumstances;

•

if applicable, the availability of other sources of comparable services or products; and

•

the financial costs involved, including costs for separate financial, legal and possibly other advisors at our expense.

Under our Partnership Agreement, when determining whether a related person transaction is “fair and reasonable,” if our managing general partner elects to adopt a resolution or a course of action that has not received Special Approval, then our managing general partner may consider:

•

the relative interests of any party to such conflict, agreement, transaction or situation and the benefits and burdens relating to such interest;

•

any customary or accepted industry practices and any customary or historical dealings with a particular person;

•

any applicable generally accepted accounting practices or principles; and

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•

such additional factors as the managing general partner or Conflicts Committee determines in its sole discretion to be relevant, reasonable or appropriate under the circumstances.

In response to the Staff’s comment, Inergy will expand its Item 404(b) discussion to disclose this information in future filings with the Commission.

18.

Also, please discuss the manner in which the Partnership Agreement proscribes [sic] the approval of related party transactions by the conflicts committee, including the criteria it provides for approving related party transactions.

Response: A related person transaction that is approved by the Conflicts Committee is, as discussed in greater detail in our response to Staff comment no. 17, conclusively deemed to be fair and reasonable to Inergy. Under the Partnership Agreement, the material facts known to our managing general partner or any of its affiliates regarding the transaction must be disclosed to the Conflicts Committee at the time the committee gives its approval. When approving a related person transaction, the Conflicts Committee considers all factors it considers relevant, reasonable or appropriate under the circumstances, including the relative interests of any party to the transaction, customary industry practices and generally accepted accounting principles.

Under the Partnership Agreement, in the absence of bad faith by the managing general partner, the resolution, action or terms so made, taken or provided by the managing general partner with respect to approval of the related person transaction will not constitute a breach of the Partnership Agreement or any standard of fiduciary duty.

In response to the Staff’s comment, Inergy will expand its Item 404(b) discussion to disclose this information in future filings with the Commission.

19.

You state that, if your managing general partner does not believe that the related party transaction must be approved by the conflicts committee, the transaction may be entered into or continue only if it is in the normal course of business, it is on terms no less favorable than the terms that would have been provided by an unaffiliated third party, and it is fair to you. Please discuss the manner in which you determine that a related party transaction is in the normal course of business, has terms as favorable as those with an unaffiliated third party, and is fair to you.

Response: When determining whether a related person transaction is in the normal course of Inergy’s business and is (a) on terms no less favorable to Inergy than those generally being provided to or available from unrelated third parties or (b) fair to Inergy, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to Inergy), the managing general partner considers any facts and circumstances that it deems to be relevant, including:

•

the terms of the transaction, including the aggregate value;

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•

the business purpose of the transaction;

•

the relative interests of any party to such conflict, agreement, transaction or situation and the benefits and burdens relating to such interest;

•

whether the terms of the transaction are comparable to the terms that would exist in a similar transaction with an unaffiliated third party;

•

any customary or accepted industry practices;

•

any applicable generally accepted accounting practices or principles; and

•

such additional factors as the managing general partner or the Conflicts Committee determines in its sole discretion to be relevant, reasonable or appropriate under the circumstances.

In response to the Staff’s comment, Inergy will expand its Item 404(b) discussion to disclose this information in future filings with the Commission.

Financial Statements, page 89

Consolidated Statements of Operations, page 93

20.

Please provide the basis in GAAP for your accounting for the beneficial conversion feature associated with the special units at the time of the issuance of the special units and at the time of conversion of the special units. Please also tell us how the value attributed to the beneficial conversion feature was derived.

Response: We have evaluated the terms of the special units and the related conversion feature and have concluded that these are properly classified as equity. Accordingly, the provisions of EITF 00-27, Application of Issue No. 98-5 to Certain Convertible Instruments, represents the GAAP guidance we followed. We believe that the terms represent a contingent beneficial conversion feature because 1) the units could expire without becoming convertible unless certain criteria outside the control of the issuer were met and 2) the conversion rate increased with the passage of time. Accordingly, under the guidance of the EITF the intrinsic value assigned was based on the most favorable conversion price that would be in effect at the conversion date, assuming there are no changes to the current circumstances except for the passage of time. In the case of the special units, the most advantageous conversion that could be realized was 1.43 to 1. It further requires that any conversion terms that would be triggered by future events not controlled by the issuer to be accounted for as contingent conversion options. The intrinsic value

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of such conversion options would be measured as of the commitment date and recognized from the date the contingency was resolved through the conversion date. The commitment date is the date the special units were issued (August 2005) as determined pursuant to paragraph 4 of the EITF. Both the resolution of the contingency and the conversion occurred during the 3^rd quarter of 2007. This EITF requires the unamortized amount of the beneficial conversion to be treated as an additional dividend as noted in paragraph 21 which states “for instruments with beneficial conversion features all of the unamortized discount (both the discount from an allocation of proceeds under Opinion 14 to other separable instruments included in the transaction and the discount originated by the beneficial conversion option accounting) remaining at the date of conversion should be immediately recognized as interest expense or as a dividend, as appropriate.” Thus in the third quarter of 2007, the intrinsic value allocated to the beneficial conversion feature was recognized as a dividend.

The calculation of the intrinsic value of the contingent beneficial conversion feature and related dividend was as follows::


769,941	–	Special Units initially sold
x 1.43	–	multiplied by the most advantageous conversion ratio
1,101,015
(769,941)	–	Special Units
331,074	–	additional units
$ 31.09	–	Fair value at the commitment date
$10,300,000 – value of beneficial conversion

Note 2. Summary of Significant Accounting Policies, page 97

21.

We note from your disclosures on pages eight and 11 that you own most of the propane storage tanks at your customers’ locations. Please tell us how you account for your ownership of these tanks, including your consideration of EITF 01-8, and tell us how you considered disclosing your accounting policy for this matter.

Response: The tanks that we own are included on our balance sheet and depreciated over a period of 30 years. As noted in paragraph 9 of EITF 01-8, Statement 13 (SFAS 13) “Accounting for Leases” covers depreciable assets. Therefore, we view Statement 13 as the authoritative literature in governing our accounting for our tanks. The agreements with our customers to lease tanks allow either party to cancel the agreement without penalty with 30 days notice. Further, the leases contain no purchase options. In addition, the barriers to switching service providers are not deemed to be significant, thus the non-cancellable lease term is determined to be 30 days. Based on these factors, the leases do not meet any of the criteria outlined in paragraph 7 of SFAS 13 and are therefore required to be accounted for as operating leases. Our accounting reflects such classification. We will include disclosure of this accounting in future filings.

Property, Plant and Equipment

Property, plant and equipment consist of the following at September 30, 2008 and 2007, respectively (in millions):


	September 30,
	2008		2007
Tanks and plant equipment	$	713.8	$	619.2
Buildings and improvements		265.6		233.9
Vehicles		104.5		97.7
Construction in process		166.5		27.7
Office furniture and equipment		24.6		21.8

		1,275.0		1,000.3
Less: accumulated depreciation		244.7		179.6

Total property, plant and equipment, net	$	1,030.3	$	820.7

Depreciation expense totaled $73.7 million, $59.7 million and $54.6 million for the years ended September 30, 2008, 2007 and 2006, respectively.

The Tanks and plant equipment balances above include tanks owned by the Company that reside at customer locations. The leases associated with these tanks are accounted for as operating leases in accordance with Statement of Financial Accounting Standard 13 “Accounting for Leases.”

At September 30, 2008 and 2007, the Company capitalized interest of $5.5 million and $3.1 million, respectively, related to certain midstream asset expansion projects.

The property, plant and equipment balances above at September 30, 2008 and 2007 include approximately $4.5 million and $2.3 million, respectively, of propane operations assets deemed held for sale under the provisions of SFAS 144. These assets were identified primarily during the later half of 2008 as a result of losses due to disconnecting customer installations of unprofitable accounts due to low margins, poor payment history or low volume usage, and the fourth quarter of 2007 as a result of the integration of the larger retail propane acquisitions as Inergy has focused on eliminating redundant operations, primarily tanks and equipment, vehicles and certain real estate. As a result, the carrying value of these assets was reduced to their estimated recoverable value less anticipated disposition costs, resulting in losses of approximately $11.5 million and $6.2 million for the years ended September 30, 2008 and 2007, respectively. The $11.5 million and $6.2 million charges are included as components of operating income as losses on disposal of assets. When aggregated with other realized losses, such amounts totaled $11.5 million and $8.0 million, respectively.

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Note 3. Acquisitions, page 105

22.

In future filings, please provide all of the disclosures required by paragraphs 51 through 57 of SFAS 141 or tell us specifically why such disclosures are not required. In your response, please provide support for your assertion that the supplemental information contemplated by paragraphs 54 and 55 of SFAS 141 are not required. We note your reference to the significant subsidiary definition and the requirements of Regulation S-X regarding the provision of pro forma information. The provisions of Regulation S-X require that historical and pro forma financial information be provided in a Form 8-K for the acquisition or disposition of any business that individually or in the aggregate meets the definition of a significant subsidiary. The provision of supplemental pro forma information in your financial statements under SFAS 141 may be required for acquisitions for which a Form 8-K would not be required, as the definition of “material” acquisitions under SFAS 141 may include acquisitions that do not meet the quantitative thresholds specified for “significant” acquisitions under Regulation S-X.

Response: The disclosures required by paragraphs 51 through 57 of SFAS 141 are only required for business combinations that are considered material. SFAS 141 does not specifically define the criteria for an acquisition to be considered “material.” Our materiality analysis consists of two components – a quantitative analysis and a qualitative analysis.

With respect to our quantitative analysis of materiality, we believe that an appropriate starting point in determining whether an acquisition is material are the guidelines set forth in Regulation S-X 210.3-05(b)(2) (“Rule 3-05”) and Regulation S-X 210.1-02(w) (“Rule 1-02(w)”). Pursuant to the asset, income and investment tests provided in those rules, we concluded that none of our acquisitions, individually or in the aggregate, constituted a “significant subsidiary.” None of our acquisitions in fiscal 2008, either individually or in the aggregate, met any of the three conditions contained in Rule 1-02(w). Specifically, (i) our investment amounted to $237 million, net of cash acquired, which was less than 20% of our total asset of $2,137 million at September 30, 2008; (ii) the aggregate total assets of the acquisitions as of September 30, 2008 amounted to $102 million, which was less than 20% of our total assets, as of September 30, 2008; and (iii) the aggregate profit before taxes as of September 30, 2008 of the acquisitions amounted to $6 million, which is less than 20% of our profit before taxes of $65.1 million, as of September 30, 2008.

With respect to our qualitative analysis of materiality, we considered certain other qualitative factors in determining whether or not an acquisition should be considered material under FAS 141. We are a very acquisitive company, having completed over 80 acquisitions in the past 10 years. As such, an acquisition, in and of itself, is not always a material occurrence for our business. Further, with respect to the businesses acquired in 2008, none represented new

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industries, but rather complement our existing businesses which operate in the same industries. One variable that we assess is our ability to leverage existing infrastructure when integrating the acquired operations with our existing businesses. We note that these acquisitions will be managed by our existing management team. Further, the operating economics and related cash flows from the acquired businesses have characteristics similar to the previously mentioned pre-existing businesses. Finally, the long-term integration benefits of these acquisitions lead us to conclude that none of our 2008 acquisitions had any qualitative characteristics for these acquisitions to be considered material, either individually or in the aggregate.

Because none of the quantitative or qualitative factors noted above led us to conclude that a material business acquisition had occurred in 2008, the disclosures in paragraphs 51 through 57 of SFAS 141 were not provided.

23.

We note that the amounts of goodwill and intangible assets acquired in fiscal 2008 presented in Note 3 do not agree with the amounts presented in allocations presented in your Statement of Cash Flows on page 96. In addition, the amount of the purchase price, net of cash acquired presented in the Statement of Cash Flows does not agree with the amount of the aggregate purchase price presented in Note 3. Please explain these differences to us, and either ensure these disclosures are consistent or explain the differences in future filings.

Response: Inergy respectfully acknowledges the Staff’s comment and will include clarifying disclosure in future filings with the Commission. This difference referred to above relates to the fact that the disclosure in Note 3 is limited to acquisitions that occurred during 2008. Note 3 states exactly which acquisitions are being aggregated in the amounts disclosed and further states that all of these acquisitions occurred during 2008. The cash flow statement represents cash and supplemental non-cash activities related to items recorded in 2008. This is not the same as acquisitions that occurred in 2008 because it does not reflect the finalization of the purchase price allocation during the allocation period of acquisitions consummated prior to 2008.

During the fiscal year ended September 30, 2008, Inergy made 6 retail acquisitions, including Riverside Gas & Oil Company, Capitol Propane L.L.C., Rice Oil Co., Farm & Home Oil Retail Company LLC, Little’s Gas Service, Inc. and Deerfield Valley Energy, Inc. Inergy also acquired 2 midstream businesses: US Salt and 100% of the membership interests of ASC. ASC is the majority owner and operator of Steuben, which owns a natural gas storage facility located in Steuben County, New York, and US Salt is an

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industry-leading solution mining and salt production company located in Schuyler County, New York. The aggregate purchase price of these 8 acquisitions, net of cash acquired, was approximately $212.7 million. This amount is $2.4 million less than the 2008 cash paid for acquisitions due to expenditures for acquisitions that closed prior to 2008. The purchase price allocation for these acquisitions has been prepared on a preliminary basis pending final asset valuation and asset rationalization, and changes are expected when additional information becomes available. Changes to final asset valuation of prior fiscal year acquisitions have been included in our consolidated financial statements but are not material.

US GAAP requires that for any material business combination or disposition of assets, pro-forma information must be disclosed. None of the fiscal 2008 acquisitions were, individually or in the aggregate, considered material.

As a result of the fiscal 2008 acquisitions, Inergy acquired $86.5 million of goodwill and $39.2 million of intangible assets, consisting of the following (in millions):


Customer accounts	$	27.9
Noncompetition agreements		11.3

Total intangible assets	$	39.2

The amounts provided above relate solely to acquisitions that closed in fiscal 2008. The amounts disclosed in the supplemental schedule of noncash investing and financing activities in the Consolidated Statement of Cash Flows relate to amounts recorded during 2008, which related to acquisitions that closed in fiscal 2008 and 2007.

The weighted average amortization period of amortizable intangible assets acquired during the year ended September 30, 2008, is approximately 9 years.

24.

We note that you acquired U.S. Salt during fiscal 2008. You disclose on page two that U.S. Salt is an industry leading solution mining and salt production company that produces and sells over 300,000 tons of salt each year. Please tell us how you valued the acquired salt reserves, where such reserves are included in your balance sheet and how you recognize the cost of salt produced. We may have further comment after reviewing your response. If you believe that the acquired salt reserves and this business are immaterial, provide support.

Response: While we will benefit in the near term from solution mining and depletion of the existing salt reserves, we primarily acquired US Salt as a way to expand our natural gas storage business. As we have previously disclosed, the solution mining process used by US Salt creates salt caverns that can be developed into usable natural gas storage capacity. The US Salt facility also has existing cavern space that we intend to convert to approximately 10 bcf of natural gas storage and 5 million barrels of LPG storage. With each new brine well that we drill we create additional potential storage capacity. Because the value of the reserves in place were not the

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primary driver of our acquisition economics, the consideration paid was more driven by US Salt’s gas storage potential than the value of the salt reserves which we did not have formally appraised during the acquisition process. We are currently waiting for the final valuation of the acquired salt reserves, which we expect to have prior to the issuance of our 4^th quarter financial statements. Upon receiving the final valuation, we intend to classify them as a component of property, plant and equipment on the balance sheet. The value of salt inventory produced is recognized in accordance with ARB 43 and includes only those costs related to production of the salt. We do not expect the finalization of the valuation of our salt reserves to require a material amount of annual depletion expense, which will be classified as cost of product sold on the Statement of Operations.

Note 4. Certain Balance Sheet Information, page 106

25.

We note that the amount recorded for Trademarks decreased by $6.5 million at September 30, 2008 compared to September 30, 2007. Please tell us and disclose in future filings whether the decline in value is due to sale or impairment of these assets.

Response: During 2008, we determined that we had incorrectly allocated the cost of an acquisition consummated in 2005 to a trademark that we did not acquire and therefore did not meet the criteria to be classified as a separate intangible apart from goodwill. We determined that the initial accounting treatment of the trademark met the definition of an error based on the guidance in FAS 154.

We then reviewed the guidance provided in SAB 99 to determine if the error in 2005 would require us to restate financial statements. SAB 99 requires that both a qualitative and quantitative assessment be made to determine whether or not the financial statements should be restated. SAB 99 provides the following factors that should be considered in such an analysis:

•

whether the misstatement arises from an item capable of precise measurement or whether it arises from an estimate;

•

whether the misstatement masks a change in earnings or other trends;

•

whether the misstatement hides a failure to meet analysts’ consensus expectations for the enterprise;

•

whether the misstatement changes a loss into income or vice versa;

•

whether the misstatement concerns a segment or other portion of the registrant’s business that has been identified as playing a significant role in the registrant’s operation or profitability;

•

whether the misstatement affects the registrant’s compliance with regulatory requirements;

•

whether the misstatement affects the registrant’s compliance with regulatory requirements;

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May 8, 2009

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•

whether the misstatement affects the registrant’s compliance with loan covenants or other contractual requirements;

•

whether the misstatement has the effect of increasing management’s compensation, for example, by satisfying requirements for the award of bonuses or other forms of incentive compensation; and

•

whether the misstatement involves concealment of an unlawful transaction.

We determined that the identified error did not have any impact on earnings, did not effect compliance with regulatory requirements or loan covenants, had no impact on management compensation and did not conceal an unlawful transaction.

The impact on the financial statements of correcting the error is simply a reclassification between two long-term intangible assets (goodwill and trademark). We believe that the users of our financial statement are primarily concerned with EBITDA, working capital and certain other financial ratios. Further, this amount represents less than 2% of goodwill and slightly more than 2% of net intangible assets.

Due to our conclusion that this item was immaterial based on the considerations discussed above, we determined that restatement of our financial statements was not required and that disclosure in the financial statements was not necessary based on the same considerations.

Note 6. Long-Term Debt, page 109

26.

We note your discussion of the 2016 Senior Notes and the 2014 Senior Notes. We also note that these debt issuances were co-issued by Inergy Finance Corp. and are jointly and severally guaranteed by all of your wholly-owned domestic subsidiaries. We further note that you appear to have registered these notes and the related guarantees. Based on the above, please tell us how you determined that your disclosures comply with Rule 3-10 of Regulation S-X. If you do not believe that this guidance is applicable to you, please explain this to us in detail.

Response: Rule 3-10 of Regulation S-X requires guarantors to present the same financial statements for the same periods as issuers of guaranteed securities. Rule 3-10(f) provides an exception to this general rule and permits modified financial information where (i) all subsidiaries guarantee securities issued by their parent company and (ii) the parent company has no independent assets or operations. The condition is also met when any non-guarantor subsidiaries are minor (their total assets, stockholders’ equity, revenues, income from continuing operations, and cash flows from operating activities, individually and in the aggregate, are less than 3% of the parent company’s consolidated totals). Because we meet the conditions of the exception, we may instead include narrative disclosure about the guarantees in a note to our financial statements. Accordingly, set forth below is revised and expanded disclosure of that contained in Inergy’s 2008 Form 10-K in order to provide the Staff with an example of how Inergy proposes to prospectively comply with the Staff’s comment in its Form 10-K for the fiscal year ended September 30, 2009. Modified language is presented in italics.

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May 8, 2009

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On January 11, 2006, Inergy and its wholly owned subsidiary, Inergy Finance Corp. (“Finance Corp.” and together with Inergy, the “Issuers”) issued $200 million aggregate principal amount of 8.25% senior unsecured notes due 2016 (“2016 Senior Notes”) in a private placement to eligible purchasers. The 2016 Senior Notes contain covenants similar to the 2014 Senior Notes. Inergy used the net proceeds of the offering to repay outstanding indebtedness under the revolving acquisition credit facility. The 2016 Senior Notes represent senior unsecured obligations of Inergy and rank pari passu in right of payment with all other present and future senior indebtedness of Inergy. The 2016 Senior Notes are fully, unconditionally, jointly and severally guaranteed by all of Inergy’s wholly-owned current domestic subsidiaries. Also, Inergy has no independent assets or operations, and subsidiaries not guaranteeing the indenture are minor. Accordingly, condensed consolidating financial information for the parent and subsidiaries is not presented. The 2016 Senior Notes also have certain call features which allow Inergy to redeem the notes at specified prices based on the date redeemed as described below.

Note 8. Partners’ Capital, page 113

Long Term Incentive Plan, page 115

27.

In future filings, for the most recent year for which an income statement is provided, please disclose the weighted average grant date fair values of restricted units for (a) those nonvested at the beginning of the year; (b) those nonvested at the end of the year and those (c) granted, (d) vested, or (e) forfeited during the year. Refer to paragraph A240 (b) of SFAS 123(R). Also for each year for which an income statement is provided, please disclose in future filings the weighted average grant date fair value of restricted units granted during the year and the total fair value of restricted units vested during each period. Refer to paragraph A240(c) of SFAS 123 (R).

Response: Set forth below is revised and expanded disclosure of that contained in Inergy’s 2008 Form 10-K in order to provide the Staff with an example of how Inergy proposes to prospectively comply with the Staff’s comment in its Form 10-K for the fiscal year ended September 30, 2009. Modified language is presented in italics.

Restricted Units

A restricted unit is a common unit that participates in distributions and vests over a period of time yet during such time is subject to forfeiture. The compensation committee may make grants of restricted units to employees, directors and consultants containing such terms as the compensation committee determines. The compensation committee will determine the period over which restricted units granted to participants will vest. The compensation committee, in its discretion, may base its determination upon the

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May 8, 2009

Page 31

achievement of specified financial objectives or other events. In addition, the restricted units will vest upon a change in control of the managing general partner of Inergy. If a grantee’s employment, consulting arrangement or membership on the board of directors terminates for any reason, the grantee’s restricted units will be automatically forfeited unless, and to the extent, the compensation committee or the terms of the award agreement provide otherwise.

The Company intends the restricted units to serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation of the common units. Therefore, plan participants will not pay any consideration for the common units they receive, and Inergy will receive no cash remuneration for the units.

The Company granted 60,064, 69,520 and 58,756 restricted units during the years ended September 30, 2008, 2007 and 2006, respectively. The majority of the restricted units are 100% vested on the fifth anniversary of the grant date, subject to the provisions as outlined in the restricted unit award agreement. Some of these units are subject to the achievement of certain specified performance objectives and failure to meet the performance objectives will result in forfeiture and cancellation of the restricted units. The Company recognizes expense on these units each quarter by multiplying the closing price of the Company’s common units on the date of grant by the number of units granted, and expensing that amount over the vesting period.

A summary of Inergy’s weighted average grant date fair value for restricted units for the year ended September 30, 2008 is as follows:


	Weighted-Average Grant Date Fair Value
Non-vested at October 1, 2007	$	29.95
Granted during the period ended September 30, 2008	$	26.27
Vested during the period ended September 30, 2008	$	11.39
Forfeited during the period ended September 30, 2008	$	18.75
Non-vested at September 30, 2008	$	16.37

The weighted average grant date fair value of restricted units granted and vested during the year ended September 30, 2007 amounted to $31.31 and $26.62, respectively. The weighted average grant date fair value of restricted units granted during the year ended September 30, 2006 amounted to $27.01. There were not any restricted units that vested during the year ended September 30, 2006.

The compensation expense recorded by the Company related to these restricted stock awards was $0.7 million, $0.4 million and less than $0.1 million for the years ended September 30, 2008, 2007 and 2006, respectively.

Securities and Exchange Commission

May 8, 2009

Page 32

Inergy Holdings. L.P.

28.

Please comply with the above comments, as applicable.

Response: Inergy Holdings respectfully acknowledges the Staff’s comment and, to the extent applicable, will include disclosure to address the Staff’s comments in future filings with the Commission.

Form 10-K for the Year Ended September 30, 2008

Item 11. Executive Compensation, page 72

29.

In the second paragraph of this section, you refer your readers to the Compensation Discussion and Analysis section of Inergy, L.P.’s annual report, but it is not clear whether you are incorporating this information into your annual report. Please include Inergy, L.P.’s Compensation Discussion and Analysis section in your annual report, with any appropriate changes tailored particularly for you, or incorporate by reference Inergy’s Compensation Discussion and Analysis section into your annual report.

Response: Inergy Holdings respectfully acknowledges the Staff’s comment and will clarify in future filings with the Commission that it is incorporating by reference Inergy’s Compensation Discussion and Analysis section in Inergy Holdings’ annual report.

*****************

Securities and Exchange Commission

May 8, 2009

Page 33

Inergy, L.P. and Inergy Holdings, L.P. acknowledge that (i) they are responsible for the adequacy and accuracy of the disclosure in the filings; (ii) Staff comment or changes to disclosure in response to Staff comment do not foreclose the Commission from taking any action with respect to the filing; and (iii) they may not assert Staff comment as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States. Should the Staff have any questions or comments, please contact the undersigned at 816-842-8181 or Gillian Hobson of Vinson & Elkins at 713-758-3747.


Sincerely, INERGY, L.P. By: Inergy GP, LLC, its Managing General Partner

By:		/s/ R. Brooks Sherman, Jr.
Name:		R. Brooks Sherman, Jr.
Title:		Executive Vice President and Chief Financial Officer


INERGY HOLDINGS, L.P. By: Inergy Holdings GP, LLC, its General Partner

By:		/s/ R. Brooks Sherman, Jr.
Name:		R. Brooks Sherman, Jr.
Title:		Executive Vice President and Chief Financial Officer

cc:	Gillian A. Hobson, Esq.

Vinson & Elkins L.L.P.

Via Facsimile

Exhibit A

Compensation Discussion and Analysis

Introduction

We do not directly employ any of the persons responsible for managing our business. Inergy GP, LLC, our managing general partner, manages our operations and activities, and its board of directors and officers make decisions on our behalf. The compensation of the directors and certain officers of our managing general partner is determined by the compensation committee of the board of directors of our managing general partner. Certain of our named executive officers also serve as executive officers of the general partner of Inergy Holdings, L.P. and the compensation of the named executive officers discussed below reflects total compensation for services to all Inergy entities. These “shared” officers receive no additional salary or cash compensation for their service to Inergy Holdings, L.P. However, as discussed in greater detail below, from time to time they do receive awards of equity in Inergy Holdings, L.P.

Compensation Philosophy and Objectives

We employ a compensation philosophy that emphasizes pay for performance. The primary measure of our performance is our ability to increase sustainable quarterly cash distributions to our unitholders and the related unitholder value realized. We believe that by tying a substantial portion of each named executive officer’s total compensation to financial performance metrics based on such distributions and unitholder value, our pay-for-performance approach aligns the interests of executive officers with that of our unitholders. Accordingly, the objectives of our total compensation program consist of:

•

aligning executive compensation incentives with the creation of unitholder value and the growth of cash earnings on behalf of our unitholders;

•

balancing short and long-term performance;

•

tying short-and long-term compensation to the achievement of performance objectives (company, business unit, department and/or individual); and

•

attracting and retaining the best possible executive talent for the benefit of our unitholders.

By accomplishing these objectives, we hope to optimize long-term unitholder value.

Compensation Setting Process

Chief Executive Officer’s Role in the Compensation Setting Process

Our Chief Executive Officer plays a significant role in the compensation setting process. The most significant aspects of his role are:

•

assisting in establishing business performance goals and objectives;

•

evaluating executive officer and company performance;

•

recommending compensation levels and awards for executive officers; and

•

implementing the approved compensation plans.

The Chief Executive Officer makes recommendations to the compensation committee with respect to financial metrics to be used for performance-based awards as well as other recommendations regarding non-CEO executive compensation, which may be based on our performance, individual performance and the peer group compensation market analysis. The compensation committee considers this information when establishing the total compensation package of the executive officers. The Chief Executive Officer’s performance and compensation is reviewed, evaluated and established separately by the compensation committee based on criteria similar to those used for non-CEO executive compensation.

~~Benchmarking~~

Market Analysis

To evaluate the competitiveness of both total executive compensation and the individual compensation components, the compensation committee utilizes ~~benchmarking~~compensation data about other companies to assist in assessing executive compensation levels, including the individual base salary and incentive components. ~~The data assembled included data from~~ The data typically consists of an analysis of total compensation, as well as base salary amounts, annual incentive awards, and long-term incentive awards and is compiled from the public filings of similar companies, as well as companies in the Kansas City region. We selected these “peer” companies because, like us, they are: (i) MLPs with significant propane operations, or (ii) MLPs with growing midstream operations. We chose the regional companies because they are public companies with which we compete for talent in the local employment market.

Exhibit A


“Peer” MLP Companies		Regional Companies
Amerigas Partners, L.P.		Compass Minerals International, Inc.

Copano Energy, LLC		DST Systems, Inc.

Crosstex Energy, L.P.		Layne Christensen Company

Energy Transfer Partners, L.P.		Kansas City Southern

Ferrellgas Partners, L.P.

Markwest Energy Partners, L.P.

Suburban Propane Partners, L.P.

The compensation committee utilizes the ~~benchmarking~~market data as a general guideline in making compensation-related decisions. ~~However, we do not advocate a specific percentile relationship of actual pay to market pay as some companies do, e.g., we do not strive to be in the 50th percentile on actual pay.~~ When determining compensation amounts for our executive officers, the compensation committee uses data from our peer group as a reference for determining:

•

Amount of total compensation;

•

Individual components of compensation; and

•

Relative proportion of each component of compensation – base salary, annual incentive award opportunity and long-term incentive award value.

While our general objective for total compensation is at or above the median of the “peer” group data with a significant portion of total compensation at risk, ~~the~~we do not require a strict policy of achieving a specific percentile relationship of actual pay to market pay as some companies do. The compensation committee has the full discretion to disregard the ~~benchmarking~~market data and ~~target~~award compensation at a different range. if there are factors warranting the adjustment. Such factors may include alignment of the officer’s position within the peer group data, experience and value he or she brings to the role, sustained high-level performance, demonstrated success in meeting key financial and other business objectives and the amount of the officer’s pay relative to the pay of his or her peers within our company.

In addition, the actual value delivered to any executive may be above or below that range depending upon our financial results, common unit price performance and the individual’s performance.

The compensation committee may in its discretion retain the services of a third-party compensation consultant, but did not retain any such consultants this fiscal year.

In collecting the peer group data for the compensation committee for fiscal 2008, we compared each officer’s position against like positions for our peer group. The data was adjusted for differences in various financial and operating metrics, including revenues, customer base, numbers of employees and scope for each position relative to comparator company positions. Based on the difficulty in assessing appropriate comparisons of relative value for equity awards, no specific comparison of equity awards of our peer companies was made for long-term incentive opportunity values although the market value of equity holdings of similarly situated employees at our peer companies was generally considered.

Elements of Compensation

The principal elements of compensation for the named executive officers are the following:

Exhibit A - 2

•

base salary;

•

incentive awards;

•

long-term incentive plan awards; and

•

retirement and health benefits.

Base Salary

Base salary is designed to compensate executives for the responsibility of the level of the position they hold and sustained individual performance (including experience, scope of responsibility, results achieved and future potential). ~~The salaries of~~ ~~the~~ Base salary amounts were initially established in the employment agreements of our named executive officers ~~are~~ ~~reviewed~~and we historically have not made annual adjustments to the salaries of our named executive officers. We do, however, review the salaries of our named executive officers on an annual basis, as well as at the time of promotion and ~~other~~ ~~change~~may adjust salaries due to changes in responsibilities or market conditions. ~~The~~ In determining the amount of any adjustments, the compensation committee uses ~~benchmarking~~market data as a ~~general~~ tool for ~~setting~~ ~~compensation~~assessing the reasonableness of the base salary amounts of the named executive officers as compared to the compensation of executives in similar positions with similar responsibility levels in our industry and in our region. However, the final determination of base salary amounts is within the compensation committee’s subjective discretion.

In fiscal 2008, after two years of no changes to base salary amounts, the compensation committee determined it was appropriate to adjust base salaries. In so doing, the compensation committee primarily considered:

•

the increased level of responsibility of each of the named executive officers ~~have received base annual salaries of~~, which resulted from a number of acquisitions in during fiscal years 2005 through 2007, including the acquisition of the Stagecoach facility, resulting in the addition of the midstream segment to our business;

•

the increased complexity in the business, which resulted from:

the initial public offering of Inergy Holdings, L.P. in fiscal 2005; and

the diversification of business, including the addition of the midstream segment;

•

our financial results during fiscal 2007, including:

adjusted EBITDA of $211.1 million for the year ended September 30, 2007, an increase of $35.8 million, or approximately 20.4% from $175.4 million for the year ended September 30, 2006;

distributable cash flow of $155.7 million in fiscal 2007 compared to $119.4 million in fiscal 2006, an increase of approximately 30%; and

distributable cash flow per unit on a fully distributed basis increased approximately 8.3% to $2.47 per diluted limited partner unit in 2007 from $2.28 per diluted limited partner unit in 2006.

•

the general value of the officers to the company based on increased knowledge of the business and the industry as a result of tenure with the company.

As a result of those considerations, the base salaries of each of our named executive officers was increased to $350,000, $225,000, $275,000, $200,000 and $200,000 for John J. Sherman, R. Brooks Sherman, Phillip L. Elbert, Laura L. Ozenberger and William R. Moler, respectively. ~~Based on the financial results we have achieved and benchmarking data~~

For fiscal 2009, consistent with its general policy of not making systematic annual adjustments to base salary, the compensation committee ~~determined~~ ~~that~~elected not to make any changes to the annual base salaries ~~for~~ ~~the~~of our named executive officers ~~will remain unchanged in fiscal 2009~~.

Exhibit A - 3

Incentive Awards

Incentive awards are designed to reward the performance of key employees, including the named executive officers, by providing annual incentive opportunities for the partnership’s achievement of its annual financial performance goals. In particular, these bonus awards are provided to the named executive officers in order to provide competitive incentives to these executives who can significantly impact performance and promote achievement of ~~the~~ our short-term business objectives. Under the terms of their respective employment agreements, each named executive officer is eligible, upon the achievement of certain subjective and objective criteria, to receive a cash bonus amount that is up to 100% of the named executive officer’s base salary.

~~Although discretionary,~~ ~~the~~The bonuses payable to the named executive officers in fiscal 2008 were based upon our achievement of three financial performance metrics: (i) earnings before income taxes, plus net interest expense, depreciation and amortization expense, further adjusted to exclude the gain or loss on derivative contracts, the gain or loss on the disposal of fixed assets and long-term incentive and equity compensation expense (“adjusted EBITDA”), (ii) distributable cash flow and (iii) growth in annualized distributions per unit. We have selected these metrics because we believe they closely align the focus of our named executive officers with the increase in unitholder value. In addition, these were the targets we communicated to our unitholders and analysts as guidance at the beginning of the 2008 fiscal year. The financial performance targets are not weighted. Bonuses are awarded to our named executive officers when we achieve or exceed the predetermined performance targets. With respect to the named executive officers, payouts are targeted to be 100% of a named executive officers’ base ~~salary.~~were not weighted.

The following table summarizes the incentive award targets and our actual results for the fiscal year ended September 30, 2008 (in millions, except per unit data):


	Target	Actual
Adjusted EBITDA⁽¹⁾	$235.0	$239.0
Distributable cash flow	$166.5	$174.3
Inergy, L.P. annualized distribution per unit (growth)	$2.48(4.2%)	$2.54(6.7%)
Inergy Holdings, L.P. annualized distribution per unit (growth)	$2.40(12.1%)	$2.60(21.5%)

⁽¹⁾

Adjusted EBITDA represents EBITDA excluding (1) non-cash gains or losses on derivative contracts associated with fixed price sales to retail propane customers, (2) long-term incentive and equity compensation charges, and (3) gains or losses on disposals of assets. For a reconciliation of EBITDA to Adjusted EBITDA please refer to page 37 of this annual report on Form 10-K.

As reflected in the table, we exceeded the targets for adjusted EBITDA, distributable cash flow and annualized distribution growth per unit. Accordingly, in accordance with the terms of the employment agreements of the named executive officers, the compensation committee approved the short-term incentive awards for fiscal 2008 at 100% of base salary performance. ~~The compensation committee awarded John J. Sherman, R. Brooks Sherman, Jr., Phillip L. Elbert and William R.~~ ~~Moler~~ ~~their fiscal~~ ~~2008~~ In approving the awards, the compensation committee also considered that combined annual base salary and annual incentive awards were generally at the median of our peer companies.

In light of economic conditions, some of the named executive officers offered to take their annual incentive award payouts in Inergy, L.P. restricted units. ~~The restricted units will be granted on~~ On December 1, ~~2008 with~~2008, the compensation committee awarded a number to beof restricted units to each of Messrs. Sherman, Sherman, Elbert and Moler based on the cash value of their respective annual incentive awards divided by the NASDAQ closing price of our common units on such date ~~and will~~, which units would fully vest 60 days from the grant date. ~~The Compensation~~ ~~Committee~~ On the same date, the compensation committee awarded a cash bonus of $200,000 to ~~Laura~~ LMs. Ozenberger for her fiscal 2008 incentive award. ~~Accordingly, the~~ The incentive award for Ms. Ozenberger is reported in the Non-Equity Incentive Plan Compensation column in the Summary Compensation Table and the incentive ~~award~~awards for the other named executive officers isare reported in the Stock Awards column of the Summary Compensation Table.

Long-Term Incentive Plans

Long-term incentive awards for the named executive officers are granted under the Inergy Long Term Incentive Plan and Inergy Holdings Long Term Incentive Plan, in order to promote achievement of our primary long-term strategic business objective of increasing distributable cash flow and increasing unitholder value. These plans are designed to align the economic interests of key employees and directors with those of our common unitholders and the common unitholders of Inergy Holdings, L.P. and to provide an incentive to management for continuous employment with the managing general partner and its affiliates. Long-term incentive compensation is based upon the common units representing limited partnership interests in us or Inergy Holdings, L.P. and may consist of unit options or restricted units. We have no policy regarding the allocation of different types of equity awards; rather, we determine which type of award will be granted due to a number of different factors, including, cost to the company, perceived value to the employee and economic conditions.

In determining whether to award unit options or restricted units for fiscal 2008, the compensation committee determined that restricted units more strongly align the interests of our executive officers and unitholders because the officers are affected by changes in common unit prices in the same manner as other investors. Our executive officers also have the right to receive cash distributions on restricted unit awards prior to vesting in the underlying common units and those cash distribution amounts are not subject to any vesting requirements. By contrast, in a declining market unit options may not serve to fully motivate our executive officers, particularly when the exercise price of the option is greater than the current common unit trading price. Moreover, unit options create a fixed expense for the company regardless of whether they actually deliver value to our executive officers and, therefore, create the possibility of incurring earnings charges for awards that may deliver little or no value. As a result of these considerations and in light of market conditions, the compensation committee determined that fiscal 2008 equity awards would consist of restricted unit awards.

Exhibit A - 4

We do not make systematic annual awards to the named executive officers. Generally, we believe that a two- to five-year grant cycle (and complete vesting over five years) provides a balance between a meaningful retention period for us and a visible, reachable reward for the executive officers. New awards are generally synchronized with the remaining time-vesting requirements of outstanding awards in a manner designed to encourage extended retention of the named executive officers.

Prior equity awards were made in fiscal 2002 and fiscal 2005. Accordingly, on October 1, ~~2007~~2007, restricted units of Inergy Holdings, L.P. were awarded to R. Brooks Sherman (35,000), Phillip L. Elbert (50,000), Laura L. Ozenberger (25,000) and William R. Moler (25,000) under the Inergy Holdings Long Term Incentive Plan. ~~Due~~ However, due to John Sherman’s significant ownership in us and in Inergy Holdings, L.P., he has requested that he receive no long-term equity incentive awards. ~~As stated in the introduction, certain of our named executive officers also serve as executive officers of~~ ~~Inergy~~ ~~Holdings GP, LLC. When analyzing total compensation of the named executive officers, we take into account awards under the~~ ~~Inergy~~ ~~Holdings Long Term Incentive Plan.~~

The restricted unit awards for Messrs. B. Sherman, Elbert, and Moler and Ms. Ozenberger will vest 25% on the 3rd anniversary of the grant date, 25% on the 4th anniversary of the grant date, and the remaining 50% on the 5th anniversary of the grant date. The delayed vesting schedule was set so as to incentive our executive officers to view our company’s performance over the long term and maximize our retention objective. In addition, distributions are paid to the holder of the restricted units. Although we did not tie vesting of these awards to specific company performance objectives, we believe that the receipt of distributions and the length of the delayed vesting schedule adequately accomplish our objective of incentivizing our executives to increase sustainable quarterly cash distributions for all unitholders.

In determining the size of the equity awards, the compensation committee primarily considered the grant date value and vesting schedule of the awards as both a retention tool and performance incentive, the experience and skills of the executive officers as well as their contributions to our operational and financial performance, the economic and retention value of outstanding equity awards held by the executives for both our company and for Inergy Holdings, the amount of cash distributions that would be received by the executives, and cost to our company. These factors were not given any specific weight; rather, they were subjectively evaluated by the compensation committee. The value of the equity awards was also compared to the equity awards of our peer companies to assess reasonableness of the awards without imposing specific targets. In light of these considerations, the compensation committee concluded that the amounts were reasonable.

Exhibit A - 5

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