10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

ý	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the quarterly period ended June 30, 2013

OR

¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the transition period from  to .

COMMISSION FILE NUMBER: 001-34664

Inergy, L.P.

(Exact name of registrant as specified in its charter)

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

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

(816) 842-8181

(Registrant’s telephone number, including area code)

(Former name, former address and former fiscal year,

if changed since last report)

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

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

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

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

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

INERGY, L.P.

INDEX TO FORM 10-Q

	Page
Part I – Financial Information
Item 1 – Financial Statements of Inergy, L.P.:
Consolidated Balance Sheets as of June 30, 2013 (unaudited) and December 31, 2012	3
Unaudited Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2013 and 2012	4
Unaudited Consolidated Statements of Comprehensive Income for the Three and Six Months Ended June 30, 2013 and 2012	5
Unaudited Consolidated Statement of Partners’ Capital for the Six Months Ended June 30, 2013	6
Unaudited Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2013 and 2012	7
Unaudited Notes to Consolidated Financial Statements	9
Item  2 – Management’s Discussion and Analysis of Financial Condition and Results of Operations	40
Item 3 – Quantitative and Qualitative Disclosures About Market Risk	53
Item 4 – Controls and Procedures	54
Part II – Other Information
Item 1 – Legal Proceedings	55
Item 1A – Risk Factors	55
Item 2 – Unregistered Sales of Equity Securities and Use of Proceeds	63
Item 3 – Defaults Upon Senior Securities	64
Item 4 – Mine Safety Disclosures	64
Item 5 – Other Information	64
Item 6 – Exhibits	64
Signature	65

2

INERGY, L.P. AND SUBSIDIARIES (FORMERLY CRESTWOOD GAS SERVICES GP LLC) CONSOLIDATED BALANCE SHEETS (in millions, except unit information)
	June 30, 2013		December 31, 2012
	(unaudited)
Assets
Current assets:
Cash and cash equivalents	$	2.7	$	0.1
Accounts receivable, less allowance for doubtful accounts of $1.3 million      at June 30, 2013	182.4		45.4
Inventory (Note 3)	53.2		—
Assets from price risk management activities	15.3		—
Prepaid expenses and other current assets	22.5		4.9
Assets held for sale (Note 3)	6.7		—
Total current assets	282.8		50.4
Property, plant and equipment (Note 3)	3,854.7		1,197.4
Less: accumulated depreciation	126.5		95.0
Property, plant and equipment, net	3,728.2		1,102.4
Intangible assets (Note 3)	1,119.2		845.2
Less: accumulated amortization	70.6		49.9
Intangible assets, net	1,048.6		795.3
Goodwill	2,452.3		352.2
Other assets	53.8		1.3
Total assets	$	7,565.7	$	2,301.6
Liabilities and partners’ capital
Current liabilities:
Accounts payable	$	151.6	$	5.4
Accrued expenses and other liabilities	115.5		43.1
Liabilities from price risk management activities	8.0		—
Current portion of long-term debt (Note 7)	2.5		—
Total current liabilities	277.6		48.5
Long-term debt, less current portion (Note 7)	1,873.1		685.2
Other long-term liabilities	39.0		17.2
Deferred income taxes	20.0		—
Partners’ capital (Note 8):
Limited partner unitholders (171,109,549 and 39,491,002 limited partner units issued and outstanding at June 30, 2013 and December 31, 2012, respectively)	1,401.8		31.7
Total Inergy, L.P. partners’ capital	1,401.8		31.7
Interest of non-controlling partners in subsidiaries	3,954.2		1,519.0
Total partners’ capital	5,356.0		1,550.7
Total liabilities and partners’ capital	$	7,565.7	$	2,301.6

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

3

INERGY, L.P. AND SUBSIDIARIES (FORMERLY CRESTWOOD GAS SERVICES GP LLC) CONSOLIDATED STATEMENTS OF OPERATIONS (in millions, except unit and per unit data) (unaudited)
	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2013			2012			2013			2012
Revenues:
Gathering and processing	$	71.1		$	55.2		$	143.5		$	109.0
NGL and crude services	38.1			—			38.1			—
Storage and transportation	9.7			—			9.7			—
	118.9			55.2			191.3			109.0
Cost of product/services sold (excluding depreciation, amortization and accretion as shown below):
Gathering and processing	14.0			7.4			27.5			16.4
NGL and crude services	36.7			—			36.7			—
Storage and transportation	1.3			—			1.3			—
	52.0			7.4			65.5			16.4
Expenses:
Operating and administrative	31.1			18.0			51.9			34.5
Depreciation, amortization and accretion	28.0			19.1			50.4			35.0
	59.1			37.1			102.3			69.5
Other operating income:
Gain on contingent consideration	—			6.8			—			6.8
Operating income	7.8			17.5			23.5			29.9
Interest and debt expense, net	12.0			8.9			23.4			16.5
Income (loss) before income taxes	(4.2		)	8.6			0.1			13.4
Provision for income taxes	0.3			0.3			0.7			0.6
Net income (loss)	(4.5		)	8.3			(0.6		)	12.8
Net (income) loss attributable to non-controlling partners	6.1			(4.9		)	7.3			(6.1		)
Net income attributable to Inergy, L.P.	$	1.6		$	3.4		$	6.7		$	6.7
Limited partners' interest information:
Subordinated unitholders' interest in net income	$	0.1		$	0.4		$	0.6		$	0.7
Common unitholders' interest in net income	$	1.5		$	3.0		$	6.1		$	6.0
Net income per limited partner unit:
Basic	$	0.03		$	0.09		$	0.14		$	0.17
Diluted	$	0.03		$	0.09		$	0.14		$	0.17
Weighted-average limited partners’ units outstanding (in thousands):
Basic	52,459			35,103			43,829			35,103
Dilutive units	4,388			4,388			4,388			4,388
Diluted	56,847			39,491			48,217			39,491

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

4

INERGY, L.P. AND SUBSIDIARIES (FORMERLY CRESTWOOD GAS SERVICES GP LLC) CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (in millions) (unaudited)
	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2013			2012		2013			2012
Net income (loss)	$	(4.5	)	$	8.3	$	(0.6	)	$	12.8
Change in Suburban Propane Partners, L.P. units (Note 2)	(0.2		)	—		(0.2		)	—
Comprehensive income (loss)	$	(4.7	)	$	8.3	$	(0.8	)	$	12.8

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

5

INERGY, L.P. AND SUBSIDIARIES (FORMERLY CRESTWOOD GAS SERVICES GP LLC) CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL (in millions) (unaudited)
	Limited Partners Capital			Non-Controlling Partners			Total Partners’ Capital
Balance at December 31, 2012	$	31.7		$	1,519.0		$	1,550.7
Net proceeds from issuance of common units by Crestwood Midstream Partners LP	—			118.5			118.5
Issuance of Class D units to non-controlling interest	(126.3		)	126.3			—
Issuance of Class C units	0.6			(0.6		)	—
Change in interest in Crestwood Marcellus Midstream LLC	238.9			(238.9		)	—
Invested capital from Inergy, L.P. net of debt (Note 4)	1,388.8			2,484.4			3,873.2
Unit-based compensation charges	0.2			1.8			2.0
Taxes paid for unit-based compensation vesting	—			(0.7		)	(0.7		)
Distributions	(9.3		)	(48.4		)	(57.7		)
Distribution of Class C units to non-controlling interests	(0.1		)	0.1			—
Distribution for additional interest in Crestwood Marcellus Midstream LLC	(129.0		)	—			(129.0		)
Change in Suburban Propane Partners, L.P. units	(0.2		)	—			(0.2		)
Other	(0.2		)	—			(0.2		)
Net income (loss)	6.7			(7.3		)	(0.6		)
Balance at June 30, 2013	$	1,401.8		$	3,954.2		$	5,356.0

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

6

INERGY, L.P. AND SUBSIDIARIES (FORMERLY CRESTWOOD GAS SERVICES GP LLC) CONSOLIDATED STATEMENTS OF CASH FLOWS (in millions) (unaudited)
	Six Months Ended
	June 30,
	2013			2012
Operating activities
Net income (loss)	$	(0.6	)	$	12.8
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and depletion	31.6			23.0
Amortization and accretion	18.8			12.0
Amortization of deferred financing costs	2.2			2.5
Amortization of bond premium	(0.1		)	—
Market adjustment on interest rate swaps	(0.9		)	—
Gain on contingent consideration	—			(6.8		)
Unit-based compensation charges	2.0			1.0
Provision for doubtful accounts	0.1			—
Changes in operating assets and liabilities, net of effects from acquisitions:
Accounts receivable	(3.7		)	4.2
Inventory	(4.7		)	—
Prepaid expenses and other current assets	—			(0.5		)
Accounts payable, accrued expenses and other liabilities	12.7			(6.0		)
Net cash provided by operating activities	57.4			42.2
Investing activities
Acquisitions, net of cash acquired	6.1			(376.8		)
Purchases of property, plant and equipment	(84.1		)	(22.4		)
Net cash used in investing activities	(78.0		)	(399.2		)
The accompanying notes are an integral part of these consolidated financial statements.

7

INERGY, L.P. AND SUBSIDIARIES (FORMERLY CRESTWOOD GAS SERVICES GP LLC) CONSOLIDATED STATEMENTS OF CASH FLOWS (continued) (in millions) (unaudited)
	Six Months Ended
	June 30,
	2013			2012
Financing activities
Proceeds from the issuance of Inergy, L.P. long-term debt	$	41.8		$	—
Proceeds from the issuance of Inergy Midstream, L.P. long-term debt	9.8			—
Proceeds from the issuance of Crestwood Midstream Partners LP long-term debt	247.5			223.7
Proceeds from the issuance of Crestwood Marcellus Midstream LLC long-term debt	69.4			21.0
Principal payments on Inergy, L.P. long-term debt	(21.5		)	—
Principal payments on Inergy Midstream, L.P. long-term debt	(15.5		)	—
Principal payments on Crestwood Midstream Partners LP long-term debt	(154.0		)	(174.7		)
Principal payments on Crestwood Marcellus Midstream LLC long-term debt	(69.0		)	(1.5		)
Contributions from partners	—			247.2
Distributions	(21.1		)	(6.1		)
Distributions paid to non-controlling partners	(48.4		)	(39.4		)
Distributions for additional interest in Crestwood Marcellus Midstream LLC	(129.0		)	—
Payments on capital leases	(2.2		)	(1.4		)
Payments for deferred financing costs	(0.1		)	(6.5		)
Net proceeds from issuance of Crestwood Midstream Partners LP common units	118.5			103.0
Taxes paid for unit-based compensation vesting	(3.0		)	(0.4		)
Net cash provided by financing activities	23.2			364.9
Net increase in cash	2.6			7.9
Cash at beginning of period	0.1			0.8
Cash at end of period	$	2.7		$	8.7
Supplemental schedule of noncash investing and financing activities
Net change to property, plant and equipment through accounts payable and accrued expenses	$	25.9		$	1.1
Acquisitions, net of cash acquired:
Current assets	$	216.6		$	—
Property, plant and equipment	2,554.9			95.1
Intangible assets	273.0			312.4
Goodwill	2,100.1			—
Other assets	51.2			—
Current liabilities	(205.5		)	(12.7		)
Debt	(1,079.3		)	(18.0		)
Invested capital of Inergy, L.P., net of debt (Note 4)	(3,873.2		)	—
Other liabilities	(43.9		)	—
Total acquisitions, net of cash acquired	$	(6.1	)	$	376.8

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

8

INERGY, L.P. AND SUBSIDIARIES (FORMERLY CRESTWOOD GAS SERVICES GP LLC)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Note 1 – Partnership Organization and Basis of Presentation

Organization

Inergy, L.P. (“Inergy”, "NRGY" or the “Company”), a Delaware limited partnership formed in March 2001, is an energy midstream company. Its common units are listed on the New York Stock Exchange (“NYSE”) under the symbol “NRGY.” Inergy is managed by its general partner, Inergy GP, LLC, which is indirectly owned by Crestwood Holdings LLC (“Crestwood Holdings”). The substantial majority of Crestwood Holdings is indirectly owned by First Reserve Management, LP, an energy-focused private equity fund (“FRC”).

Inergy conducts a significant part of its consolidated operations through two publicly-traded master limited partnerships, Inergy Midstream, L.P. (“Inergy Midstream” or “NRGM”) and Crestwood Midstream Partners LP (“Crestwood Midstream” or “CMLP”). These master limited partnerships are managed by their general partners, and Inergy owns the general partners of Inergy Midstream and Crestwood Midstream. Inergy therefore manages and controls Inergy Midstream, whose common units are listed on the NYSE under the symbol “NRGM,” and Crestwood Midstream, whose common units are listed on the NYSE under the symbol “CMLP.”

In addition to managing and controlling both NRGM and CMLP, Inergy also owns the incentive distribution rights (“IDRs”) of Inergy Midstream and Crestwood Midstream. The IDRs of Inergy Midstream entitle Inergy to receive 50% of all distributions paid by Inergy Midstream in excess of its initial quarterly distribution of $0.37 per common unit. The GP interest of CMLP entitles Inergy to receive 1.8% of all distributions paid by Crestwood Midstream. The IDRs of CMLP entitle Inergy to receive 15% of all distributions above the first target distribution ($0.345 per common unit), 25% of all distributions above the second target distribution ($0.375 per common unit) and thereafter 50% of all distributions above the third target distribution level of $0.45 per common unit.

The following diagram comprises a simplified depiction of our ownership structure as of June 30, 2013:

9

INERGY, L.P. AND SUBSIDIARIES (FORMERLY CRESTWOOD GAS SERVICES GP LLC)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Unless otherwise indicated, references in this report to “we,” “us,” “our,” “ours,” “our company,” “Inergy,” “the Company” and similar terms refer to either Inergy, L.P. itself or Inergy, L.P. and its consolidated subsidiaries, as the context requires. Unless otherwise indicated, references to (i) Inergy Midstream refer to either Inergy Midstream, L.P. itself or Inergy Midstream, L.P. and its consolidated subsidiaries, and (ii) Crestwood Midstream refer to either Crestwood Midstream Partners LP itself or Crestwood Midstream Partners LP and its consolidated subsidiaries, in each case, as the context requires.

10

INERGY, L.P. AND SUBSIDIARIES (FORMERLY CRESTWOOD GAS SERVICES GP LLC)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Business Combination

On May 5, 2013, Inergy and certain of its affiliates entered into a series of definitive agreements with Crestwood Holdings and certain of its affiliates under which, among other things, (i) Inergy agreed to distribute to its common unitholders all of the NRGM common units owned by Inergy; (ii) Crestwood Holdings agreed to acquire the owner of Inergy's general partner; (iii) Crestwood Holdings agreed to contribute ownership of CMLP's general partner and IDRs to Inergy in exchange for common and subordinated units of Inergy; and (iv) Crestwood Midstream agreed to merge with and into a subsidiary of Inergy Midstream in a merger in which CMLP unitholders will receive 1.07 NRGM common units for each CMLP common unit they own. As part of the merger, which is expected to close in 2013, CMLP's unaffiliated unitholders will also receive a one-time $35 million cash payment at the closing of the merger, $25 million of which will be payable by NRGM and $10 million of which will be payable by Crestwood Holdings.

On June 5, 2013, Crestwood Midstream's general partner distributed to a wholly-owned subsidiary of Crestwood Holdings LLC approximately 137,105 common units and approximately 21,588 Class D units of CMLP, representing all of the CMLP common and Class D units held by Crestwood Midstream's general partner.

On June 18, 2013, Inergy distributed to its unitholders approximately 56.4 million NRGM common units, representing all of the NRGM common units held by Inergy.

On June 19, 2013, Crestwood Holdings acquired the owner of Inergy's general partner and contributed to Inergy ownership of Crestwood Gas Services GP, LLC ("CMLP GP"), which owns 100% of the general partnership interests and IDRs of Crestwood Midstream. Crestwood Holdings and its ultimate parent company, FRC, acquired control of Inergy as a result of these transactions.

Description of Business

Inergy provides gathering, processing, storage and transportation solutions to customers in the crude oil, natural gas liquids (“NGLs”) and natural gas sectors of the energy industry. Inergy's financial statements reflect three operating and reporting segments: (i) gathering and processing; (ii) NGL and crude services; and (iii) storage and transportation.

Inergy's gathering and processing (“G&P) operations provide natural gas gathering, processing, treating, compression and transportation services to producers in unconventional shale plays in West Virginia, Texas, Arkansas, New Mexico and Louisiana. The consolidated assets reflected in this segment include rich gas gathering systems and processing plants in the Marcellus Shale, Barnett Shale, Granite Wash, and Avalon Shale plays, and dry gas gathering systems in the Barnett Shale, Fayetteville Shale, and Haynesville Shale plays.

Inergy's NGL and crude services operations provide NGL marketing, supply and logistics services to producers, refiners, petrochemical companies, marketers, and others customers. The consolidated assets reflected in this segment primarily include a crude oil loading and storage terminal (the “COLT Hub”), the West Coast operations, and a fleet of over-the-road truck and rail transports.

Inergy's storage and transportation operations provide natural gas and NGL storage and transportation services to third parties, as well as the production and sale of salt products. The consolidated assets reflected in this segment primarily include natural gas storage facilities in New York and Texas (the Stagecoach, Thomas Corners, Steuben, Seneca Lake and Tres Palacios storage facilities), natural gas transmission facilities in New York and Pennsylvania (the North-South Facilities, the MARC I Pipeline, and the East Pipeline), an NGL storage facility in New York (the Bath storage facility), and a solution-mining and salt production company in New York (US Salt).

Inergy owns and operates the Tres Palacios storage facility, a fractionation facility on the West Coast and an NGL supply and logistics business.

11

INERGY, L.P. AND SUBSIDIARIES (FORMERLY CRESTWOOD GAS SERVICES GP LLC)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Basis of Presentation

These financial statements were originally the financial statements of CMLP GP, prior to being acquired by Inergy on June 19, 2013 as discussed above. Inergy's acquisition of CMLP GP was accounted for as a reverse acquisition under the purchase method of accounting in accordance with FASB Accounting Standard Codification Subtopic 805 - Business Combinations. The accounting for a reverse acquisition results in the legal acquiree (CMLP GP) being the acquiror for accounting purposes. Although CMLP GP was the surviving entity for accounting purposes, Inergy was the surviving entity for legal purposes, consequently, the name on these financial statements was changed from Crestwood Gas Services GP, LLC to Inergy, L.P.

On June 18, 2013, Inergy changed its fiscal year from September 30 to December 31 to adopt the fiscal year of CMLP GP.

The financial information contained herein as of June 30, 2013, and for the three-month and six-month periods endedJune 30, 2013 and 2012, is unaudited. Inergy believes this information has been prepared in accordance with accounting principles generally accepted in the United States for interim financial information and Article 10 of Regulation S-X. Inergy also believes this information includes all adjustments (consisting only of normal recurring adjustments) necessary to present fairly the financial position, results of operations and cash flows for the periods then ended.

The accompanying consolidated financial statements should be read in conjunction with the Form 10-K as filed with the Securities and Exchange Commission for the fiscal year ended September 30, 2012 as well as the Form 8-K/A filed August 5, 2013, containing consolidated financial statements related to CMLP GP.

The accompanying consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries, including among others Inergy Partners, LLC (“Inergy Partners”), Tres Palacios Gas Storage LLC (“TPGS”), IPCH Acquisition Corp. (“IPCHA”), Inergy Finance Corp., Inergy Operations, LLC, NRGM GP, LLC and CMLP GP. The accompanying consolidated financial statements also include the accounts of Inergy Midstream and Crestwood Midstream and each of their consolidated subsidiaries.

All significant intercompany transactions and balances have been eliminated in consolidation.

Note 2 – Summary of Significant Accounting Policies

Financial Instruments and Price Risk Management

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

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

Inergy had no derivatives identified as fair value hedges for accounting purposes in the three-month and six-month periods endedJune 30, 2012 and 2013.

12

INERGY, L.P. AND SUBSIDIARIES (FORMERLY CRESTWOOD GAS SERVICES GP LLC)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Inergy also enters into derivative financial instruments that may qualify as cash flow hedges, which hedge the exposure of variability in expected future cash flows predominantly attributable to variable interest payments. These derivatives are recorded on the balance sheet at fair value as other assets or other long-term 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. In certain situations under the rules, the ineffective portion of the gain or loss is recognized as cost of product sold/services sold or interest expense in the current period. Inergy did not have any derivatives identified as cash flow hedges in the three and six-month periods ended June 30, 2012 and 2013.

Accumulated other comprehensive loss was $0.2 million at June 30, 2013. Included in accumulated other comprehensive loss at June 30, 2013 was a loss of $0.2 million attributable to Suburban Propane Partners, LP ("SPH") units. The SPH units were acquired by Inergy in August 2012 in conjunction with the disposition of its retail propane business.

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

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

Revenue Recognition

Inergy's gathering and processing operations gather, process, treat, compress, transport and sell natural gas pursuant to fixed-fee and percent-of-proceeds contracts. For fixed-fee contracts, Inergy recognizes revenues based on the volume of natural gas gathered, processed and treated or compressed. For percent-of-proceeds contracts, Inergy recognizes revenues based on the value of products sold to third parties. Inergy recognizes revenues for these services and products when all of the following criteria are met:

• services have been rendered or products delivered;

• persuasive evidence of an exchange arrangement exists;

• the price for services is fixed or determinable; and

• collectability is reasonably assured.

Sales of NGLs and salt are recognized at the time product is shipped or delivered to the customer depending on the sales terms. NGL processing and fractionation fees are recognized upon delivery of the product. Revenues from the COLT Hub are recognized when the contractual services are provided, such as loading of customer rail cars. Revenues from storage and transportation contracts are recognized during the period in which the storage and transportation services are provided, such as providing storage and transportation services during the period a firm service contract is in place.

Use of Estimates

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

Inventory

Inventory for NGL and crude services operations, which mainly consist of NGLs, are stated at the lower of cost or market and are computed using the average cost method. Inventory for storage and transportation operations are stated at the lower of cost or market and are computed predominantly using the average cost method. Inergy had no inventory at December 31, 2012.

Shipping and Handling Costs

Shipping and handling costs are recorded as part of cost of product/services sold at the time product is shipped or delivered to the customer.

13

INERGY, L.P. AND SUBSIDIARIES (FORMERLY CRESTWOOD GAS SERVICES GP LLC)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Property, Plant and Equipment

Property, plant and equipment is recorded at its original cost of construction or, upon acquisition, at fair value of the assets acquired. For assets Inergy constructs, it capitalizes direct costs, such as labor and materials, and indirect costs, such as overhead and interest. Inergy capitalizes major units of property replacements or improvements and expenses minor items. Depreciation is computed by the straight-line method over the estimated useful lives of the assets, as follows:

	Years
Gathering systems	20
Processing plants and compression facilities	20 – 25
Buildings, rights-of-way, easements and storage rights	20 – 70
Office furniture and equipment	5 – 10
Vehicles	5
Pipelines	20
Base gas	10

Salt deposits are depleted utilizing the unit of production method.

Identifiable Intangible Assets

The Company has recorded certain identifiable intangible assets, including customer accounts, trademarks, deferred financing costs and gas gathering, compression and processing contracts. Customer accounts and trademarks have arisen from acquisitions. Deferred financing costs represent financing costs incurred in obtaining financing and are being amortized over the term of the related debt using the effective interest method. The Company recognizes acquired intangible asset separately 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.

Customer accounts and trademarks are generally amortized on a straight-line basis over their estimated economic lives, typically 8 years - 12 years and 5 years - 10 years, respectively. The gas gathering, compression and processing contracts are generally amortized based on the projected cash flows associated with the contracts, typically 5 years - 20 years.

Goodwill

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

Inergy completed its annual impairment test for each of its reporting units and determined that no impairment existed as of December 31, 2012. No indicators of impairment were identified requiring an interim impairment test during the six-month period ended June 30, 2013.

Income Taxes

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

14

INERGY, L.P. AND SUBSIDIARIES (FORMERLY CRESTWOOD GAS SERVICES GP LLC)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Inergy is responsible for its portion of the Texas Margin tax that is included in Crestwood Holdings' consolidated Texas franchise tax return. Inergy's current tax liability will be assessed based on 0.7% of the gross revenue apportioned to Texas. The margin tax qualifies as an income tax under GAAP, which requires Inergy to recognize the impact of this tax on the temporary differences between the financial statement assets and liabilities and their tax basis attributable to such tax.

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

Sales Tax

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

Income Per Unit

Inergy calculates basic net income per limited partner unit by utilizing the two class method. Diluted net income per limited partner unit is computed by dividing net income attributable to the limited partners by the weighted-average number of units outstanding and the effect of dilutive units granted in the Inergy acquisition of CMLP GP. Net income attributable to the limited partners is determined by first allocating to Inergy, L.P. the earnings from the general partner and IDR interests from NRGM and CMLP with the remaining earnings allocated according to the capital accounts. The weighted average number of units outstanding is calculated based on the presumption that the common and subordinated units issued to acquire CMLP GP (the accounting predecessor) were outstanding for the entire period prior to the June 19, 2013 acquisition. On the date of the acquisition, all of NRGY's limited partner units are considered outstanding.

Accrued Additions to Property, Plant and Equipment

The Company has accrued for property, plant and equipment, including certain construction work in process relating to construction efforts on various growth projects. At June 30, 2013 and December 31, 2012, the Company had accrued $45.1 million and $9.2 million relating to property, plant and equipment classified as accrued expenses on the consolidated balance sheets.

Asset Retirement Obligations

An asset retirement obligation ("ARO") is an estimated liability for the cost to retire a tangible asset. Inergy records a liability for legal or contractual obligations to retire its long-lived assets associated with right-of-way contracts it holds and its facilities whether owned or leased. Inergy records a liability in the period the obligation is incurred and estimable. An ARO is initially recorded at its estimated fair value with a corresponding increase to property, plant and equipment. This increase in property, plant and equipment is then depreciated over the useful life of the asset to which that liability relates. An ongoing expense is recognized for changes in the value of the liability as a result of the passage of time, which Inergy records as depreciation, amortization and accretion expense on its consolidated statements of operations. The fair value of certain AROs could not be determined as settlement dates (or range of dates) associated with these assets were not estimable. The net AROs were $14.4 million and $14.0 million at June 30, 2013 and December 31, 2012, respectively, and are included in other long-term liabilities on the consolidated balance sheets.

Environmental Costs and Other Contingencies

Inergy recognizes liabilities for environmental and other contingencies when it has an exposure that indicates it is both probable that a liability has been incurred and the amount of loss can be reasonably estimated. Where the most likely outcome of a contingency can be reasonably estimated, Inergy accrues a liability for that amount. Where the most likely outcome cannot be estimated, a range of potential losses is established and if no one amount in that range is more likely than any other, the low end of the range is accrued.

15

INERGY, L.P. AND SUBSIDIARIES (FORMERLY CRESTWOOD GAS SERVICES GP LLC)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Inergy records liabilities for environmental contingencies at their undiscounted amounts on its consolidated balance sheets as accrued expenses and other liabilities when environmental assessments indicate that remediation efforts are probable and costs can be reasonably estimated. Estimates of Inergy's liabilities are based on currently available facts and presently enacted laws and regulations, taking into consideration the likely effects of other societal and economic factors. These estimates are subject to revision in future periods based on actual costs or new circumstances. Inergy capitalizes costs that benefit future periods and recognize a current period charge in operation and maintenance expense when clean-up efforts do not benefit future periods.

Inergy evaluates potential recoveries of amounts from third parties, including insurance coverage, separately from its liability. Recovery is evaluated based on the solvency of the third party, among other factors. When recovery is assured, Inergy records and reports an asset separately from the associated liability on its consolidated balance sheet.

Accounting for Unit-Based Compensation

Unit-based compensation awards are valued at the closing market price of our common units on the date of grant, which reflects the fair value of such awards. For those awards that are settled in cash, the associated liability is remeasured at every balance sheet date through settlement, such that the vested portion of the liability is adjusted to reflect its revised fair value through compensation expense. Inergy generally recognizes the expense associated with the award over the vesting period. At the time of issuance of phantom units, management of the General Partner determines whether they will be settled in cash or settled in common units. Unit-based compensation awards at Inergy Midstream and Crestwood Midstream are fully reflected in these financial statements and are accounted for in the manner described above.

The amount of compensation expense recorded by the Company was $1.4 million and $0.5 million during the three months endedJune 30, 2013 and 2012, respectively, and $2.0 million and $1.0 million during the six months endedJune 30, 2013 and 2012, respectively.

Segment Information

There are certain accounting requirements that establish standards for reporting information about operating segments, as well as related disclosures about products and services, geographic areas and major customers. Further, they define operating segments as components of an enterprise for which separate financial information is available that is evaluated regularly by the chief operating decision maker in deciding how to allocate resources and assess performance. In determining its operating segments, Inergy examined the way it organizes its business internally for making operating decisions and assessing business performance. See Note 10 for disclosures related to Inergy’s three operating and reporting segments.

Fair Value

Cash and Cash Equivalents, Accounts Receivable and Accounts Payable

As of June 30, 2013 and December 31, 2012, the carrying amounts of cash and cash equivalents, accounts receivable (net of allowance for doubtful accounts) and accounts payable represent fair value due to their liquid and short-term nature.

Credit Facilities

The fair value of the Company's credit agreement and all of its credit facilities approximates their carrying amounts as of June 30, 2013 and December 31, 2012 due primarily to the variable nature of the interest rates of the instruments.

16

INERGY, L.P. AND SUBSIDIARIES (FORMERLY CRESTWOOD GAS SERVICES GP LLC)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Senior Notes

Inergy estimates the fair value of its senior notes primarily based on quoted market prices for the same or similar issuances. This valuation methodology is considered level 2 in the fair value hierarchy. The following table reflects the carrying value and fair value of the senior notes (in millions):

	June 30, 2013				December 31, 2012
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Inergy senior unsecured notes	$	11.5	$	11.8	$	—	$	—
CMLP senior notes	$	351.3	$	362.5	$	351.5	$	365.9
NRGM senior unsecured notes	$	500.0	$	494.7	$	—	$	—

See Note 6 for a discussion of the Company's assets and liabilities recorded at fair value on the balance sheet.

Recently Issued Accounting Pronouncements

On December 16, 2011, the Financial Accounting Standards Board issued ASU No. 2011-11, “Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities.” This ASU requires disclosures to provide information to help reconcile differences in the offsetting requirements under U.S. Generally Accepted Accounting Principles and International Financial Reporting Standards. The disclosure requirements of this ASU mandate that entities disclose both gross and net information about financial instruments and transactions eligible for offset in the statement of financial position as well as instruments and transactions subject to an enforceable master netting arrangement or similar agreement. ASU No. 2011-11 also requires disclosure of collateral received and posted in connection with master netting arrangements or similar arrangements. The scope of this ASU includes derivative contracts, repurchase agreements, and securities borrowing and lending arrangements. Entities are required to apply the amendments of ASU No. 2011-11 for annual reporting periods beginning on or after January 1, 2013, and interim periods within those annual periods. All disclosures provided by those amendments are required to be provided retrospectively for all comparative periods presented. The Company adopted the effects of ASU No. 2011-11 on January 1, 2013.

On February 5, 2013, the FASB issued ASU No. 2013-02, “Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income.” This ASU amends and clarifies the disclosure requirements prescribed in ASU No. 2011-05, “Comprehensive Income (Topic 220): Presentation of Comprehensive Income.” ASU No. 2013-02 requires that entities present information about reclassification adjustments from accumulated other comprehensive income in their annual financial statements in a single note or on the face of the financial statements. Public entities will also have to provide this information in their interim financial statements. Specifically, entities must present, either in a single note or parenthetically on the face of the financial statements, the effect of significant amounts reclassified from each component of accumulated other comprehensive income based on its source and the income statement line items affected by the reclassification. If a component is not required to be reclassified to net income in its entirety, entities would instead cross reference to the related footnote for additional information.  The Company adopted the requirements of ASU No. 2013-02 on January 1, 2013 and presented the required information in a single note.

Note 3 – Certain Balance Sheet Information

Inventory consisted of the following at June 30, 2013 and December 31, 2012, respectively (in millions):

	June 30, 2013		December 31, 2012
NGLs	$	46.8	$	—
Parts, supplies and other	6.4		—
Total inventory	$	53.2	$	—

17

INERGY, L.P. AND SUBSIDIARIES (FORMERLY CRESTWOOD GAS SERVICES GP LLC)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Property, plant and equipment consisted of the following at June 30, 2013 and December 31, 2012, respectively (in millions):

	June 30, 2013		December 31, 2012
Gathering systems	$	622.6	$	582.3
Processing plants and compression facilities	507.3		485.4
Plant equipment	659.5		—
Buildings, rights-of-way, easements and storage rights	102.8		66.4
Land	779.6		4.1
Pipelines	650.4		—
Vehicles	32.1		0.3
Construction in process	280.6		56.0
Base gas	109.1		—
Salt deposits	102.0		—
Office furniture and equipment	8.7		2.9
	3,854.7		1,197.4
Less: accumulated depreciation	126.5		95.0
Total property, plant and equipment, net	$	3,728.2	$	1,102.4

Inergy had capital lease assets of $11.6 million and $11.8 million included in property, plant and equipment at June 30, 2013 and December 31, 2012, respectively.

Intangible assets consisted of the following at June 30, 2013 and December 31, 2012, respectively (in millions):

	June 30, 2013		December 31, 2012
Customer accounts	$	239.0	$	—
Gas gathering, compression and processing contracts	813.1		813.0
Trademarks	34.0		—
Deferred financing and other costs	33.1		32.2
	1,119.2		845.2
Less: accumulated amortization	70.6		49.9
Total intangible assets, net	$	1,048.6	$	795.3

Assets Held for Sale

In June 2013, CMLP entered into an agreement to sell a cryogenic plant and associated equipment for approximately $11 million, net of fees. At June 30, 2013, the Company has classified these assets as held for sale at their historical book value of $6.7 million. The Company completed this sale on July 25, 2013.

Note 4 – Business Acquisitions

As described in Note 1, the Company's acquisition of CMLP GP was accounted for as a reverse acquisition under the purchase method of accounting in accordance with FASB Accounting Standard Codification Subtopic 805 - Business Combinations. This accounting treatment requires the accounting acquiree (Inergy) to have its assets and liabilities stated at fair value as well as any other purchase accounting adjustments as of the date of the acquisition, June 19, 2013. The fair value of Inergy was calculated based on the consolidated enterprise value of Inergy as of June 19, 2013. This consolidated enterprise value was based on the stock prices of NRGY and NRGM, the value of the outstanding senior notes based on quoted market prices for same or similar issuances and the value of the outstanding floating rate debt. Our preliminary purchase allocation is subject to material change pending the completion of the valuation of assets acquired and liabilities assumed.

18

The following table summarizes the estimated fair values of the assets acquired and liabilities assumed at the acquisition date (in millions):

	June 19, 2013
Current assets	$	222.7
Property, plant and equipment	2,554.9
Intangible assets	273.0
Other assets	51.2
Total identifiable assets acquired	3,101.8
Current liabilities	205.5
Long-term debt	1,079.3
Other long-term liabilities	43.9
Total liabilities assumed	1,328.7
Net identifiable assets acquired	1,773.1
Goodwill	2,100.1
Net assets acquired	$	3,873.2

The $2,100.1 million of goodwill is reflected in Inergy's NGL and crude services segment and storage and transportation segment. Goodwill recognized in the transaction relates primarily to synergies and new expansion opportunities expected upon completion of the integration of Inergy and CMLP GP.  Based on the preliminary purchase price allocation, amortization expenses relative to the intangible assets acquired are expected to be $28.9 million for each of the years ended December 31, 2013 through December 31, 2017.

The following table represents the pro forma consolidated statements of operations as if the Inergy reverse acquisition had been included in the consolidated results of the Company for the full three-month periods ended June 30, 2013 and 2012 and for the full six-month periods ended June 30, 2013 and 2012 (in millions, except per unit information):

	Pro Forma Consolidated Statement of Operations  (Unaudited)
	Three Months Ended  June 30,					Six Months Ended  June 30,
	2013			2012 (a)		2013			2012 (a)
Revenues	$	389.9		$	297.4	$	912.7		$	692.3
Net income (loss)	$	(37.1	)	$	18.9	$	(27.6	)	$	32.6
Net income (loss) per limited partner unit:
Basic	$	(0.51	)	$	0.25	$	(0.49	)	$	0.48
Diluted	$	(0.51	)	$	0.25	$	(0.49	)	$	0.48

(a) The three and six month periods ended June 30, 2012 have also been adjusted to reflect the contribution of Inergy's retail operations on August 1, 2012 as if that contribution had been removed from the consolidated results of operations at the beginning of each period presented.

19

These amounts have been calculated after applying the Company's accounting policies and adjusting the results of the Inergy reverse acquisition to reflect the depreciation and amortization that would have been charged assuming the preliminary fair value adjustments to property, plant and equipment and intangible assets had been made at the beginning of the current period. The purchase price allocation for the Inergy reverse acquisition has been prepared on a preliminary basis pending final asset valuation and asset rationalization, and changes are expected when additional information becomes available. Accordingly, the purchase accounting adjustments made in connection with the development of the unaudited pro forma are preliminary and subject to change.

Note 5 – Risk Management

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

Commodity Derivative Instruments and Price Risk Management

Risk Management Activities

Inergy sells NGLs to energy related businesses and may use a variety of financial and other instruments including forward contracts involving physical delivery of NGLs. Inergy will enter into offsetting positions to economically hedge against the exposure its customer contracts create, however does not designate these instruments as hedging instruments for accounting purposes. These instruments are marked to market with the changes in the market value reflected in cost of product/services sold. Inergy attempts to balance its contractual portfolio in terms of notional amounts and timing of performance and delivery obligations. This balance in the contractual portfolio significantly reduces the volatility in cost of product/services sold related to these instruments.

Fair Value Hedging Activity

Inergy will enter into derivative instruments to hedge its exposure to fluctuating commodity prices that results from maintaining its NGL inventory. Inergy may choose to designate these instruments as fair value hedges for accounting purposes. This accounting treatment requires the fair value changes in both the derivative instruments and the hedged inventory to be recorded in cost of product/services sold.

A significant amount of inventory held in bulk storage facilities is hedged as it is not expected to be sold in the immediate future and is therefore exposed to fluctuations in commodity prices.

Inergy did not have any derivative instruments designated as fair value hedges for accounting purposes in the three and six month periods ended June 30, 2013 and 2012.

Commodity Price and Credit Risk

Notional Amounts and Terms

The notional amounts and terms of the Company’s derivative financial instruments include the following at June 30, 2013 and December 31, 2012, respectively (in millions):

	June 30, 2013		December 31, 2012
	Fixed Price Payor	Fixed Price Receiver	Fixed Price Payor	Fixed Price Receiver
Propane, crude and heating oil (barrels)	4.8	5.8	—	—

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

20

INERGY, L.P. AND SUBSIDIARIES (FORMERLY CRESTWOOD GAS SERVICES GP LLC)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

All contracts subject to price risk had a maturity of twenty-eight months or less; however, 96.8% of the contracts expire within twelve months.

Credit Risk

Inherent in the Company's contractual portfolio are certain credit risks. Credit risk is the risk of loss from nonperformance by suppliers, customers or financial counterparties to a contract. Inergy takes an active role in managing credit risk and has established control procedures, which are reviewed on an ongoing basis. The Company attempts to minimize credit risk exposure through credit policies and periodic monitoring procedures as well as through customer deposits, letters of credit and entering into netting agreements that allow for offsetting counterparty receivable and payable balances for certain financial transactions, as deemed appropriate. The counterparties associated with assets from price risk management activities as of June 30, 2013 were energy marketers and propane retailers, resellers and dealers. There were no activities associated with assets from price risk management at December 31, 2012.

Certain of the Company's derivative instruments have credit limits that require the Company to post collateral. The amount of collateral required to be posted is a function of the net liability position of the derivative as well as the Company's established credit limit with the respective counterparty. If the Company's credit rating were to change, the counterparties could require the Company to post additional collateral. The amount of additional collateral that would be required to be posted would vary depending on the extent of change in the Company's credit rating as well as the requirements of the individual counterparty. The aggregate fair value of all commodity derivative instruments with credit-risk-related contingent features that are in a liability position on June 30, 2013, is $2.5 million for which the Company has posted $0.8 million of collateral in the normal course of business. The Company has posted $4.1 million of NYMEX margin deposit in the normal course of business. The Company has received collateral of $5.1 million in the normal course of business. All collateral amounts have been netted against the asset or liability with the respective counterparty.

Note 6 – Fair Value Measurements

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

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

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

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

As of June 30, 2013, the Company held certain assets and liabilities that are required to be measured at fair value on a recurring basis. These included the Company’s derivative instruments related to heating oil, crude oil, NGLs and interest rates. The Company’s derivative instruments consist of forwards, swaps, futures, physical exchanges and options.

21

INERGY, L.P. AND SUBSIDIARIES (FORMERLY CRESTWOOD GAS SERVICES GP LLC)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

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

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

The Company’s OTC options are valued based on the Black Scholes option pricing model that considers time value and volatility of the underlying commodity. The inputs utilized in the model are based on publicly available information as well as broker quotes. These options have been categorized as level 2.

The assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company's assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

The following tables set forth by level within the fair value hierarchy the Company's assets and liabilities that were accounted for at fair value on a recurring basis at June 30, 2013 (in millions):

	June 30, 2013
	Fair Value of Derivatives
	Level 1		Level 2		Level 3		Total		Designated as Hedges		Not Designated as Hedges		Netting Agreements(a)			Total
Assets
Assets from price risk management	$	0.1	$	21.1	$	—	$	21.2	$	—	$	21.2	$	(5.9	)	$	15.3
SPH units	6.6		—		—		6.6		—		—		—			6.6
Total assets at fair value	$	6.7	$	21.1	$	—	$	27.8	$	—	$	21.2	$	(5.9	)	$	21.9
Liabilities
Liabilities from price risk management	$	0.2	$	11.1	$	—	$	11.3	$	—	$	11.3	$	(3.3	)	$	8.0
Interest rate swaps	—		5.1		—		5.1		—		—		—			5.1
Total liabilities at fair value	$	0.2	$	16.2	$	—	$	16.4	$	—	$	11.3	$	(3.3	)	$	13.1

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

The Company had no assets or liabilities recorded at fair value at December 31, 2012.

22

INERGY, L.P. AND SUBSIDIARIES (FORMERLY CRESTWOOD GAS SERVICES GP LLC)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Note 7 – Long-Term Debt

Long-term debt consisted of the following at June 30, 2013 and December 31, 2012, respectively (in millions):

	June 30, 2013		December 31, 2012
NRGY credit agreement	$	340.3	$	—
NRGY senior unsecured notes	11.5		—
NRGY obligations under noncompetition agreements and notes to former owners of businesses acquired	2.9		—
CMLP credit facility	300.2		206.7
CMLP senior notes	350.0		350.0
CMLP premium on senior notes	1.3		1.5
CMM credit facility	127.4		127.0
NRGM credit facility	237.0		—
NRGM senior unsecured notes	500.0		—
Fair value adjustment of NRGM senior unsecured notes	5.0		—
Total debt	1,875.6		685.2
Less: current portion	2.5		—
Total long-term debt	$	1,873.1	$	685.2

At June 30, 2013, each of Inergy, Inergy Midstream, Crestwood Midstream and Crestwood Marcellus Midstream LLC (CMM), a wholly-owned subsidiary of Crestwood Midstream, was in compliance with the debt covenants in their respective credit facilities and senior notes, as described below.

Inergy and its subsidiaries do not provide credit support or guarantee any amounts outstanding under NRGM's or CMLP's credit facilities or senior notes. NRGM, CMLP and their respective subsidiaries do not provide credit support or guarantee any amounts outstanding under Inergy's credit facility or senior notes.

NRGY Credit Facility

Inergy utilizes a secured credit facility ("NRGY Credit Facility") with an aggregate revolving loan facility of $550 million to fund working capital requirements and as a source of capital to fund capital expenditures and acquisitions. All borrowings under the NRGY Credit Facility are generally secured by substantially all of Inergy's assets and the equity interests in all of Inergy's wholly owned subsidiaries, and loans thereunder bear interest, at Inergy's option, subject to certain limitations, at a rate equal to the following:

• the Alternate Base Rate, which is defined as the higher of (i) the federal funds rate plus 0.50%; (ii) JP Morgan's prime rate; or (iii) the Adjusted LIBO Rate plus 1%; plus a margin varying from 0.75% to 2.00%; or

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

At June 30, 2013, the balance outstanding under the NRGY Credit Facility was $340.3 million. The interest rates of the NRGY Credit Facility are based on prime rate and LIBOR plus the applicable spreads, resulting in interest rates which were between 1.95% and 4.00% at June 30, 2013. Availability under the NRGY Credit Facility amounted to $166.5 million at June 30, 2013. Outstanding standby letters of credit under the credit facility amounted to $43.2 million at June 30, 2013.

The credit agreement governing the NRGY Credit Facility contains various covenants and restrictive provisions that limit its ability to, among other things: incur additional debt; make distributions on or redeem or repurchase units; make certain investments and acquisitions; incur or permit certain liens to exist; enter into certain types of transactions with affiliates; merge, consolidate or amalgamate with another company; and transfer or otherwise dispose of assets.

23

INERGY, L.P. AND SUBSIDIARIES (FORMERLY CRESTWOOD GAS SERVICES GP LLC)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

The NRGY Credit Facility contains the following financial covenants:

• the ratio of Inergy's total funded debt (as defined in the credit agreement) to consolidated EBITDA (as defined in the credit agreement) for the four fiscal quarters most recently ended must be no greater than 4.75 to 1.0; and

• the ratio of Inergy's consolidated EBITDA to consolidated interest expense (as defined in the credit agreement), for the four fiscal quarters then most recently ended, must not be less than 2.50 to 1.0.

At June 30, 2013, the total funded debt to consolidated EBITDA was approximately 4.0 to 1.0 and consolidated EBITDA to consolidated interest expense was approximately 10.0 to 1.0.

On May 23, 2013, Inergy obtained from its lenders certain waivers and consents necessary to consummate the transactions that resulted in Crestwood Holdings' acquisition of its general partner and its acquisition of the general partner of Crestwood Midstream. Inergy also amended its credit agreement to, among other things, (i) require Inergy to prepay up to $300 million in aggregate principal amount of borrowings outstanding under the NRGY Credit Facility with net proceeds received by Inergy or its subsidiaries from asset dispositions or insurance proceeds (“Net Proceeds”), (ii) automatically reduce the lenders' revolving loan commitments by an amount equal to the Net Proceeds, and (iii) permit the sale of assets from Inergy to its subsidiaries and to Inergy Midstream and its subsidiaries.

Inergy has entered into six interest rate swaps that mature in 2016 to hedge our exposure to variable interest payments due under the NRGY Credit Facility. These swap agreements require Inergy to pay the counterparty an amount based on fixed rates from 0.84% to 2.52% due quarterly on an aggregate notional amount of $225.0 million. In exchange, the counterparty is required to make quarterly floating interest rate payments on the same date to Inergy based on the three-month LIBOR applied to the same aggregate notional amount of $225.0 million.

NRGY Senior Notes

Inergy has $11.5 million in outstanding senior notes, the majority of which mature on October 1, 2018 and have a coupon rate of 7%. The outstanding senior notes do not contain any financial covenants.

CMLP Credit Facility

In November 2012, CMLP entered into an amended and restated $550 millionfive-year revolving credit facility (“CMLP Credit Facility”). The CMLP Credit Facility is available to fund acquisitions, working capital and internal growth projects and for general partnership purposes. The credit facility includes sub-limits up to $10 million and $100 million for swing loans and letters of credit, respectively.

Borrowings under the CMLP Credit Facility are generally secured by liens on substantially all of the assets of CMLP and its wholly owned subsidiaries, except CMM and its consolidated subsidiaries. The CMLP Credit Agreement is fully and unconditionally guaranteed, jointly and severally, by CMLP's wholly owned subsidiaries other than CMM.

Borrowings under the CMLP Credit Facility bear interest at LIBOR plus an applicable margin or a base rate as defined in the CMLP credit agreement. Under the terms of the CMLP Credit Facility, the applicable margin under LIBOR borrowings was 2.8% and 2.5% at June 30, 2013 and December 31, 2012, respectively. The weighted-average interest rate as of June 30, 2013 and December 31, 2012 was 3.0% and 2.8%, respectively. At June 30, 2013 and December 31, 2012, the balance outstanding under the CMLP Credit Facility was $300.2 million and $206.7 million, respectively. As a result, CMLP had approximately $110.6 million of remaining capacity under the CMLP Credit Facility at June 30, 2013, subject to compliance with any applicable covenants under such facility.

The credit facility requires CMLP to maintain:

• a ratio of consolidated trailing twelve-month EBITDA (as defined in its credit facility) to net interest expense of not less than 2.5 to 1.0; and

• a ratio of total indebtedness to consolidated trailing twelve-month EBITDA (as defined in its credit facility) of not more than 5.0 to 1.0, or not more than 5.5 to 1.0 for up to nine months following certain acquisitions.

24

INERGY, L.P. AND SUBSIDIARIES (FORMERLY CRESTWOOD GAS SERVICES GP LLC)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

At June 30, 2013, consolidated trailing twelve-month EBITDA to net interest expense was 4.1 to 1.0 and total indebtedness to consolidated trailing twelve-month EBITDA was 4.3 to 1.0.

The CMLP Credit Facility contains restrictive covenants that, among other things, prohibit the declaration or payment of distributions by CMLP if a default then exists or would result therefrom, and otherwise limits the amount of distributions that CMLP can make.

CMLP Senior Notes

In April 2011, CMLP and Crestwood Midstream Finance Corporation (“Crestwood Finance” and together with CMLP, the “CMLP Issuers”) issued $200 million in a private offering in aggregate principal amount of their 7.75% Senior Notes due 2019 (the “Initial CMLP Notes”). On November 14, 2012, the CMLP Issuers issued and sold an additional $150 million in a private offering in aggregate principal amount of their 7.75% Senior Notes due 2019 (the “Additional CMLP Notes,” and together with the Initial CMLP Notes, the “CMLP Notes”). The CMLP Notes will mature on April 1, 2019, and interest is payable semi-annually in arrears on April 1 and October 1 of each year. Interest payments commenced on October 1, 2011 and April 1, 2013 for the Initial CMLP Notes and the Additional CMLP Notes, respectively, noting that interest payable on the Additional CMLP Notes' April 1, 2013 payment date commenced accruing on October 1, 2012.

In general, the CMLP Notes are fully and unconditionally guaranteed, joint and severally, on a senior unsecured basis by CMLP's subsidiaries (other than Crestwood Finance and CMM and its subsidiaries). The indenture contains customary release provisions, such as (i) disposition of all or substantially all the assets of, or the capital stock of, a guarantor subsidiary to a third person if the disposition complies with the indenture; (ii) designation of a guarantor subsidiary as an Unrestricted Subsidiary in accordance with its indentures; (iii) legal or covenant defeasance of a series of senior notes, or satisfaction and discharge of the related indenture; and (iv) guarantor subsidiary ceases to guarantee any other indebtedness of CMLP or any other guarantor subsidiary, provided it no longer guarantees indebtedness under the CMLP Credit Facility. CMLP has no independent assets or operations, and Crestwood Finance is a 100% finance subsidiary of CMLP.

The indenture restricts the ability of CMLP and its subsidiaries to, among other things, sell assets; pay distributions on, redeem or repurchase CMLP units, redeem or repurchase subordinated debt; make investments; incur or guarantee additional indebtedness or issue preferred units; create or incur certain liens; enter into agreements that restrict distributions or other payments to CMLP from its restricted subsidiaries; consolidate, merge or transfer all or substantially all of CMLP's assets; and, engage in affiliate transactions; create unrestricted subsidiaries. These restrictions are subject to a number of important exceptions and qualifications, and many of these restrictions will terminate when the senior notes are rated investment grade and no default under the indenture has occurred and is continuing.

The CMLP Notes require CMLP to maintain a ratio of our consolidated trailing twelve-month EBITDA (as defined in the indenture governing the senior notes) to fixed charges of at least 1.75 to 1.0, which at June 30, 2013 was 3.9 to 1.0.

CMM Credit Facility

In March 2012, CMM entered into a $200 million, revolving five-year credit facility (“CMM Credit Facility”). The CMM Credit Facility is available to fund CMM's continued build out of its Marcellus gathering systems. The credit facility includes sub-limits up to $10 million and $25 million for swing loans and letters of credit, respectively. The CMM Credit Facility is secured by all of CMM's assets.

At June 30, 2013, the balance outstanding under the CMM Credit Facility was $127.4 million. At December 31, 2012, the balance outstanding under the CMM Credit Facility was $127.0 million. There were no outstanding standby letters of credit under the CMM Credit Facility at June 30, 2013. As a result, CMM had approximately $72.6 million of remaining capacity at June 30, 2013, subject to compliance with any applicable covenants under such facility.

Borrowings under the CMM Credit Facility bear interest at LIBOR plus an applicable margin or base rate, as defined in the credit agreement governing the CMM Credit Facility. Under the terms of the CMM Credit Facility, the applicable margin under LIBOR was 2.5% at June 30, 2013 and December 31, 2012. The weighted-average interest rate as of June 30, 2013 and December 31, 2012 was 2.8%.

25

INERGY, L.P. AND SUBSIDIARIES (FORMERLY CRESTWOOD GAS SERVICES GP LLC)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

The CMM Credit Facility requires CMM to maintain:

• a ratio of trailing twelve-month EBITDA (as defined in the credit agreement) to net interest expense of not less than 2.0 to 1.0; and

• a ratio of total indebtedness to trailing twelve-month EBITDA (as defined in the credit agreement) of not more than 4.5 to 1.0, or not more than 5.0 to 1.0 for up to nine months following certain acquisitions.

At June 30, 2013, trailing twelve-month EBITDA to net interest expense was 11.4 to 1.0 and total indebtedness to trailing twelve-month EBITDA was 2.9 to 1.0.

The CMM Credit Facility contains restrictive covenants that, among other things, prohibit the declaration or payment of distributions by CMM if a default then exists or would result therefrom, and otherwise limits the amount of distributions that CMM can make.

NRGM Credit Facility

Inergy Midstream utilizes a $600.0 million revolving credit facility (“NRGM Credit Facility”). The NRGM Credit Facility is available to fund acquisitions, working capital and internal growth projects and for general partnership purposes. The NRGM Credit Facility has an accordion feature that allows Inergy Midstream to increase the available borrowings under the facility by up to $150.0 million, subject to the lenders' agreement and the satisfaction of certain conditions. In addition, its credit facility includes a sub-limit up to $10 million for same-day swing line advances and a sub-limit up to $100 million for letters of credit.

At June 30, 2013, the balance outstanding under the NRGM Credit Facility was $237.0 million. Outstanding standby letters of credit under the NRGM Credit Facility amounted to $2.0 million at June 30, 2013. As a result, Inergy Midstream had approximately $361.0 million of remaining capacity at June 30, 2013, subject to compliance with any applicable covenants under such facility.

Borrowings under the NRGM Credit Facility are generally secured by liens on substantially all of the assets of, and pledges of the equity interests in, Inergy Midstream's subsidiaries. The NRGM Credit Facility is fully and unconditionally guaranteed, jointly and severally, by Inergy Midstream's subsidiaries. The credit agreement governing the NRGM Credit Facility contains various covenants and restrictive provisions that limit its ability to, among other things: incur additional debt; make distributions on or redeem or repurchase units; make certain investments and acquisitions; incur or permit certain liens to exist; enter into certain types of transactions with affiliates; merge, consolidate or amalgamate with another company; and transfer or otherwise dispose of assets.

The NRGM Credit Facility requires maintenance of a consolidated leverage ratio (as defined in its credit agreement) of not more than 5.00 to 1.0 (subject to increase to 5.50 to 1.0 following certain permitted acquisitions, as indicated above) and an interest coverage ratio (as defined in its credit agreement) of not less than 2.50 to 1.0. The NRGM Credit Facility also requires maintenance of a senior secured leverage ratio (as defined in its credit agreement) of not more than 3.75 to 1.0 on and after the cumulative issuance of $200 million or more of permitted junior debt. At June 30, 2013, the consolidated leverage ratio was 4.1 to 1.0, the interest coverage ratio was 6.8 to 1.0 and the senior secured leverage ratio was 1.3 to 1.0.

Borrowings under the NRGM Credit Facility (other than swing loans) will bear interest at its option at either:

• the Alternate Base Rate, which is defined as the highest of (i) the federal funds rate plus 0.50%; (ii) JP Morgan's prime rate; or (iii) the Adjusted LIBO Rate plus 1%; plus a margin varying from 0.75% to 1.75% depending on Inergy Midstream's most recent total leverage ratio; or

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

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

26

INERGY, L.P. AND SUBSIDIARIES (FORMERLY CRESTWOOD GAS SERVICES GP LLC)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

NRGM Senior Notes

At June 30, 2013, the balance outstanding on the Inergy Midstream 6.0% Senior Notes due 2020 (the “NRGM Notes”) was $500.0 million. The Company recorded a $5.0 million adjustment in conjunction with the Inergy reverse acquisition to adjust the debt to fair value. The senior notes will mature on December 15, 2020, and interest is payable semi-annually in arrears on June 15 and December 15 of each year.

In general, the NRGM Notes are fully and unconditionally guaranteed, joint and severally, on a senior unsecured basis by Inergy Midstream's subsidiaries (other than Finance Corp.). The indenture contains customary release provisions, such as (i) disposition of all or substantially all the assets of, or the capital stock of, a guarantor subsidiary to a third person if the disposition complies with the indenture; (ii) designation of a guarantor subsidiary as an Unrestricted Subsidiary in accordance with our indentures; (iii) legal or covenant defeasance of a series of senior notes, or satisfaction and discharge of the related indenture; and (iv) guarantor subsidiary ceases to guarantee any other indebtedness of ours or any other guarantor subsidiary, provided it no longer guarantees indebtedness under the NRGM Credit Facility. Inergy Midstream has no independent assets or operations, and Finance Corp. is a 100% finance subsidiary of Inergy Midstream.

The indenture restricts the ability of Inergy Midstream and its subsidiaries to, among other things, sell assets; pay distributions on, redeem or repurchase NRGM units, redeem or repurchase subordinated debt; make investments; incur or guarantee additional indebtedness or issue preferred units; create or incur certain liens; enter into agreements that restrict distributions or other payments to Inergy Midstream from its restricted subsidiaries; consolidate, merge or transfer all or substantially all of Inergy Midstream's assets; and, engage in affiliate transactions; create unrestricted subsidiaries. These restrictions are subject to a number of important exceptions and qualifications, and many of these restrictions will terminate when the senior notes are rated investment grade and no default under the indenture has occurred and is continuing.

On May 14, 2013, Inergy Midstream commenced a consent solicitation for the purpose of amending the indenture to ensure that the consummation of the Crestwood business combination would not constitute a “Change of Control” thereunder, which would have entitled the NRGM note holders to require Inergy Midstream to repurchase the senior notes. The consent solicitation was conditioned on the receipt of consents from holders of record on the record date of a majority in aggregate principal amount of the NRGM Notes. On May 22, 2013, following its receipt of the requisite consents, Inergy Midstream entered into a second supplemental indenture memorializing the requested changes to the indenture. As part of the consent solicitation, consents were delivered and not revoked by holders of approximately $464.5 million in aggregate principal amount (or 92.9%) of the NRGM Notes.

Note 8 – Partners’ Capital

Common Unit Offering

On March 22, 2013, CMLP completed a public offering of 4,500,000 common units, representing limited partner interests in CMLP at a price of $23.90 per common unit ($23.00 per common unit, net of underwriting discounts) providing net proceeds of approximately $103.5 million. CMLP granted the underwriters a 30 day option to purchase up to 675,000 additional common units if the underwriters sold more than 4,500,000 common units in the offering. The underwriters exercised this option on April 5, 2013, providing net proceeds of approximately $15.5 million. The net proceeds from these transactions were used to reduce indebtedness under each of the CMM and CMLP Credit Facilities.

Limited Partner Unit Issuances

On April 1, 2013, CMLP's outstanding Class C units converted to common units on a one-for-one basis. Prior to the conversion of CMLP's Class C units to common, CMLP had the option to pay distributions to our Class C unitholders with cash or by issuing additional Paid-in-Kind Class C units, based upon the volume weighted-average price of CMLP's common units for the 10 trading days immediately preceding the date the distribution was declared. The unitholders of the converted units received a quarterly cash distribution for the period ended March 31, 2013 although the Class C units were not converted until April 1, 2013.

27

INERGY, L.P. AND SUBSIDIARIES (FORMERLY CRESTWOOD GAS SERVICES GP LLC)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

In January 2013, CMLP issued 6,190,469 Class D units, representing limited partner interests, to Crestwood Holdings in connection with its acquisition of Crestwood Holdings' 65% interest in CMM. The Class D units are similar in certain respects to CMLP's common units and Class C units, except that CMLP has the option to pay distributions to its Class D unitholders with cash or by issuing additional Paid-in-Kind Class D units based on the volume weighted-average price of CMLP's common units for the 10 trading days immediately preceding the date the distribution is declared. CMLP issued 151,238 additional Class D units in lieu of paying cash quarterly distributions on CMLP's Class D units attributable to the three months ended March 31, 2013. In March 2014, CMLP's outstanding Class D units will convert to common units.

Quarterly Distributions of Available Cash

CMLP paid cash distributions to its common unitholders of $27.4 million and $48.4 million during the three and six months ended June 30, 2013, and $18.2 million and $36.1 million during the three and six months ended June 30, 2012. CMLP also declared a $0.51 per common unit cash distribution payable on August 9, 2013, which is estimated to be $27.5 million.

On July 25, 2013, Inergy declared a distribution of $0.130 per limited partner unit to be paid on August 14, 2013, to unitholders of record on August 7, 2013 with respect to the second calendar quarter of 2013. On June 18, 2013, Inergy completed the pro rata distribution to its unitholders of approximately 56.4 million common units of Inergy Midstream at a distribution rate of 0.432052 NRGM unit for each Inergy limited partner unit owned on the record date. As a result, Inergy’s quarterly cash distribution of $0.130 reflects the NRGM unit distribution. Inergy investors who received, and continue to own through August 7, 2013, NRGM common units distributed by Inergy will receive total quarterly cash distributions of $0.3025 per Inergy unit, consisting of the $0.130 per unit to be paid directly by Inergy and approximately $0.1725 per Inergy unit to be paid by NRGM, based upon NRGM’s declared quarterly distribution of $0.40 per NRGM common unit.

Note 9 – Commitments and Contingencies

Purchase Commitments

Inergy periodically enters into agreements with suppliers to purchase fixed quantities of NGLs, distillates and natural gas at fixed prices. At June 30, 2013, the total of these firm purchase commitments was $179.0 million, 97.9% of which will occur over the course of the next twelve months. The Company also enters into non-binding agreements with suppliers to purchase quantities of NGLs, distillates and natural gas at variable prices at future dates at the then prevailing market prices.

Inergy and Inergy Midstream entered into certain purchase commitments in connection with the identified growth projects primarily related to the Watkins Glen NGL development project, the COLT Hub expansion project, and certain upgrades to the US Salt facility. The Watkins Glen NGL development project entails the conversion of certain caverns created by US Salt into 2.1 million barrels of NGL storage.  The COLT Hub expansion project primarily includes an expansion of receiving, storage, and take-away capacity via interconnecting pipelines, storage tanks, and rail facilities. At June 30, 2013, the total of Inergy's and Inergy Midstream's storage and transportation operations' firm purchase commitments was approximately $24.0 million. The gathering and processing segment also has purchase commitments of approximately $14.6 million related to other growth and maintenance contractual purchase obligations, as well as environmental obligations. The majority of the purchases associated with these commitments are expected to occur over the course of the next twelve months.

Capital Leases

The Company has auto leases, a compressor, and a treating facility that are accounted for as capital leases. The terms of the agreements vary from 2013 until 2016. Inergy's capital lease liabilities were $4.9 million and $7.0 million at June 30, 2013 and December 31, 2012, respectively, and are included in accrued expenses and other liabilities and other long-term liabilities on the consolidated balance sheets.

28

INERGY, L.P. AND SUBSIDIARIES (FORMERLY CRESTWOOD GAS SERVICES GP LLC)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Legal Proceedings

Inergy is periodically involved in litigation proceedings. If Inergy determines that a negative outcome is probable and the amount of loss is reasonably estimable, then it accrues the estimated amount. The results of litigation proceedings cannot be predicted with certainty; however, management believes that Inergy does not have material potential liability in connection with these proceedings that would have a significant financial impact on its consolidated financial condition, results of operations or cash flows. However, Inergy could incur judgments, enter into settlements or revise its expectations regarding the outcome of certain matters, and such developments could have a material adverse effect on Inergy's results of operations or cash flows in the period in which the amounts are paid and/or accrued.

Any loss estimates are inherently subjective, based on currently available information, and are subject to management's judgment and various assumptions. Due to the inherently subjective nature of these estimates and the uncertainty and unpredictability surrounding the outcome of legal proceedings, actual results may differ materially from any amounts that have been accrued.

Five putative class action lawsuits challenging the Crestwood-Inergy merger have been filed, four in federal court in the United States District Court for the Southern District of Texas: (i) Abraham Knoll v. Robert G. Phillips, et al. (Case No. 4:13-cv-01528); (ii) Greg Podell v. Crestwood Midstream Partners, LP, et al. (Case No. 4:13-cv-01599); (iii) Johnny Cooper v. Crestwood Midstream Partners LP, et al. (Case No. 4:13-cv-01660); and (iv) Steven Elliot LLC v. Robert G. Phillips, et al. (Case No. 4:13-cv-01763), and one in Delaware Chancery Court, Hawley v. Crestwood Midstream Partners LP, et al. (Case No. 8689-VCL).  All of the cases name Crestwood, Crestwood Gas Services GP LLC, Crestwood Holdings LLC, the current and former directors of Crestwood Gas Services GP LLC, Inergy, L.P., Inergy Midstream, L.P., NRGM GP, LLC, and Intrepid Merger Sub, LLC as defendants.  All of the suits are brought by a purported holder of common units of Crestwood, both individually and on behalf of a putative class consisting of holders of common units of Crestwood.  The lawsuits generally allege, among other things, that the directors of Crestwood Gas Services GP LLC breached their fiduciary duties to holders of common units of Crestwood by agreeing to a transaction with inadequate consideration and unfair terms and pursuant to an inadequate process.  The lawsuits further allege that Inergy, L.P., Inergy Midstream, L.P., NRGM GP, LLC, and Intrepid Merger Sub, LLC aided and abetted the Crestwood directors in the alleged breach of their fiduciary duties.  The lawsuits seek, in general, (i) injunctive relief enjoining the merger, (ii) in the event the merger is consummated, rescission or an award of rescissory damages, (iii) an award of plaintiffs' costs, including reasonable attorneys' and experts' fees, (iv) the accounting by the defendants to the plaintiffs for all damages caused by the defendants, and (v) such further equitable relief as the court deems just and proper.  Certain of the actions also assert claims of inadequate disclosure under Sections 14(a) and 20(a) of the Securities Exchange Act of 1934, and the Elliot case also names Citigroup Global Markets Inc. as an alleged aider and abettor.  The plaintiff in the Hawley action in Delaware filed a motion for expedited proceedings but subsequently withdrew that motion and then filed a stipulation voluntarily dismissing the action without prejudice, which has been granted by the Court, such that the Hawley action has now been dismissed.  The plaintiffs in the Knoll, Podell, Cooper, and Elliot actions filed an unopposed motion to consolidate these four cases, which the Court granted.  The plaintiff in the Elliot action filed a motion for expedited discovery, which remains pending. These lawsuits are at a preliminary stage. Crestwood, Inergy Midstream and the other defendants believe that these lawsuits are without merit and intend to defend against them vigorously.

In June 2010, Inergy Midstream and CNYOG entered into a letter of intent with Anadarko Petroleum Corporation (“Anadarko”) which contemplated that, subject to certain conditions, Anadarko may exercise an option to acquire up to a 25% ownership interest in the MARC I pipeline. On September 23, 2011, Anadarko filed a complaint against the Company and CNYOG in the Court of Common Pleas in Lycoming County, Pennsylvania (Cause No. 11-01697) alleging that (i) Anadarko had an option to acquire, and timely exercised its option to acquire, a 25% ownership interest in the MARC I pipeline, (ii) the Company refused to enter into definitive agreements under which Anadarko would acquire a 25% interest in the pipeline and, by doing so, the Company breached the letter of intent, and (iii) by refusing to enter into definitive agreements, the Company breached a duty of good faith and fair dealing in connection with the letter of intent. Based on these allegations, Anadarko seeks various remedies, including specific performance of the letter of intent and monetary damages. 

The Company filed its answer to Anadarko's complaint on January 17, 2012 and discovery is ongoing. The Company believes that Anadarko's claims are without merit and intends to vigorously defend themselves in the lawsuit. Because this litigation is in the early stages of the proceedings, the Company is unable to estimate a reasonably possible loss or range of loss in this matter. Moreover, the Company believes that it has meritorious defenses that it intends to assert.

29

INERGY, L.P. AND SUBSIDIARIES (FORMERLY CRESTWOOD GAS SERVICES GP LLC)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Regulatory Compliance

In the ordinary course of our business, Inergy is subject to various laws and regulations. In the opinion of Inergy's management, compliance with current laws and regulations will not have a material effect on its results of operations, cash flows or financial condition.

Environmental Compliance

Inergy's operations are subject to stringent and complex laws and regulations pertaining to health, safety, and the environment. Inergy is subject to laws and regulations at the federal, state and local levels that relate to air and water quality, hazardous and solid waste management and disposal and other environmental matters. The cost of planning, designing, constructing and operating Inergy's facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures. At June 30, 2013, Inergy had accrued approximately $0.3 million for environmental matters, which was based on Inergy's undiscounted estimate of amounts it will spend on environmental compliance and remediation. Inergy estimates that its potential liability for reasonably possible outcomes related to its environmental exposures could range from approximately $0.3 million to $0.4 million. Inergy had $0.2 million accrued for environmental matters at December 31, 2012.

Self-Insurance

Inergy utilizes third-party insurance subject to varying retention levels of self-insurance, which management considers prudent. Such self-insurance relates to losses and liabilities primarily associated with medical claims, workers' compensation claims and general, product, vehicle and environmental liability. Losses are accrued based upon management's estimates of the aggregate liability for claims incurred using certain assumptions followed in the insurance industry and based on past experience. The primary assumption utilized is actuarially determined loss development factors. The loss development factors are based primarily on historical data. Inergy's self insurance reserves could be affected if future claim developments differ from the historical trends. Inergy believes changes in health care costs, trends in health care claims of its employee base, accident frequency and severity and other factors could materially affect the estimate for these liabilities. Inergy continually monitors changes in employee demographics, incident and claim type and evaluates its insurance accruals and adjusts its accruals based on its evaluation of these qualitative data points. Inergy is liable for the development of claims for its disposed retail propane operations, provided they were reported prior to August 1, 2012. At June 30, 2013, Inergy's self-insurance reserves were $19.9 million. The Company estimates that $17.2 million of this balance will be paid subsequent to June 30, 2014. As such, $17.2 million has been classified in other long-term liabilities on the consolidated balance sheets. There were no self-insurance reserves at December 31, 2012.

Note 10 – Segments

In conjunction with the June 19, 2013 transactions described in Note 1, Inergy modified its segments and now our financial statements reflect three operating and reporting segments: (i) gathering and processing operations; (ii) NGL and crude services operations; and (iii) storage and transportation operations. Inergy's gathering and processing operations engage in the gathering, processing, treating, compression, transportation and sales of natural gas and the delivery of NGLs. Inergy's NGL and crude services operations provide NGLs and crude oil marketing, supply and logistics services to producers, refiners, petrochemical companies, marketers, and others that effectively provide flow assurances to our customers. Inergy's storage and transportation operations provide natural gas and NGL storage and transportation services to third parties, as well as the production and sale of salt products.

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

30

INERGY, L.P. AND SUBSIDIARIES (FORMERLY CRESTWOOD GAS SERVICES GP LLC)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

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

	Three Months Ended June 30, 2013
	Gathering and Processing Operations		NGL and Crude Services Operations		Storage and Transportation Operations		Intersegment Operations		Corporate Assets		Total
Gathering and processing revenues	$	71.1	$	—	$	—	$	—	$	—	$	71.1
Supply and logistics revenues	—		38.1		—		—		—		38.1
Storage and transportation revenues	—		—		9.7		—		—		9.7
Gross profit (excluding depreciation, amortization and accretion)	57.1		1.4		8.4		—		—		66.9
Identifiable assets	42.6		163.0		30.0		—		—		235.6
Goodwill	352.2		1,249.7		850.4		—		—		2,452.3
Property, plant and equipment	1,297.7		402.2		2,152.4		—		2.4		3,854.7
Cash expenditures for property, plant and equipment	56.0		0.3		3.5		—		—		59.8

	Three Months Ended June 30, 2012
	Gathering and Processing Operations		NGL and Crude Services Operations		Storage and Transportation Operations		Intersegment Operations		Corporate Assets		Total
Gathering and processing revenues	$	55.2	$	—	$	—	$	—	$	—	$	55.2
Supply and logistics revenues	—		—		—		—		—		—
Storage and transportation revenues	—		—		—		—		—		—
Gross profit (excluding depreciation, amortization and accretion)	47.8		—		—		—		—		47.8
Identifiable assets	35.0		—		—		—		—		35.0
Goodwill	348.1		—		—		—		—		348.1
Property, plant and equipment	1,087.9		—		—		—		—		1,087.9
Cash expenditures for property, plant and equipment	9.5		—		—		—		—		9.5

31

INERGY, L.P. AND SUBSIDIARIES (FORMERLY CRESTWOOD GAS SERVICES GP LLC)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

	Six Months Ended June 30, 2013
	Gathering and Processing Operations		NGL and Crude Services Operations		Storage and Transportation Operations		Intersegment Operations		Corporate Assets		Total
Gathering and processing revenues	$	143.5	$	—	$	—	$	—	$	—	$	143.5
Supply and logistics revenues	—		38.1		—		—		—		38.1
Storage and transportation revenues	—		—		9.7		—		—		9.7
Gross profit (excluding depreciation, amortization and accretion)	116.0		1.4		8.4		—		—		125.8
Identifiable assets	42.6		163.0		30.0		—		—		235.6
Goodwill	352.2		1,249.7		850.4		—		—		2,452.3
Property, plant and equipment	1,297.7		402.2		2,152.4		—		2.4		3,854.7
Cash expenditures for property, plant and equipment	80.3		0.3		3.5		—		—		84.1

	Six Months Ended June 30, 2012
	Gathering and Processing Operations		NGL and Crude Services Operations		Storage and Transportation Operations		Intersegment Operations		Corporate Assets		Total
Gathering and processing revenues	$	109.0	$	—	$	—	$	—	$	—	$	109.0
Supply and logistics revenues	—		—		—		—		—		—
Storage and transportation revenues	—		—		—		—		—		—
Gross profit (excluding depreciation, amortization and accretion)	92.6		—		—		—		—		92.6
Identifiable assets	35.0		—		—		—		—		35.0
Goodwill	348.1		—		—		—		—		348.1
Property, plant and equipment	1,087.9		—		—		—		—		1,087.9
Cash expenditures for property, plant and equipment	22.4		—		—		—		—		22.4

32

INERGY, L.P. AND SUBSIDIARIES (FORMERLY CRESTWOOD GAS SERVICES GP LLC)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Note 11 – Related Party Transactions

Inergy enters into transactions with its affiliates within the ordinary course of business. For a further discussion of Inergy's affiliated transactions, see the Form 8-K as filed with the Securities and Exchange Commission on August 5, 2013. The following table shows revenues, cost of goods sold, operating and administrative expense and reimbursements from Inergy's affiliates for the three-month and six-month periods endedJune 30, 2013 and 2012, respectively (in millions):

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2013		2012		2013		2012
Gathering and processing revenues	$	24.6	$	28.2	$	50.2	$	58.8
Gathering and processing cost of goods sold	$	7.9	$	—	$	14.6	$	—
Operating and administrative expense	$	5.5	$	4.8	$	11.1	$	9.5
Reimbursements	$	0.3	$	0.3	$	0.5	$	0.5

The following table shows accounts receivable and accounts payable from Inergy's affiliates as of June 30, 2013 and December 31, 2012, respectively (in millions):

	June 30,  2013		December 31, 2012
Accounts receivable	$	20.9	$	23.8
Accounts payable	$	7.2	$	3.1

Note 12 – Condensed Consolidating Financial Information

Inergy is a holding company and owns no operating assets and has no significant operations independent of its subsidiaries. Obligations under its outstanding senior notes and credit agreement listed in Note 7 are jointly and severally guaranteed by Inergy's wholly owned domestic subsidiaries. NRGM and CMLP and each of their wholly owned subsidiaries do not guarantee Inergy's senior notes or credit agreement.

As discussed in Note 1, the accounting for Inergy's acquisition of CMLP GP results in the historical Inergy operations being acquired on June 19, 2013. Inergy's senior notes are thus not included in the financial statements prior to June 19, 2013. CMLP GP (the accounting predecessor) does not guarantee any debt. Therefore, the condensed consolidated financial statements do not include 2012 financial information.

The tables below present condensed consolidated financial statements for Inergy (parent) on a stand-alone, unconsolidated basis, and its combined guarantor and combined non-guarantor subsidiaries as of June 30, 2013 and for the three-month and six-month periods endedJune 30, 2013. The financial information may not necessarily be indicative of the results of operations, cash flows or financial position had the subsidiaries operated as independent entities.

33

INERGY, L.P. AND SUBSIDIARIES (FORMERLY CRESTWOOD GAS SERVICES GP LLC)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Condensed Consolidating Balance Sheet
June 30, 2013
(in millions)
	Parent		Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	0.1	$	1.3	$	1.3	$	—		$	2.7
Accounts receivable	—		111.7		70.7		—			182.4
Inventories	—		47.6		5.6		—			53.2
Other current assets	—		21.2		24.5		(1.2		)	44.5
Total current assets	0.1		181.8		102.1		(1.2		)	282.8
Property, plant and equipment, net	—		816.7		2,911.5		—			3,728.2
Goodwill and intangible assets, net	—		928.9		2,572.0		—			3,500.9
Investment in subsidiary	1,782.6		—		—		(1,782.6		)	—
Other assets	—		29.3		24.5		—			53.8
Total assets	$	1,782.7	$	1,956.7	$	5,610.1	$	(1,783.8	)	$	7,565.7
Liabilities and partners' capital
Current liabilities:
Accounts payable	$	—	$	132.6	$	19.0	$	—		$	151.6
Other current liabilities	1.6		39.5		86.1		(1.2		)	126.0
Total current liabilities	1.6		172.1		105.1		(1.2		)	277.6
Long-term liabilities:
Long-term debt, less current portion	354.2		—		1,518.9		—			1,873.1
Other long-term liabilities	25.1		17.2		16.7		—			59.0
Total long-term liabilities	379.3		17.2		1,535.6		—			1,932.1
Partners' capital	1,401.8		1,767.4		15.2		(1,782.6		)	1,401.8
Interest of non-controlling partners in subsidiary	—		—		3,954.2		—			3,954.2
Total partners' capital	1,401.8		1,767.4		3,969.4		(1,782.6		)	5,356.0
Total liabilities and partners' capital	$	1,782.7	$	1,956.7	$	5,610.1	$	(1,783.8	)	$	7,565.7

34

INERGY, L.P. AND SUBSIDIARIES (FORMERLY CRESTWOOD GAS SERVICES GP LLC)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Condensed Consolidating Statements of Operations
Three Months Ended June 30, 2013
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Revenues:
Gathering and processing	$	—		$	—		$	71.1		$	—		$	71.1
NGL and crude services	—			38.1			—			—			38.1
Storage and transportation	—			1.1			9.0			(0.4		)	9.7
	—			39.2			80.1			(0.4		)	118.9
Cost of product/services sold (excluding depreciation, amortization and accretion as shown below):
Gathering and processing	—			—			14.0			—			14.0
NGL and crude services	—			36.5			0.2			—			36.7
Storage and transportation	—			0.6			1.1			(0.4		)	1.3
	—			37.1			15.3			(0.4		)	52.0
Expenses:
Operating and administrative	—			2.5			28.6			—			31.1
Depreciation, amortization and accretion	—			2.1			25.9			—			28.0
Operating income (loss)	—			(2.5		)	10.3			—			7.8
Other income (expense):
Interest and debt expense, net	0.5			—			(12.5		)	—			(12.0		)
Equity in net income of subsidiary	(5.0		)	—			—			5.0			—
Income (loss) before income taxes	(4.5		)	(2.5		)	(2.2		)	5.0			(4.2		)
Provision for income taxes	—			—			0.3			—			0.3
Net income (loss)	(4.5		)	(2.5		)	(2.5		)	5.0			(4.5		)
Net loss attributable to non-controlling partners in subsidiary	—			—			6.1			—			6.1
Net income (loss) attributable to partners	$	(4.5	)	$	(2.5	)	$	3.6		$	5.0		$	1.6

35

INERGY, L.P. AND SUBSIDIARIES (FORMERLY CRESTWOOD GAS SERVICES GP LLC)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Condensed Consolidating Statements of Operations
Six Months Ended June 30, 2013
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Revenues:
Gathering and processing	$	—		$	—		$	143.5		$	—		$	143.5
NGL and crude services	—			38.1			—			—			38.1
Storage and transportation	—			1.1			9.0			(0.4		)	9.7
	—			39.2			152.5			(0.4		)	191.3
Cost of product/services sold (excluding depreciation, amortization and accretion as shown below):
Gathering and processing	—			—			27.5			—			27.5
NGL and crude services	—			36.5			0.2			—			36.7
Storage and transportation	—			0.6			1.1			(0.4		)	1.3
	—			37.1			28.8			(0.4		)	65.5
Expenses:
Operating and administrative	—			2.5			49.4			—			51.9
Depreciation, amortization and accretion	—			2.1			48.3			—			50.4
Operating income (loss)	—			(2.5		)	26.0			—			23.5
Other income (expense):
Interest and debt expense, net	0.5			—			(23.9		)	—			(23.4		)
Equity in net income of subsidiary	(1.1		)	—			—			1.1			—
Income (loss) before income taxes	(0.6		)	(2.5		)	2.1			1.1			0.1
Provision for income taxes	—			—			0.7			—			0.7
Net income (loss)	(0.6		)	(2.5		)	1.4			1.1			(0.6		)
Net loss attributable to non-controlling partners in subsidiary	—			—			7.3			—			7.3
Net income (loss) attributable to partners	$	(0.6	)	$	(2.5	)	$	8.7		$	1.1		$	6.7

36

INERGY, L.P. AND SUBSIDIARIES (FORMERLY CRESTWOOD GAS SERVICES GP LLC)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Condensed Consolidating Statements of Comprehensive Income
Three Months Ended June 30, 2013
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations		Consolidated
Net income (loss)	$	(4.5	)	$	(2.5	)	$	(2.5	)	$	5.0	$	(4.5	)
Change in Suburban Propane Partners LP units	(0.2		)	—			—			—		(0.2		)
Comprehensive income (loss)	$	(4.7	)	$	(2.5	)	$	(2.5	)	$	5.0	$	(4.7	)

Condensed Consolidating Statements of Comprehensive Income
Six Months Ended June 30, 2013
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries		Eliminations		Consolidated
Net income (loss)	$	(0.6	)	$	(2.5	)	$	1.4	$	1.1	$	(0.6	)
Change in Suburban Propane Partners LP units	(0.2		)	—			—		—		(0.2		)
Comprehensive income (loss)	$	(0.8	)	$	(2.5	)	$	1.4	$	1.1	$	(0.8	)

37

INERGY, L.P. AND SUBSIDIARIES (FORMERLY CRESTWOOD GAS SERVICES GP LLC)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Condensed Consolidating Statements of Cash Flows
Six Months Ended June 30, 2013
(in millions)
	Parent		Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations		Consolidated
Cash flows from operating activities	$	—	$	(9.5	)	$	66.9		$	—	$	57.4
Cash flows from investing activities
Acquisitions, net of cash acquired	0.1		5.0			1.0			—		6.1
Purchases of property, plant and equipment	—		(0.5		)	(83.6		)	—		(84.1		)
Net cash provided by (used in) investing activities	0.1		4.5			(82.6		)	—		(78.0		)
Cash flows from financing activities:
Proceeds from the issuance of long-term debt	—		41.8			326.7			—		368.5
Principal payments on long-term debt	—		(21.5		)	(238.5		)	—		(260.0		)
Distributions paid	—		(11.8		)	(9.3		)	—		(21.1		)
Distributions paid to non-controlling partners	—		—			(177.4		)	—		(177.4		)
Net proceeds from the issuance of common units	—		—			118.5			—		118.5
Other	—		(2.2		)	(3.1		)	—		(5.3		)
Net cash provided by financing activities	—		6.3			16.9			—		23.2
Net increase in cash	0.1		1.3			1.2			—		2.6
Cash at beginning of period	—		—			0.1			—		0.1
Cash at end of period	$	0.1	$	1.3		$	1.3		$	—	$	2.7

Note 13 – Subsequent Events

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

On July 25, 2013, Inergy declared a distribution of $0.130 per limited partner unit to be paid on August 14, 2013, to unitholders of record on August 7, 2013. On June 18, 2013, Inergy completed the pro rata distribution to its unitholders of approximately 56.4 million common units of Inergy Midstream at a distribution rate of 0.432052 NRGM unit for each Inergy limited partner unit owned on the record date. As a result, Inergy’s quarterly cash distribution of $0.130 reflects the NRGM unit distribution. Inergy investors who received, and continue to own through August 7, 2013, NRGM common units distributed by Inergy will receive total quarterly cash distributions of $0.3025 per Inergy unit, consisting of the $0.130 per unit to be paid directly by Inergy and approximately $0.1725 per Inergy unit to be paid by NRGM, based upon NRGM’s declared quarterly distribution of $0.40 per NRGM common unit.

On June 24, 2013, Crestwood Niobrara LLC, CMLP's consolidated subsidiary, entered into an agreement with RKI Exploration and Production LLC (RKI), an affiliate of CMLP GP, to purchase RKI's 50% interest in a gathering system located in the Powder River Basin Niobrara play for approximately $108 million. This acquisition closed on July 19, 2013, and was funded through CMLP's contribution of approximately $27 million to Crestwood Niobrara (which was borrowed under the CMLP Credit Facility) and an additional $81 million was obtained through Crestwood Niobrara's issuance of a preferred interest to a subsidiary of General Electric Capital Corporation and GE Structured Finance, Inc. (collectively, GE EFS).

38

INERGY, L.P. AND SUBSIDIARIES (FORMERLY CRESTWOOD GAS SERVICES GP LLC)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Crestwood Niobrara will fund 75% of future capital contributions to the gathering system joint venture through additional preferred interest issuances to GE EFS (up to a maximum of $69 million), with the remainder to be funded through CMLP's capital contributions to Crestwood Niobrara. CMLP serves as the managing member of Crestwood Niobrara and CMLP has the ability to redeem GE EFS's preferred security in either cash or CMLP common units, subject to certain restrictions.

39

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

Item 2 of this report should be read in conjunction with the accompanying consolidated financial statements; “Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations” in the Annual Report on Form 10-K of Inergy, L.P. for the fiscal year ended September 30, 2012, and the Annual Report on Form 10-K of Crestwood Midstream Partners LP for the fiscal year ended December 31, 2012; and the Form 8-K/A of Inergy, L.P. filed on August 5, 2013 that provides historical information about the historical financial condition and results of operations of Crestwood Gas Services GP LLC.

This report, including information included or incorporated by reference herein, contains forward-looking statements concerning the financial condition, results of operations, plans, objectives, future performance and business of our company and its subsidiaries. These forward-looking statements include:

• statements that are not historical in nature, including, but not limited to: (i) our expectation that we will grow our business through both organic growth projects and acquisitions; (ii) our belief  that anticipated cash from operations, cash distributions from entities that we own or control, and borrowing capacity under our credit facility will be sufficient to meet our anticipated liquidity needs for the foreseeable future; (iii) our belief that anticipated cash from operations and borrowing capacity under credit facilities will be sufficient for NRGM and CMLP to meet their anticipated liquidity needs for the foreseeable future; (iv) our belief that we do not have material potential liability in connection with legal proceedings that would have a significant financial impact on our consolidated financial condition, results of operations or cash flows; (v) our belief that our assets, and the assets of entities that we control, will continue to benefit from the development of unconventional shale plays as significant supply basins; (vi) our belief that CMLP combination will produce certain commercial synergies and other benefits; and (vii) our expectation that Tres Palacios will generate greater revenue over the second half of the calendar year; and

• statements preceded by, followed by or that contain forward-looking terminology including the words “believe,” “expect,” “may,” “will,” “should,” “could,” “anticipate,” “estimate,” “intend” or the negation thereof, or similar expressions.

Forward-looking statements are not guarantees of future performance or results. They involve risks, uncertainties and assumptions. Actual results may differ materially from those contemplated by the forward-looking statements due to, among others, the following factors:

• our ability to successfully implement our business plan for our assets and operations;

• governmental legislation and regulations;

• industry factors that influence the supply of and demand for crude oil, natural gas and NGLs;

• industry factors that influence the demand for services in the markets (particularly the unconventional shale plays) in which we provide midstream services;

• weather conditions;

• the availability of crude oil, natural gas and NGLs, and the price of those commodities, to consumers relative to the price of alternative and competing fuels;

• economic conditions; costs or difficulties related to the integration of our existing businesses and acquisitions;

• environmental claims;

• operating hazards and other risks incidental to the provision of midstream services, including the gathering, treating, processing, fractionating, transporting and storing crude oil, NGLs and natural gas;

• interest rates; and

• the price and availability of debt and equity financing.

Overview

We are a publicly-traded master limited partnership (“MLP”) that manages, owns and operates crude oil, natural gas and NGL midstream assets and operations. Headquartered in Houston, Texas, we are a fully-integrated midstream solution provider that specializes in connecting shale-based energy supplies to key demand markets. We manage and conduct a substantial portion of our operations through two growth-oriented, publicly-traded MLPs: (i) Inergy Midstream, which owns and operates storage and transportation assets located in North Dakota and the Northeast region of the United States, and (ii) Crestwood Midstream, which owns and operates gathering and processing assets located in multiple shale plays across the United States. We own the general partnership interests and IDRs of both Inergy Midstream and Crestwood Midstream.

40

Strategic Business Combination

As described previously, we recently entered into a series of definitive agreements with Crestwood Holdings and its affiliates that have effectively combined and consolidated the management and operations of Inergy, Inergy Midstream and Crestwood Midstream. After the contribution of our retail propane operations in 2012, we believe this strategic combination enhances our position as a pure play midstream company poised for growth. We anticipate that this combination will, among other things, produce commercial synergies that enable us to significantly expand the mix of midstream services that we are able to offer our customers; diversify our cash flows and asset base; provide the scale necessary to accelerate opportunities to reduce leverage and improve creditworthy; and provide the scale necessary to better take advantage of growth opportunities, in terms of both organic growth projects and third-party acquisitions.

Our Company

We are a growth-oriented midstream energy company that offers customer solutions across the crude oil, NGL and natural gas sector of the energy value chain. Our midstream infrastructure is geographically located in or near significant supply basins, particularly developing unconventional shale plays, across the United States. In general, we own or control:

• natural gas facilities with more than 2,000 MMcf/d of gathering capacity, 400 MMcf/d of processing capacity, 80 Bcf of working gas storage capacity, and 1,300 MMcf/d of transportation capacity;

• NGL facilities with more than 12,000 barrels per day of fractionation capacity and 2.6 million barrels of storage capacity; and

• crude oil facilities with more than 120,000 barrels per day of rail loading capacity and 720,000 gallons of storage capacity.

Our primary business objective is to increase the cash distributions that we pay to our unitholders. We expect to position Inergy Midstream and Crestwood Midstream to increase their cash distributions by providing strong general partner support and using them as the primary vehicles through which we grow our midstream business. We intend to grow our NGL and crude services business by leveraging our industry knowledge, expertise and relationships with Crestwood Midstream's relationships and operational experience to offer unparalleled takeaway solutions from the wellhead to the end user.

Our three business segments include (i) gathering and processing, which comprises the gathering and processing operations of Crestwood Midstream; (ii) NGL and crude services, which comprises our NGL business and the COLT Hub; and (iii) storage and transportation, which comprises our Tres Palacios gas storage facility and the storage and transportation operations of Inergy Midstream, including US Salt.

Gathering & Processing

Our gathering and processing (G&P) operations are conducted primarily through Crestwood Midstream, which provides gathering, compression, treating, and processing services to producers in the Marcellus Shale, the Barnett Shale, the Fayetteville Shale, the Granite Wash, the Avalon Shale/Bone Spring and the Haynesville/Bossier Shale. Our G&P operations primarily include:

• Marcellus Shale. We own and operate (i) a low-pressure natural gas gathering system with a gathering capacity of approximately 420 MMcf/d of rich gas produced by our customers in Harrison and Doddridge Counties, West Virginia, and (ii) four compression and dehydration stations located on our gathering systems in Harrison County, West Virginia;

• Barnett Shale. We own and operate (i) a low-pressure natural gas gathering system with a gathering capacity of approximately 955 MMcf/d of rich gas produced by our customers in Hood, Somervell and Johnson Counties, Texas, and delivers the rich gas to our two processing plants where NGLs are extracted from the natural gas stream; and (ii) low-pressure gathering systems with a gathering capacity of 530 MMcf/d of dry natural gas produced by our customers in Tarrant and Denton Counties, Texas;

• Fayetteville Shale. We own and operate five low-pressure gas gathering systems with a gathering capacity of approximately 510 MMcf/d of dry natural gas produced by our customers in Conway, Faulkner, Van Buren, and White Counties, Arkansas;

41

• Granite Wash. We own and operate a low-pressure natural gas gathering system with a gathering capacity of approximately 36 MMcf/d of rich gas produced by our customers in Roberts County, Texas, and a processing plant that extracts NGLs from the natural gas stream;

• Avalon Shale/Bone Spring. We own and operate three low-pressure natural gas gathering systems with a gathering capacity of approximately 50 MMcf/d of rich gas produced by our customers in Eddy County, New Mexico; and

• Haynesville/Bossier Shale. We own and operate high-pressure natural gas gathering pipelines with a gathering capacity of approximately 100 MMcf/d that provide gathering and treating services to our customers located in Sabine Parish, Louisiana.

The cash flows from our G&P operations are predominantly fee-based with creditworthy counterparties under contracts with terms that vary, the longest of which expires in 2042. The results of our G&P operations are significantly influenced by the volumes of natural gas gathered and processed through our systems. We gather, process, treat, compress, transport and sell natural gas pursuant to fixed-fee and percent-of-proceeds contracts. We do not take title to natural gas or NGLs under our fixed-fee contracts, whereas under our percent-of-proceeds contracts, we take title to the residue gas, NGLs and condensate and remit a portion of the sale proceeds to the producer based on prevailing commodity prices. For the three months ended June 30, 2013, approximately 98% of our gross margin (which we define as total revenue less product purchases) was derived from fixed-fee service contracts and approximately 2% of our G&P segment's gross margin was derived from percent-of-proceeds contracts. Our election to enter primarily into fixed-fee contracts minimizes our G&P segment's commodity price exposure and provides us more stable operating performance and cash flows.

Our two largest G&P customers are Quicksilver Resources Inc. (“Quicksilver”) and Antero Resources Appalachian Corporation (“Antero”). For the six months ended June 30, 2013, services provided to Quicksilver and Antero accounted for approximately 26% and 15% of our total revenues.

In July 2013, we acquired a 50% interest in a gathering system located in the Powder River Basin Niobrara Shale play for approximately $108 million. This system is comprised of approximately 100 miles of gathering pipelines located in Converse County, Wyoming. The system is being developed to gather and process rich natural gas produced from a 311,000 gross acres area of dedication from Chesapeake Energy Corporation and RKI Exploration & Production, LLC.

NGL and Crude Services

Our NGL and crude services segment consists of our proprietary NGL business and our COLT Hub. Our team utilizes assets we own or control to provide services to producers, refiners and other customers which effectively provide flow assurance to our customers. These services offer customers certainty of NGL and crude oil supply volumes flowing without interruption and at attractive economic value.

Our NGL and crude services business optimizes assets that we own or control, including among others (i) our West Coast processing, fractionation and storage operations, which includes 24 million gallon of NGL storage capacity, a 25 MMcf/day of natural gas processing capacity, 12,000 barrels per day of fractionation capacity, 8,000 barrels per day of butane isomerization capacity, and NGL rail and truck loading; (ii) our NGL storage facility in Seymour, Indiana, which has 21 million gallons of underground NGL storage capacity and 1.2 million gallons of aboveground “bullet” storage capacity; and (iii) our fleet of rail and rolling stock, terminals and maintenance facilities.

The COLT Hub is a crude oil terminal strategically located near the town of Epping in Williams County, North Dakota, in the heart of the Bakken and Three Forks shale oil-producing areas. With 720,000 barrels of crude oil storage and two rail loops, the terminal can accommodate 120-car unit trains and is capable of loading up to 120,000 barrels per day by rail. Customers can source product via gathering systems, a truck unloading rack and the COLT Connector, a 21-mile, 10-inch bidirectional pipeline that connects the COLT Hub to the Enbridge and Tesoro crude pipelines at Dry Fork (Beaver Lodge/Ramberg junction). The COLT Hub is connected to the Banner, Meadowlark Midstream (formerly, Bear Tracker Energy) and Hiland Pipeline crude gathering systems.

42

In May 2013, we commenced construction of an expansion of our COLT Hub that will increase our crude oil throughput and storage capacities. The expansion primarily entails the installation of additional crude oil loading arms and pumps at our rail loading rack; the construction of parallel rail tracks on which we will be able to store additional unit trains; the construction of two floating-roof crude oil storage tanks; the construction of additional truck unloading racks; and, modifications that will enable us to receive more crude oil from interconnected gathering systems. The expansion is designed to increase our unit train loading capacity to 160,000 barrels per day, our truck unloading capacity to 96,000 barrels per day, our working storage capacity to 1.08 million barrels, and our input capacity from third-party gathering systems to more than 100,000 barrels per day.

The cash flows from our NGL and crude services business represent sales to creditworthy customers typically under contracts that are less than one year in duration, and these cash flows tend to be seasonal in nature due to our customer profiles and their tendencies to purchase NGLs during peak winter periods. The cash flows from our COLT Hub are predominantly fee-based with creditworthy counterparties under three to five year contracts, and are generally economically stable and not significantly affected in the short term by changing commodity prices, seasonality or weather fluctuations.

Storage & Transportation

Our storage and transportation segment includes six natural gas and NGL storage facilities, including: (i) Stagecoach, a 26.25 Bcf multi-cycle depleted reservoir natural gas storage facility located approximately 150 miles northwest of New York City in Tioga County, New York and Bradford County, Pennsylvania; (ii) Thomas Corners, a 7.0 Bcf multi-cycle depleted reservoir natural gas storage facility located in Steuben County, New York; (iii) Steuben, a 6.2 Bcf single-turn depleted reservoir natural gas storage facility located in Steuben County, New York; (iv) Seneca Lake, a 1.45 Bcf multi-cycle salt dome reservoir natural gas storage facility located in Schuyler County, New York; (v) Tres Palacios, a 38.4 Bcf high-performance multi-cycle natural gas storage facility located in Matagorda and Wharton Counties, Texas, with an extensive header system connected to 10 interstate and intrastate pipelines and Kinder Morgan's (formerly, Copano's) Houston Central processing plant; and (vi) Bath, a 1.5 million barrel NGL storage facility located near Bath, New York.

Our storage and transportation segment includes three natural gas transmission facilities, including (i) the compression and appurtenant facilities installed by CNYOG to expand transportation capacity on the Stagecoach north and south laterals (the “North-South Facilities”), which provide 325 MMcf/d of firm interstate transportation service to shippers; (ii) the MARC I Pipeline, a 39-mile, 30-inch interstate natural gas pipeline that extends from the Stagecoach south lateral interconnect with TGP's 300 Line and Transco's Leidy Line, and capable of providing 550 MMcf/d of firm transportation service to shippers; and (iii) the East Pipeline, a 37.5-mile, 12-inch diameter intrastate natural gas pipeline in New York.

In addition, our storage and transportation segment includes US Salt, a solution mined salt production facility located on the shores of Seneca Lake outside of Watkins Glen, New York. The solution mining process used by US Salt creates salt caverns that can be developed into usable natural gas and NGL storage capacity.

The cash flows from our storage operations are predominantly fee-based with creditworthy counterparties under one to ten year contracts (Northeast storage and transportation) or one to three year contracts (Tres Palacios), and the cash flows from our transportation operations are predominantly fee-based with creditworthy counterparties under five to ten year contracts. The cash flows from our salt operations represent sales to creditworthy customers typically under contracts that are less than one year in duration, and these cash flows tend to be relatively stable and not subject to seasonal or cyclical variation due to the use of, and demand for salt products in everyday life.

Outlook and Trends

Our long-term profitability will be influenced primarily by our ability to (and to cause the MLPs we control to) execute our growth strategy, including both growth projects and strategic acquisitions, and to increase cash available for distribution from the assets we own or control. An integral part of our growth strategy entails extracting commercial synergies from the Inergy-Crestwood business combination, such as combining CMLP's gathering and processing experience with Inergy's NGL and crude services businesses to achieve commercial opportunities that were not available to us prior to the business combination. The integration of our gathering, processing, marketing, storage and transportation experience will be instrumental to our ability to derive such commercial synergies.

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Organic growth projects, including both expansions and greenfield development projects, have recently provided cost-effective options for each of Inergy Midstream and Crestwood Midstream to grow its infrastructure base. The ongoing expansion of the COLT Hub and continued build out of our Marcellus Shale rich gas gathering systems are examples of our ability to internally grow our operations at very low multiples. In general, purchasers of energy infrastructure have paid relatively high prices (measured in terms of a multiple of EBITDA or another financial metric) to acquire midstream assets and operations in recent arms-length transactions. Although the prices paid for certain types of midstream assets are likely to remain robust for the foreseeable future, acquisitions will continue to permit us to gain access to new markets (with respect to geographic footprint and product offerings) and develop the scale required to grow our businesses quickly and successfully. The acquisition of the COLT Hub and our recent Jackalope G&P investment are examples of where we believe we can cost-effectively accelerate growth through third-party acquisitions. We therefore expect to grow our business in the near term through both organic growth projects and acquisitions.

Our long-term profitability will also depend on our ability to contract and re-contract with customers and to manage increasingly difficult regulatory processes at the federal, state and local levels. The time required to secure the authorizations necessary for development projects and expansions, for both unregulated and regulated projects, and the amounts we pay to secure authorizations and land rights are increasing in most markets in which we participate. However, we remain confident that the incremental time and money required to pursue and complete market-driven facilities will deliver meaningful value to our unitholders, as the combination of the ongoing regulatory climate and the location of our assets relative to both high-demand markets and prolific shale basins effectively provides a significant barrier to entry that other market participants may find difficult to overcome.

Our natural gas storage revenues are driven in large part by competition and demand for our storage capacity and deliverability. Demand for storage in the Northeast 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. Demand for firm storage service in Texas remains depressed due to low commodity prices, an abundance of Gulf Coast storage capacity, and low seasonal spreads. In the current market conditions, we expect to generate greater revenue over the second half of the calendar year by utilizing Tres Palacios' storage capacity for hub and interruptible services, rather than selling the capacity on a firm basis. As of June 30, 2013, we are optimizing approximately 23.9 Bcf of working gas storage capacity available at Tres Palacios through hub and interruptible services.

How We Evaluate Our Operations

We evaluate our overall business performance based primarily on EBITDA and Adjusted EBITDA. We evaluate the performance of our individual segments based on gross profit (which is defined as operating revenues less product purchases). We evaluate our ability to make distributions to our unitholders based on cash available for distribution and distributions received from Inergy Midstream and Crestwood Midstream.

We do not utilize depreciation, depletion and amortization expense in our key measures because we focus our performance management on cash flow generation and our assets have long useful lives.

EBITDA and Adjusted EBITDA - We believe that EBITDA and Adjusted EBITDA are widely accepted financial indicators of a company's operational performance and its ability to incur and service debt, fund capital expenditures and make distributions. EBITDA is defined as income before income taxes, plus net interest and debt expense, and depreciation, amortization and accretion expense. In addition, Adjusted EBITDA considers the impact of certain significant items, such as the gain or loss on economically hedged transactions not designated as hedges for accounting purposes, long-term incentive and equity compensation expenses, gain on contingent consideration, and third party costs incurred related to potential and completed acquisitions and other transactions identified in a specific reporting period. EBITDA and Adjusted EBITDA are not measures calculated in accordance with accounting principles generally accepted in the United States of America (GAAP), as they do not include deductions for items such as depreciation, amortization and accretion, interest and income taxes, which are necessary to maintain our business. EBITDA and Adjusted EBITDA should not be considered an alternative to net income, operating cash flow or any other measure of financial performance presented in accordance with GAAP. EBITDA and Adjusted EBITDA calculations may vary among entities, so our computation may not be comparable to measures used by other companies.

See our reconciliation of net income to EBITDA and Adjusted EBITDA in Results of Operations below.

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Results of Operations

Three and Six Months Ended June 30, 2013 Compared with Three and Six Months Ended June 30, 2012

The following table summarizes our results of operations (in millions):

	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
Revenues	$	118.9		$	55.2		$	191.3		$	109.0
Cost of product/services sold (excluding depreciation, amortization and accretion as shown below)	52.0			7.4			65.5			16.4
Gross profit	66.9			47.8			125.8			92.6
Operating and administrative expense	31.1			18.0			51.9			34.5
Depreciation, amortization and accretion expense	28.0			19.1			50.4			35.0
Gain on contingent consideration	—			6.8			—			6.8
Operating income	7.8			17.5			23.5			29.9
Interest and debt expense, net	12.0			8.9			23.4			16.5
Provision for income taxes	0.3			0.3			0.7			0.6
Net income (loss)	(4.5		)	8.3			(0.6		)	12.8
Add:
Interest and debt expense, net	12.0			8.9			23.4			16.5
Provision for income taxes	0.3			0.3			0.7			0.6
Depreciation, amortization and accretion	28.0			19.1			50.4			35.0
EBITDA	$	35.8		$	36.6		$	73.9		$	64.9
Long-term incentive and equity compensation expense	1.4			0.5			2.0			1.0
Gain on contingent consideration	—			(6.8		)	—			(6.8		)
ASC 815 adjustment	1.6			—			1.6			—
Expenses associated with other significant items	9.0			2.3			9.7			2.3
Adjusted EBITDA	$	47.8		$	32.6		$	87.2		$	61.4

	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
EBITDA:
Net cash provided by operating activities	$	23.3		$	20.1		$	57.4		$	42.2
Net changes in working capital balances	1.9			2.2			(4.3		)	2.3
Provision for doubtful accounts	(0.1		)	—			(0.1		)	—
Amortization of deferred financing costs and bond premium	(1.1		)	(0.9		)	(2.1		)	(2.5		)
Other non-cash income	—			(0.3		)	—			—
Market adjustment on interest rate swap	0.9			—			0.9			—
Gain on contingent consideration	—			6.8			—			6.8
Long-term incentive and equity compensation expense	(1.4		)	(0.5		)	(2.0		)	(1.0		)
Interest expense and debt expense, net	12.0			8.9			23.4			16.5
Provision for income taxes	0.3			0.3			0.7			0.6
EBITDA	$	35.8		$	36.6		$	73.9		$	64.9
Long-term incentive and equity compensation expense	1.4			0.5			2.0			1.0
Gain on contingent consideration	—			(6.8		)	—			(6.8		)
ASC 815 adjustment	1.6			—			1.6			—
Expenses associated with other significant items	9.0			2.3			9.7			2.3
Adjusted EBITDA	$	47.8		$	32.6		$	87.2		$	61.4

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The following tables summarize the gross profit of our segments (in millions):

	Three Months Ended June 30, 2013
	Gathering and Processing		NGL and Crude Services		Storage and Transportation		Total
Revenues	$	71.1	$	38.1	$	9.7	$	118.9
Cost of product/services sold (excluding depreciation, amortization and accretion as shown below)	14.0		36.7		1.3		52.0
Gross profit	$	57.1	$	1.4	$	8.4	$	66.9
	Three Months Ended June 30, 2012
	Gathering and Processing		NGL and Crude Services		Storage and Transportation		Total
Revenues	$	55.2	$	—	$	—	$	55.2
Cost of product/services sold (excluding depreciation, amortization and accretion as shown below)	7.4		—		—		7.4
Gross profit	$	47.8	$	—	$	—	$	47.8
	Six Months Ended June 30, 2013
	Gathering and Processing		NGL and Crude Services		Storage and Transportation		Total
Revenues	$	143.5	$	38.1	$	9.7	$	191.3
Cost of product/services sold (excluding depreciation, amortization and accretion as shown below)	27.5		36.7		1.3		65.5
Gross profit	$	116.0	$	1.4	$	8.4	$	125.8
	Six Months Ended June 30, 2012
	Gathering and Processing		NGL and Crude Services		Storage and Transportation		Total
Revenues	$	109.0	$	—	$	—	$	109.0
Cost of product/services sold (excluding depreciation, amortization and accretion as shown below)	16.4		—		—		16.4
Gross profit	$	92.6	$	—	$	—	$	92.6

Segment Results

Below is a discussion of the factors that impacted gross profit by segment for the three and six months ended June 30, 2013 compared to the same periods in 2012.

Gathering and Processing:

Gross profit for our gathering and processing segment for the three and six months ended June 30, 2013 increased by $9.3 million and $23.4 million over the same periods in 2012. The increase was primarily due to an increase in gathering volumes in 2013 as compared to 2012, which was primarily driven by the acquisition of assets from Antero, Devon and Enerven in March 2012, August 2012 and December 2012, respectively.

For the three months ended June 30, 2013, we gathered 90.3 Bcf of natural gas compared to 74.5 Bcf of natural gas during the same period in 2012. For the six months ended June 30, 2013, we gathered 178.0 Bcf of natural gas compared to 130.0 Bcf of natural gas during the same period in 2012. This increase was primarily due to our gathering assets in the Marcellus shale, which gathered 61% more volumes during the second quarter of 2013 compared to 2012. Our capital projects and acquisitions in the Marcellus shale have significantly increased the capacity of our assets in the region, which has capitalized on increased producer activity.

Also contributing to the quarter-over-quarter increase in gathering volumes were our gathering assets in the Barnett shale, which gathered 9% more volumes during the second quarter of 2013 compared to 2012. This was primarily attributable to the acquisition of the West Johnson County gathering system from Devon, which offset production declines from Quicksilver during that period.

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NGL and Crude Services:

Our NGL and crude services segment reflects only the results of our operations from June 19, 2013 (i.e. the date that Crestwood Holdings acquired control of our general partner) to June 30, 2013. During this period, our NGL and crude services segment's gross profit was $1.4 million.

Storage and Transportation:

Our storage and transportation segment reflects only the results of our operations from June 19, 2013 (i.e. the date that Crestwood Holdings acquired control of our general partner) to June 30, 2013. During this period, our storage and transportation segment's gross profit was $8.4 million.

Other Results

EBITDA for the three and six months ended June 30, 2013 was $35.8 million and $73.9 million, an increase of $(0.8) million and $9.0 million compared to same periods in 2012. In the same manner, Adjusted EBITDA for the three and six months ended June 30, 2013 was $47.8 million and $87.2 million, an increase of $15.2 million and $25.8 million compared to the same periods in 2012. Below is a discussion of items impacting our EBITDA that are not included in our segment results described above.

Operating and Administrative Expense - During the three and six months ended June 30, 2013, operating and administrative expense increased by $13.1 million and $17.4 million when compared to the same periods in 2012. The increase was due primarily to the assets acquired from Antero, Devon and Enerven during 2012. Also contributing to the increase was approximately $9.0 million of legal and other consulting expenses we incurred to evaluate certain transaction opportunities during the three and six months ended June 30, 2013.

Also impacting our general and administrative expenses for the three and six months ended June 30, 2013 were increases in payroll and related benefit costs, which reflects the increased scope of our business operations compared to the same periods in 2012. We incurred an increase of $0.9 million and $1.0 million of expense related to our long-term incentive and equity compensation plans during the three and six months ended June 30, 2013, respectively.

Gain on Contingent Consideration - During 2012, we recognized a gain on the reversal of a liability related to contingent consideration potentially payable to Quicksilver Resources, Inc.

Items not affecting EBITDA include the following:

Depreciation, Amortization and Accretion Expense - We have experienced increases in our depreciation, amortization and accretion expense primarily due to the assets acquired from Antero, Devon and Enerven during 2012.

Interest and Debt Expense - Interest and debt expense increased for the three and six months ended June 30, 2013 compared to the same periods in 2012, primarily due to (i) higher outstanding balances on our credit facilities and (ii) the issuance of an additional $150 million of 7.75% Senior Notes in November 2012.

The following table provides a summary of interest and debt expense (in millions):

	Three Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
Credit facilities	$	4.3	$	4.9	$	8.7	$	8.1
Senior notes	7.0		4.0		14.0		8.0
Capital lease interest	0.1		—		0.1		0.1
Other debt-related costs	0.7		0.1		0.7		0.5
Gross interest and debt expense	12.1		9.0		23.5		16.7
Less: capitalized interest	0.1		0.1		0.1		0.2
Interest and debt expense, net	$	12.0	$	8.9	$	23.4	$	16.5

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Liquidity and Sources of Capital

We believe that anticipated cash from operations, cash distributions from Inergy Midstream and Crestwood Midstream, and borrowing capacity under our Credit Agreement will be sufficient to meet our liquidity needs for the foreseeable future. Moreover, given that a substantial portion of our consolidated assets are conducted through NRGM and CMLP, we do not anticipate the need for Inergy to raise additional capital in the foreseeable future. However, if our plans or assumptions change or are inaccurate, or we make acquisitions, we may need to raise additional capital. Although global financial markets and economic conditions have improved more recently, to the extent we need to raise additional capital, we cannot provide assurances that we will be able to raise the additional capital to meet these needs.

We also believe that the anticipated cash from operations and borrowing capacity under credit agreements will be sufficient for each of NRGM and CMLP to meet their liquidity needs for the foreseeable future.

Contemporaneously with the closing of the pending NRGM-CMLP merger, we expect Inergy Midstream to enter into a new five-year senior secured credit facility under which at least $1 billion of cash borrowing capacity will be made available to Inergy Midstream and its subsidiaries by a syndicate of financial institutions. We believe this facility is sized sufficiently to fund the combined organization's growth plans and working capital needs. Inergy Midstream intends to borrow funds under the new revolving credit facility (i) to repay in full and retire the NRGM Credit Facility, the CMLP Credit Facility, and the CMM Credit Facility; (ii) to pay fees and expenses relating to the merger and related transactions; and (iii) from time to time thereafter, for general partnership purposes, including acquisitions. Subject to limited exception, we expect the new credit facility to be secured by substantially all of the equity interests and assets of Inergy Midstream's subsidiaries, and to be jointly and severally guaranteed by substantially all of Inergy Midstream's subsidiaries.

See Item 1, Financial Statements, Note 7 for a more detailed description of our credit facilities.

The following table provides a summary of our cash flows by category (in millions):

	Six Months Ended June 30,
	2013			2012
Net cash provided by operating activities	$	57.4		$	42.2
Net cash used in investing activities	(78.0		)	(399.2		)
Net cash provided by financing activities	23.2			364.9

Operating Activities

During the three and six months ended June 30, 2013, we experienced an increase in our operating cash flows compared to the same periods in 2012 primarily due to higher operating revenues as a result of our asset acquisitions during 2012 partially offset by higher operations and maintenances expenses on the acquired assets. In addition, our interest costs increased due to higher outstanding balances on our credit facilities and senior notes.

Investing Activities

The midstream energy business is capital intensive, requiring significant investments for the acquisition or development of new facilities. We categorize our capital expenditures as either:

• expansion capital expenditures, which are made to construct additional assets, expand and upgrade existing systems, or acquire additional assets; or

• maintenance capital expenditures, which are made to replace partially or fully depreciated assets, to maintain the existing operating capacity of our assets, extend their useful lives or comply with regulatory requirements.

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The following table summarizes our capital expenditures for the six months ended June 30, 2013 (in millions). We have identified additional growth capital expansion project opportunities for all three of our reporting segments. A summary of the purchase commitments related to these growth capital projects is described in Contractual Obligations below. Additional commitments or expenditures will be made at our discretion, and any discontinuation of the construction of these projects will likely result in less future cash flow and earnings.

Expansion capital	$	79.2
Maintenance capital	3.0
Other(1)	1.9
Total	$	84.1

(1)     Represents capital expenditures that are reimbursable from our insurers.

Financing Activities

Significant items impacting our financing activities during the six months ended June 30, 2013 included the following:

• Net borrowings under our credit facilities of $108.5 million;

• $103.5 million in proceeds from the issuance of 4,500,000 CMLP common units in March 2013; and

• $15.5 million in proceeds from the issuance of 675,000 CMLP common units in April 2013.

In January 2013, we acquired Crestwood Holdings' 65% membership interest in CMM for $258 million, which was funded through $129 million of borrowings under the CMLP Credit Facility and the issuance of approximately $129 million of equity to Crestwood Holdings.

During the three and six months ended June 30, 2013, CMLP paid distributions to its unitholders of approximately $33 million and $58 million. On April 1, 2013, all of CMLP's Class C units automatically converted into CMLP common units on a one-for-one basis. Quarterly distributions on these converted units will be paid in cash.

In July 2013, Crestwood Niobrara acquired a 50% interest in a joint venture which was funded through CMLP's contribution of approximately $27 million (which was borrowed under the CMLP Credit Facility) and an additional $81 million was obtained through Crestwood Niobrara's issuance of a preferred interest to a subsidiary of General Electric Capital Corporation and GE Structured Finance, Inc. (collectively, GE EFS). Crestwood Niobrara will fund 75% of future capital contributions to the gathering system joint venture through additional preferred interest issuances to GE EFS (up to a maximum of $69 million), with the remainder to be funded through CMLP capital contributions to Crestwood Niobrara. CMLP serves as the managing member of Crestwood Niobrara and CMLP has the ability to redeem GE EFS's preferred security in either cash or CMLP common units, subject to certain restrictions.

Off-Balance Sheet Arrangements

We had no significant off-balance sheet arrangements as of June 30, 2013.

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Contractual Obligations

We are party to various contractual obligations. A portion of these obligations are reflected in our financial statements, such as long-term debt and other accrued liabilities, while other obligations, such as operating leases, capital commitments and contractual interest amounts are not reflected on our balance sheet. The following table and discussion summarizes our contractual cash obligations as of June 30, 2013 (in millions):

	July 1, 2013 to December 31, 2013		January 1, 2014 to December 31, 2015		January 1, 2016 to December 31, 2017		Thereafter		Total
Long-term debt:
Principal	$	2.5	$	1.2	$	1,003.0	$	862.6	$	1,869.3
Interest (a)	41.8		166.7		147.0		123.6		479.1
Future minimum payments under operating leases	3.0		32.7		36.0		323.7		395.4
Future minimum payments under capital leases	2.0		3.1		0.2		—		5.3
Asset retirement obligations	—		—		—		14.4		14.4
Fixed price commodity purchase commitments (b)	150.0		29.0		—		—		179.0
Standby letters of credit	14.3		30.9		—		—		45.2
Growth capital-related purchase commitments and other contractual obligations (c)	38.6		—		—		—		38.6
Total contractual obligations	$	252.2	$	263.6	$	1,186.2	$	1,324.3	$	3,026.3

(a) $779.9 million of our long-term debt, including interest rate swaps, is variable interest rate debt at prime rate or LIBOR plus an applicable spread. These rates plus their applicable spreads were between 1.95% and 4.5% at June 30, 2013. These rates have been applied for each period presented in the table.

(b) Fixed price purchase commitments are volumetrically offset by third party fixed price sale contracts.

(c) Includes identified growth projects related to the Watkins Glen NGL development project, the COLT Hub expansion project and certain upgrades to the US Salt facility, as well as environmental obligations included in other current liabilities on our balance sheet. Other contractual purchase obligations are defined as legally enforceable agreements to purchase goods or services that have fixed or minimum quantities and fixed or minimum variable price provisions, and that detail approximate timing of the underlying obligations.

Critical Accounting Estimates

The preparation of financial statements in conformity with United States generally accepted accounting principles requires management to select appropriate accounting estimates and to make estimates and assumptions that affect the reported amount of assets, liabilities, revenues and expenses and the disclosures of contingent assets and liabilities. We consider our critical accounting estimates to be those that require difficult, complex, or subjective judgment necessary in accounting for inherently uncertain matters and those that could significantly influence our financial results based on changes in those judgments. Changes in facts and circumstances may result in revised estimates and actual results may differ materially from those estimates. We have discussed the development and selection of the following critical accounting estimates and related disclosures with the Audit Committee of the board of directors of our General Partner.

Long-Lived Assets

Our long-lived assets consist primarily of property, plant and equipment and intangible assets that have been obtained through multiple historical business combinations. The initial recording of a majority of these long-lived assets was at fair value, which is estimated by management primarily utilizing market-related information and other projections on the performance of the assets acquired. Management reviews this information to determine its reasonableness in comparison to the assumptions utilized in determining the purchase price of the assets in addition to other market-based information that was received through the purchase process and other sources. Due to the imprecise nature of the projections and assumptions utilized in determining fair value, actual results can, and often do, differ from our estimates.

We also utilize assumptions related to the useful lives and related salvage value of our long-lived assets in order to determine depreciation and amortization expense each period. Due to the imprecise nature of the projections and assumptions utilized determining useful lives, actual results can, and often do, differ from our estimates.

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We continually monitor our business, the business environment and the performance of our operations to determine if an event has occurred that indicates that a long-lived asset may be impaired. If an event occurs, which is a determination that involves judgment, we may be required to utilize cash flow projections to assess our ability to recover the carrying value of our assets based on our long-lived assets' ability to generate future cash flows on an undiscounted basis. Projected cash flows of the asset are generally based on current and anticipated future market conditions, which require significant judgment to make projections and assumptions about pricing, demand, competition, operating costs, construction costs, legal and regulatory issues and other factors that may extend many years into the future and are often outside of our control. If those cash flow projections indicate that the long-lived asset's carrying value is not recoverable, we record an impairment charge for the excess of carrying value of the asset over its fair value. The estimate of fair value considers a number of factors, including the potential value we would receive if we sold the asset, discount rates and projected cash flows. Due to the imprecise nature of these projections and assumptions, actual results can and often do, differ from our estimates.

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.

We did not record any material impairments of our long-lived assets or losses on disposal of our long-lived assets during the three and six months ended June 30, 2013 or 2012.

Goodwill Impairment

Our goodwill represents the excess of the amount we paid for a business over the fair value of the net identifiable assets acquired. We evaluate goodwill for impairment annually, and whenever events or changes indicate that it is more likely than not that the fair value of a reporting unit could be less than its carrying amount. This evaluation requires us to compare the fair value of each of our reporting units to its carrying value (including goodwill). If the fair value exceeds the carry amount, goodwill of the reporting unit is not considered impaired.

We did not record any impairments of goodwill during the three or six months ended June 30, 2013 or 2012. We estimate the fair value of our reporting units based on a number of factors, including the potential value we would receive if we sold the reporting unit, discount rates and projected cash flows. Estimating projected cash flows 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 imprecise nature of these projections and assumptions, actual results can and often do, differ from our estimates. If the growth assumptions embodied in the current year impairment testing prove inaccurate, we could incur an impairment charge. The reverse acquisition of CMLP GP has added a significant amount of goodwill to our balance sheet.

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 commodity will be available; and (iii) manage our exposure to interest rate risk associated with fixed and variable rate borrowings. We record all derivative instruments on the balance sheet as either assets or liabilities measured at fair value. Changes in the fair value of these derivative financial instruments are recorded either through current earnings or as other comprehensive income, depending on the type of transaction.

We determine fair value of our derivative financial instruments according to the following hierarchy: (1) comparable market prices to the extent available; (2) 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.

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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 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.

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

Any ineffective portion of the fair value hedges is recognized as cost of product/services sold in the current period. We did not recognize any material gains or losses related to the ineffective portion of our fair value hedging instruments or 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 and variable interest payments. 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. In certain situations under the rules, the ineffective portion of the gain or loss is recognized as cost of product/services sold in the current period.

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

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

Self-Insurance

We are insured by third parties for both ourselves and Inergy Midstream, subject to varying retention levels of self-insurance, which management considers prudent. Such self-insurance relates to losses and liabilities primarily associated with medical claims, workers' compensation claims and general, product, vehicle and environmental liability. Losses are accrued based upon management's estimates of the aggregate liability for claims incurred using certain assumptions followed in the insurance industry and based on past experience. The primary assumption utilized is actuarially determined loss development factors. The loss development factors are based primarily on historical data. 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 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. We are liable for the development of claims for our disposed retail propane operations, provided they were reported prior to August 1, 2012. At June 30, 2013, our self-insurance reserves were $19.9 million. We estimate that $17.2 million of this balance will be paid subsequent to June 30, 2014. As such, $17.2 million has been classified in other long-term liabilities on the consolidated balance sheets.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

Interest Rate Risk

We have four credit facilities that are subject to the risk of loss associated with movements in interest rates. At June 30, 2013, we had floating rate obligations totaling $779.9 million borrowed under these credit facilities (net of certain interest rate swaps, which convert the interest rate on one of our credit facilities to a fixed rate). Floating rate obligations expose us to the risk of increased interest expense in the event of increases in short-term interest rates.

If the floating rate on our credit facilities were to fluctuate by 100 basis points from June 2013 levels, our interest expenditures would change by a total of approximately $7.8 million per year.

Commodity Price, Market and Credit Risk

Inherent in our business are certain business risks, including market risk and credit risk.

Market Risk

Market risk is the risk that the value of our NGL and crude services segment's portfolio will change, either favorably or unfavorably, in response to changing market conditions. We take an active role in managing and controlling market risk and have established control procedures, which are reviewed on an ongoing basis. We monitor market risk through a variety of techniques, including daily reporting of the portfolio's position to senior management. We attempt to minimize credit risk exposure through credit policies and periodic monitoring procedures as well as through customer deposits, letters of credit and entering into netting agreements that allow for offsetting counterparty receivable and payable balances for certain financial transactions, as deemed appropriate. The counterparties associated with assets from price risk management activities as of June 30, 2013 were energy marketers, propane retailers, resellers, and dealers.

Although our base interest rates remain low, our leverage ratios directly influence the spreads charged by lenders. The credit markets could also drive the spreads charged by lenders upward. As base rates or spreads increase, our financing costs will increase accordingly. Although this could limit our ability to raise funds in the capital markets, we expect that our competitors would face similar challenges with respect to funding acquisitions and capital projects. We are exposed to variable interest rate risk as a result of borrowings under our Credit Facility. See Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations, Critical Accounting Estimates, for more information regarding our interest rate sensitivity.

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

We rarely take title to any commodity in our storage and transportation business.

The fair value of the derivatives and inventory exchange contracts related to price risk management activities as of June 30, 2013 were assets of $15.3 million and liabilities of $8.0 million. We use observable market values for determining the fair value of our trading instruments. In cases where actively quoted prices are not available, other external sources are used that incorporate information about commodity prices in actively quoted markets, quoted prices in less active markets and other market fundamental analysis. Our risk management department regularly compares valuations to independent sources and models on a quarterly basis. A theoretical change of 10% in the underlying commodity value would result in a negligible change in the market value of the contracts as there were 0.1 million gallons of net unbalanced positions at June 30, 2013.

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Credit Risk

Credit risk is the risk of loss from nonperformance by suppliers, customers or financial counterparties to a contract. We take an active role in managing and controlling credit risk and have established control procedures, which are reviewed on an ongoing basis. Our primary credit risk relates to our dependency on Quicksilver for a portion of our revenues, which causes us to be subject to the risk of nonpayment or late payment by Quicksilver. Quicksilver's credit ratings are below investment grade, where they may remain for the foreseeable future. We have diversified this risk through having long term contracts with many investment grade customers and creditworthy producers. Additionally, we perform credit analyses of our customers on a regular basis pursuant to our corporate credit policy. We have not had any significant losses due to failures to perform by our counterparties

Item 4. Controls and Procedures

We maintain controls and procedures designed to provide a reasonable assurance that information required to be disclosed in our reports that we file or submit under the Securities Exchange Act of 1934 are recorded, processed, summarized and reported within the time periods specified by the rules and forms of the SEC, and that information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. An evaluation was performed under the supervision and with the participation of our management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as such terms are defined in Rule 13a-15(e) and 15d-15(e) of the Exchange Act). Based upon that evaluation, management, including the Chief Executive Officer and the Chief Financial Officer, concluded that our disclosure controls and procedures were effective as of June 30, 2013, at the reasonable assurance level. There have been no changes in our internal control over financial reporting except as discussed below (as defined in Rule 13(a)-15(f) or Rule 15d-15(f) of the Exchange Act) during the period ended June 30, 2013, that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

Changes in Internal Control over Financial Reporting

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

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PART II – OTHER INFORMATION

Item 1. Legal Proceedings

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

Item 1A. Risk Factors

One should carefully consider the following risk factors together, with all of the other information included in this report and those included in our Annual Report on Form 10-K for the year ended September 30, 2012, when deciding whether to invest in us. Limited partner interests are inherently different from capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. One should be aware that the occurrence of any of the events described in this report could have a material adverse effect on our business, financial condition, results of operations and cash flows. In such event, we may not be able to make distributions to our unitholders and the trading price of our common units could decline.

Risk Factors are described in “Item 1A. Risk Factors” of the Company's Report on Form 10-K for the year ended September 30, 2012 and Form 10-Q for the quarter ended  December 31, 2012.  Except where indicated below there have been no material changes thereto. The Company is supplementing its disclosure of risk factors by adding the following:

Risks Related to Crestwood Midstream's Business

Crestwood Midstream is dependent on a limited number of natural gas producers, including Quicksilver, for the natural gas it gathers, processes, treats, compresses, transports and sells. A material reduction in production by these customers would result in a material decline in its revenue and cash available for distribution.

Crestwood Midstream relies on a limited number of customers for its revenue. Its top five customers comprised approximately 85% of Crestwood Midstream's total consolidated revenues in 2012. Although many of its contracts extend to 2020 and beyond, it may be unable to negotiate on favorable terms, if at all, any extension or replacement of its contracts with such customers after the term of their respective contracts expire. Crestwood Midstream's largest customer is Quicksilver. Quicksilver's production volumes accounted for 43% of its total revenues in 2012. Crestwood Midstream also gather certain natural gas volumes that Quicksilver purchases from Eni SpA, which comprised approximately 4% of its total revenues in 2012. Crestwood Midstream expects Quicksilver to continue to account for a significant portion of its revenues in 2013.

Quicksilver has no contractual obligation to develop its properties in the areas covered by their dedication to Crestwood Midstream and it may determine that it is strategically more attractive to direct its capital spending and resources to other areas. A decrease in Quicksilver's capital spending and reserves in the areas covered by their dedication to Crestwood Midstream could result in reduced natural gas gathered and processed by Crestwood Midstream and a material decline in its revenue and cash flow.

Furthermore, the credit ratings of Quicksilver are below investment grade. Accordingly, the risk of loss resulting from any material non-payment or non-performance by Quicksilver is higher than it would be with a more creditworthy customer, especially in light of the significant concentration of business conducted with Quicksilver. Unless and until Crestwood Midstream significantly diversifies its customer base, Crestwood Midstream expects to remain subject to non-diversified risk of non-payment or late payment of its fees. In addition, Quicksilver is highly leveraged and subject to its own operating and regulatory risks, which could increase the risk that it may default on its obligations to Crestwood Midstream.

Crestwood Midstream may not have sufficient available cash to enable it to make cash distributions to holders of our common units at the current distribution rate under our cash distribution policy.

In order to pay cash distributions of $0.51 per unit per quarter (based on the distribution declared in July 2013), or $2.04 per unit per year, Crestwood Midstream must generate available cash of approximately $32.7 million per quarter, or $130.8 million per year based on the number of general partner units and common units outstanding on June 30, 2013. Crestwood Midstream may not have sufficient available cash from operating surplus each quarter to enable it to pay the announced distributions. The amount of cash Crestwood Midstream can distribute depends principally upon the amount of cash it generates from its operations, which may fluctuate from quarter to quarter based on, among other things:

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• the fees it charges and the margins it realizes for its services;

• the level of production, and the prices of, natural gas, NGLs, and condensate;

• the volume of natural gas and NGLs it gathers and processes;

• the level of competition from other midstream energy companies;

• the level of its operating and maintenance and general and administrative costs;

• prevailing economic conditions;

• the level of capital expenditures it make;

• its ability to make borrowings under its Credit Facility;

• the cost of acquisitions;

• its debt service requirements;

• fluctuations in its working capital needs;

• its ability to access capital markets;

• compliance with its debt agreements; and

• the amount of cash reserves established by its General Partner.

The amount of cash Crestwood Midstream has available for distribution to holders of its common units depends primarily on its cash flow and not solely on profitability. Accordingly Crestwood Midstream may be prevented from making distributions, even during periods in which it records net income.

The amount of cash Crestwood Midstream has available for distribution depends primarily upon its cash flow and not solely its profitability, which may be affected by non-cash items. As a result, Crestwood Midstream may make cash distributions during periods when we report net losses, and conversely, Crestwood Midstream might fail to make cash distributions during periods when it reports net profits.

Estimates of oil and gas reserves depend on many assumptions that may turn out to be inaccurate. Therefore, future volumes of natural gas on our systems could be less than we anticipate and could adversely affect Crestwood Midstream's financial performance.

Crestwood Midstream does not typically obtain independent evaluations of natural gas reserves connected to its systems. Accordingly, Crestwood Midstream does not have independent estimates of total reserves dedicated to its systems or the anticipated life of such reserves. If the total reserves or estimated life of the reserves connected to its systems is less than it anticipates and Crestwood Midstream is unable to secure additional sources of natural gas, it could have a material adverse effect on its business, results of operations and financial condition.

Because of the natural decline in production from existing wells in Crestwood Midstream's areas of operations, its success depends on our ability to obtain new sources of natural gas which is dependent on factors beyond its control. Any decrease in available supplies of natural gas could result in a material decline in the volumes Crestwood Midstream gathers, processes, treats and compresses.

Crestwood Midstream's gathering systems are connected to wells whose production will naturally decline over time, which means that its cash flows associated with these wells will also decline over time. To maintain or increase throughput levels on its system, Crestwood Midstream must continually obtain new natural gas supplies. Crestwood Midstream's ability to obtain additional sources of natural gas depends in part on the level of successful drilling activity near its pipeline systems by its customers and its ability to compete for volumes against other midstream service providers.

While Crestwood Midstream has dedications from its customers which include certain producing and non-producing oil and gas properties, it has no control over the level of drilling activity in its areas of operations, the amount of reserves associated with the wells drilled, rate at which wells are produced or the rate at which production from a well will decline. In addition, Crestwood Midstream has no control over producers' drilling or production decisions, which are affected by, among other things, prevailing and projected energy prices, demand for hydrocarbons, the level of reserves, geological considerations, governmental regulations, availability of drilling rigs and other production and development services and the availability and cost of capital. Fluctuations in energy prices can greatly affect investments to develop natural gas reserves. Drilling activity generally decreases as natural gas prices decrease. Declines in natural gas prices could have a negative impact on exploration, development and production activity and, if sustained, could lead to a material decrease in such activity. Reductions in exploration or production activity in Crestwood Midstream's areas of operations could lead to reduced utilization of its systems. Because of these factors, even if natural gas reserves are known to exist in areas served by its assets, producers may choose not to develop those reserves. Moreover, Crestwood Midstream's customers are not contractually obligated to develop the reserves and or properties they have dedicated to Crestwood Midstream. If reductions in drilling activity or increased competition result in Crestwood Midstream's inability to obtain new sources of supply to replace the natural decline of volumes from existing

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wells, throughput on its systems would decline, which could reduce our revenue, cash flow and cash available for distribution to its unitholders.

In addition, various federal and state initiatives are underway to regulate, or further investigate, the environmental impacts of hydraulic fracturing, a practice that involves the pressurized injection of water, chemicals and other substances into rock formations to stimulate hydrocarbon production. Hydraulic fracturing has also generated publicity regarding its potential environmental impact. The adoption of any future federal, state or local laws or regulations imposing additional permitting, disclosure or regulatory obligations related to, or otherwise restricting or increasing costs regarding the use of hydraulic fracturing could make it more difficult to drill certain oil and natural gas wells. As a result, the volume of natural gas or associated NGLs that Crestwood Midstream gathers and processes from wells that use hydraulic fracturing could be substantially reduced, which could adversely affect its business, financial condition, results of operations and cash available for distributions to its unitholders.

Crestwood Midstream's construction of new assets may not result in revenue increases and is subject to regulatory, environmental, safety, political, legal and economic risks, which could adversely affect its cash flow, results of operations and financial condition.

One of the ways Crestwood Midstream intends to grow its business is through the construction of new midstream assets. Additions or modifications to its asset base involve numerous regulatory, environmental, safety, political and legal uncertainties beyond its control and may require the expenditure of significant amounts of capital. If Crestwood Midstream undertakes these projects, they may not be completed on schedule, at the budgeted cost, or at all. Moreover, Crestwood Midstream's revenue may not increase as anticipated for a particular project. For instance, Crestwood Midstream may construct facilities to capture anticipated future growth in production in a region in which such growth does not materialize. Since Crestwood Midstream is not engaged in the exploration for and development of natural gas reserves, it may not have access to third party estimates of potential reserves in an area prior to constructing or acquiring facilities in such area. To the extent Crestwood Midstream relies on estimates of future production by parties in its decision to expand its systems, such estimates may prove to be inaccurate due to numerous uncertainties inherent in estimating quantities of future production. As a result, new facilities may not be able to attract enough throughput to achieve Crestwood Midstream's expected investment return, which could adversely affect its results of operations and financial condition. In addition, expansion of Crestwood Midstream's asset base generally requires it to obtain new rights-of-way. Crestwood Midstream may be unable to obtain such rights-of-way or it may become more expensive for it to obtain or renew rights-of-way. If the cost of rights-of-way increases, our cash flow could be adversely affected.

If Crestwood Midstream does not make acquisitions on economically acceptable terms, its future growth will be limited.

In addition to expanding its existing systems, one of Crestwood Midstream's primary strategies is to pursue acquisitions. If Crestwood Midstream is unable to make these acquisitions because it is: (1) unable to identify attractive acquisition candidates, to analyze acquisition opportunities successfully from an operational and financial point of view or to negotiate acceptable purchase contracts with them; (2) unable to obtain financing for these acquisitions on economically acceptable terms; or (3) outbid by competitors, then its future growth could be limited. Furthermore, even if Crestwood Midstream does make acquisitions, these acquisitions may not result in an increase in the cash generated by operations.

Any acquisition involves potential risks, including, among other things:

• incorrect assumptions about volumes, revenues and costs, including synergies;

• an inability to successfully integrate the assets we acquire;

• the assumption of unknown liabilities;

• limitations on rights to indemnity from the seller;

• incorrect assumptions about the overall costs of equity or debt;

• the diversion of management's and employees' attention from other business matters;

• unforeseen difficulties of operating in new product areas, with new customers, or new geographic areas;

• customer or key employee losses at the acquired businesses;

• an inability to secure adequate customer commitments to use the acquired systems or facilities;

• operating a larger combined organization and adding operations;

• maintaining an effective system of internal controls related to the acquired business and integrating internal controls, compliance under the Sarbanes Oxley Act of 2002 and other regulatory compliance and corporate governance matters; and

• potential environmental or regulatory compliance matters or liabilities and title issues, including certain liabilities arising from the operation of the acquired business before the acquisition.

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Any of the above risks could significantly impair our ability to manage our business and materially and adversely affect our business, results of operations and financial condition.

Crestwood Midstream depends on its midstream assets to generate its revenues, and if the utilization of these assets was reduced significantly, there could be a material adverse effect on its revenues, earnings and ability to make cash distributions to its unitholders.

Operations of Crestwood Midstream's midstream assets could be partially curtailed or completely shut down, temporarily or permanently, as a result of:

• operational problems, labor difficulties or environmental proceedings or other litigation;

• catastrophic events at its facilities or at downstream facilities owned by others;

• lack of transportation or fractionation capacity;

• an inability to obtain sufficient quantities of natural gas; or

• prolonged reductions in exploration or production activity by producers in the areas in which it operates.

The magnitude of the effect on us of any curtailment of Crestwood Midstream's operations will depend on the length of the curtailment and the extent of the operations affected by such curtailment. Crestwood Midstream has no control over many of the factors that may lead to a curtailment of operations. In the event that Crestwood Midstream is unable to provide gathering, processing, treating, compression, transportation or sales services for 60 consecutive days its producers may have the right to deliver their gas to alternative pipelines. If such a termination were to occur, it could cause our revenues, earnings and cash flow to decrease.

Crestwood Midstream cannot control the operations of third party NGL fractionation and natural gas and NGL transportation facilities, and its business, results of operations, financial condition and cash available for distribution could be adversely affected.

Crestwood Midstream depends upon third-party NGL transportation and fractionation systems that it does not own. Since Crestwood Midstream does not own or operate these assets, their continuing operation is not within its control. If any of these third party pipelines and other facilities becomes unavailable or capacity constrained, it could have a material adverse effect on Crestwood Midstream's business, results of operations, financial condition and cash available for distribution to its unitholders.

If one of Crestwood Midstream's gas gathering agreements were to be terminated by a customer as a result of Crestwood Midstream's failure to perform certain obligations under the agreement, and Crestwood Midstream was unable to secure comparable alternative arrangements, Crestwood Midstream's financial condition, results of operations, cash flows and ability to make cash distributions to its unitholders would be adversely affected.

Crestwood Midstream's gas gathering agreements are terminable if it fails to perform any of its material obligations and fails to correct such non-performance within specified periods. To the extent a customer terminates a gas gathering agreement or there is a reduction in our minimum volume commitments, Crestwood Midstream's business, results of operation, financial condition and ability to make cash distributions to its unitholders may be adversely affected.

A change in the jurisdictional characterization of some of Crestwood Midstream's assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of its assets, which may cause its revenues to decline and operating expenses to increase.

Crestwood Midstream's operations are generally exempt from the jurisdiction and regulation of the FERC, except that Crestwood Midstream is subject to the anti-market manipulation provisions in the Natural Gas Act, as amended by the Energy Policy Act of 2005, and to the FERC's regulations thereunder, including the FERC's authority to impose fines of up to $1 million per day per violation. Notwithstanding, FERC regulation still affects these businesses and the markets for products derived from these businesses. The FERC's policies and practices across the range of its oil and natural gas regulatory activities, including, for example, its policies on open access transportation, rate making, capacity release and market center promotion, indirectly affect intrastate markets. In recent years, the FERC has pursued pro-competitive policies in its regulation of interstate oil and natural gas pipelines. However, we have no assurance that the FERC will continue this approach as it considers matters such as pipeline rates and rules and policies that may affect rights of access to oil and natural gas transportation capacity. In addition, the distinction between FERC-regulated transmission services and federally unregulated gathering services has regularly been the subject of substantial, on-going litigation. Consequently, the classification and regulation of some of Crestwood Midstream's pipelines could change based on future determinations by the FERC, the courts

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or Congress. If Crestwood Midstream's gas gathering operations become subject to FERC jurisdiction, the result may adversely affect the rates Crestwood Midstream is able to charge and the services it currently provides, and may include the potential for a termination of the gathering and processing agreements with its customers.

State and municipal regulations also affect Crestwood Midstream's business. Common purchaser statutes generally require gatherers to gather or provide services without undue discrimination as to source of supply or producer; as a result, these statutes restrict Crestwood Midstream's right to decide whose production it gathers. Federal law leaves any economic regulation of natural gas gathering to the states. The states in which Crestwood Midstream currently operates have adopted complaint-based regulation of gathering activities, which allows oil and natural gas producers and shippers to file complaints with state regulators in an effort to resolve access and rate grievances. Other state and municipal regulations may not directly regulate Crestwood Midstream's business, but may nonetheless affect the availability of natural gas for purchase, processing and sale, including state regulation of production rates and maximum daily production allowable from gas wells. While Crestwood Midstream's gathering lines currently are subject to limited state regulation, there is a risk that state laws will be changed, which may give producers a stronger basis to challenge the rates, terms and conditions of its gathering lines.

Crestwood Midstream is subject to environmental laws, regulations and permits, including greenhouse gas requirements that may expose it to significant costs, liabilities and obligations.

Crestwood Midstream is subject to stringent and complex federal, state and local environmental laws, regulations and permits, relating to, among other things, the generation, storage, handling, use, disposal, movement and remediation of natural gas, NGLs, crude oil and other hazardous materials; the emission and discharge of such materials to the ground, air and water; wildlife protection; and the health and safety of our employees. Failure to comply with these environmental requirements may result in Crestwood Midstream being subject to litigation, fines or other sanctions, including the revocation of permits and suspension of operations. Crestwood Midstream may incur significant compliance related costs and other associated expenses related to such requirements.

Crestwood Midstream could be liable for any environmental contamination at its or its predecessors' currently or formerly owned or operated properties or third party waste disposal sites, regardless of whether Crestwood Midstream was at fault. In addition to potentially significant investigation and remediation costs, such matters can give rise to claims from governmental authorities and other third parties for fines or penalties, natural resource damages, personal injury and property damage.

Moreover, stricter laws, regulations or enforcement policies could significantly increase Crestwood Midstream's operational or compliance costs and the cost of any remediation that may become necessary. For instance, since August 2009, the Texas Commission on Environmental Quality has conducted a series of analyses of air emissions in the Barnett Shale area in response to reported concerns about high concentrations of benzene in the air near drilling sites and natural gas processing facilities, and the analysis could result in the adoption of new air emission regulatory or permitting limitations that could require Crestwood Midstream to incur increased capital or operating costs. Additionally, environmental groups have advocated increased regulation and a moratorium on the issuance of drilling permits for new natural gas wells in developed or developing shale areas. The adoption of any laws, regulations or other legally enforceable mandates that result in more stringent air emission limitations or that restrict or prohibit the drilling of new natural gas wells for any extended period of time could increase Crestwood Midstream's operating and compliance costs as well as reduce the rate of production of natural gas operators with whom the Crestwood Midstream has a business relationship, which could have a material adverse effect on Crestwood Midstream's results of operations and cash flows.

These laws, regulations and permits, and the enforcement and interpretation thereof, change frequently and generally have become more stringent over time. In particular, requirements pertaining to air emissions, including volatile organic compound emissions, have been implemented or are under development that could lead Crestwood Midstream to incur significant costs or obligations or curtail Crestwood Midstream's operations. For example, GHG emission regulation has become more stringent. We are currently required to report annual GHG emissions from some of our operations, and additional GHG emission-related requirements are in various stages of development. In addition, the EPA has now begun regulating GHG emissions from stationary sources pursuant to the Prevention of Significant Deterioration and Title V provisions of the CAA. Such regulations could require Crestwood Midstream to modify existing or obtain new permits, implement additional pollution control technology, curtail operations or increase significantly its operating costs in the future. Any regulation of GHG emissions, including through a cap-and-trade or similar emissions trading schemes, technology mandate, emissions tax, reporting requirement or other program, could adversely affect Crestwood Midstream's business, reputation, operating performance and product demand. In addition, to the extent climate change results in more severe weather, our customers' operations may be disrupted, which could reduce product demand.

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In addition, various federal and state initiatives are underway to regulate, or further investigate the environmental impacts of hydraulic fracturing, a practice that involves the pressurized injection of water, chemicals and other substances into rock formations to stimulate hydrocarbon production. To the extent these initiatives reduce the volume of natural gas or associated NGLs that we gather and process, they could adversely affect Crestwood Midstream's business.

Crestwood Midstream's costs, liabilities and obligations relating to environmental matters could have a material adverse effect on its business, reputation, results of operations and financial condition.

Crestwood Midstream may incur costs as a result of pipeline integrity management program testing.

The DOT requires pipeline operators to develop integrity management programs for pipelines located where a leak or rupture could harm “high consequence areas.” The regulations require operators, including Crestwood Midstream, to:

• perform ongoing assessments of pipeline integrity;

• identify and characterize applicable threats to pipeline segments that could impact a high consequence area;

• maintain processes for data collection, integration and analysis;

• repair and remediate pipelines as necessary; and

• implement preventive and mitigating actions.

Crestwood Midstream currently estimates that we will incur total future costs of approximately $1 million through 2016 to complete the testing required by existing DOT regulations. This estimate does not include the costs, if any, for repair, remediation, preventative or mitigating actions that may be determined to be necessary as a result of the testing program itself.

Crestwood Midstream may incur costs as a result of additional pipeline safety legislation.

The Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 was enacted by Congress in December 2011 and signed into law by the President on January 3, 2012. In addition to reauthorizing federal pipeline safety programs through 2015, this legislation adopts additional safety requirements and reforms and increases penalties for safety violations. The PHMSA has also published an advanced notice of proposed rule making to solicit comments on the need for changes to its safety regulations, including whether to revise the integrity management requirements and add new regulations governing the safety of gathering lines. Such legislative and regulatory changes could have a material effect on Crestwood Midstream's operations through more stringent and comprehensive safety regulations and higher penalties for the violation of those regulations.

Crestwood Midstream's level of indebtedness could adversely affect its ability to raise additional capital to fund its operations, limit its ability to react to changes in its business or its industry and place it at a competitive disadvantage.

Crestwood Midstream had approximately $779 million of long-term debt outstanding as of June 30, 2013. Crestwood Midstream's inability to generate sufficient cash flow to satisfy its debt obligations or to obtain alternative financing could materially and adversely affect its business, results of operations, financial condition and business prospects.

Crestwood Midstream's substantial debt could have important consequences to its unitholders. For example, it could:

• increase Crestwood Midstream's vulnerability to general adverse economic and industry conditions;

• limit Crestwood Midstream's ability to fund future capital expenditures and working capital, to engage in development activities, or to otherwise realize the value of its assets and opportunities fully because of the need to dedicate a substantial portion of its cash flow from operations to payments of interest and principal on its debt or to comply with any restrictive covenants or terms of its debt;

• result in an event of default if Crestwood Midstream fails to satisfy its obligations with respect to its indebtedness or fail to comply with the financial and other restrictive covenants contained in the agreements governing its indebtedness, which event of default could result in all of Crestwood Midstream's debt becoming immediately due and payable and could permit its lenders to foreclose on any of the collateral securing such debt;

• require a substantial portion of cash flow from operations to be dedicated to the payment of principal and interest on its indebtedness, therefore reducing Crestwood Midstream's ability to use its cash flow to fund its operations, capital expenditures and future business opportunities;

• increase Crestwood Midstream's borrowings;

60

• restrict Crestwood Midstream from making strategic acquisitions or causing it to make non-strategic divestitures;

• limit Crestwood Midstream's flexibility in planning for, or reacting to, changes in its business or industry in which it operates, placing it at a competitive disadvantage compared to its peers who are less highly leveraged and who therefore may be able to take advantage of opportunities that Crestwood Midstream's leverage prevents it from exploring; and

• impair Crestwood Midstream's ability to obtain additional financing in the future.

Realization of any of these factors could adversely affect Crestwood Midstream's financial condition, results of operations and cash flows.

If Crestwood Midstream is unable to obtain needed capital or financing on satisfactory terms, its ability to make cash distributions may be diminished and its financial leverage could increase.

Historically, Crestwood Midstream has used its cash flow from operations, borrowings under its Credit Facility and issuances of equity to fund its capital program, working capital needs and acquisitions. Crestwood Midstream's capital program may require additional financing above the level of cash generated by its operations to fund its growth. If Crestwood Midstream's cash flow from operations decreases as a result of lower throughput volumes on its gathering and processing systems or otherwise, its ability to expend the capital necessary to expand its business or increase its future cash distributions may be limited. If Crestwood Midstream's cash flow from operations is insufficient to satisfy its financing needs, Crestwood Midstream cannot be certain that additional financing will be available to it on acceptable terms or at all. Crestwood Midstream's ability to obtain bank financing or to access the capital markets for future equity or debt offerings may be limited by its financial condition or general economic conditions at the time of any such financing or offering. Even if Crestwood Midstream is successful in obtaining the necessary funds, the terms of such financings could have a material adverse effect on its business, results of operation, financial condition and ability to make cash distributions to its unitholders. Further, incurring additional debt may significantly increase Crestwood Midstream's interest expense and financial leverage and issuing additional limited partner interests may result in significant unitholder dilution and would increase the aggregate amount of cash required to maintain the cash distribution rate which could materially decrease its ability to pay distributions. If additional capital resources are unavailable, Crestwood Midstream may curtail its activities or be forced to sell some of its assets on an untimely or unfavorable basis.

Increases in interest rates could adversely impact Crestwood Midstream's unit price, its ability to issue equity or incur debt for acquisitions or other purposes, and its ability to make payments on its debt obligations.

Interest rates may increase in the future. As a result, interest rates on future credit facilities and debt offerings could be higher than current levels, causing Crestwood Midstream's financing costs to increase accordingly. Therefore, changes in interest rates either positive or negative, may affect the yield requirements of investors who invest in Crestwood Midstream units, and a rising interest rate environment could have an adverse impact on Crestwood Midstream's unit price and its ability to issue equity or incur debt for acquisitions or other purposes and to make payments on its debt obligations.

Crestwood Midstream does not own all of the land on which our pipelines and facilities are located, which could disrupt its operations.

Crestwood Midstream does not own all of the land on which our pipelines and facilities have been constructed, which subjects us to the possibility of more onerous terms or increased costs to obtain and maintain valid easements and rights-of-way. Crestwood Midstream obtains standard easement rights to construct and operate its pipelines on land owned by third parties. Crestwood Midstream's rights generally revert back to the landowner after it stops using the easement for its specified purpose.

Therefore, these easements exist for varying periods of time. Crestwood Midstream's loss of easement rights could have a material adverse effect on its ability to operate its business, thereby resulting in a material reduction in its revenue, earnings and ability to make cash distributions to its unitholders.

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Crestwood Midstream's business involves many hazards and operational risks, some of which may not be adequately covered by insurance. The occurrence of a significant accident or other event that is not adequately insured could curtail its operations and have a material adverse effect on its business, results of operations, financial condition and ability to make cash distributions to its unitholders.

Crestwood Midstream's operations are subject to many risks inherent in the midstream industry including:

• damage to pipelines and plants, related equipment and surrounding properties caused by natural disasters and acts of terrorism;

• inadvertent damage from construction, farm and utility equipment;

• leaks or losses of natural gas or NGLs as a result of the malfunction of equipment or facilities;

• fires and explosions;

• cyber intrusions; and

• other hazards that could also result in personal injury, loss of life, pollution or suspension of operations.

These risks could result in curtailment or suspension of its related operations. A natural disaster or other hazard affecting the areas in which Crestwood Midstream operates could have a material adverse effect on its operations. Hostile cyber intrusions, including those targeting sensitive customer information, employee and vendor information maintained by Crestwood Midstream in the normal course of business, as well as breaches in the technology used in its business processes, could severely disrupt business operations and result in loss of service to customers, as well as significant expense to repair security breaches or system damage. Crestwood Midstream maintains insurance against some, but not all, of such risks and losses in accordance with customary industry practice. For example, Crestwood Midstream does not have any property insurance on any of its underground pipeline systems that would cover damage to the pipelines. Crestwood Midstream is not insured against all environmental incidents, claims or damages that might occur. Any significant accident or event that is not adequately insured could adversely affect its business, results of operations and financial condition. In addition, Crestwood Midstream may be unable to economically obtain or maintain the insurance that it desires. As a result of market conditions, premiums and deductibles for certain of its insurance policies could escalate further. In some instances, certain insurance could become unavailable or available only at reduced coverage levels. Any type of catastrophic event could have a material adverse effect on Crestwood Midstream's business, results of operations, financial condition and ability to make cash distributions to its unitholders.

The loss of key personnel could adversely affect Crestwood Midstream's ability to operate.

Crestwood Midstream's success is dependent upon the efforts of its senior management, as well as on its ability to attract and retain senior management. Crestwood Midstream's senior executive officers have significant experience in the natural gas industry and have developed strong relationships with a broad range of industry participants. The loss of any of these executives could prevent Crestwood Midstream from implementing its business strategy and have a material adverse effect on its relationships with these industry participants, its results of operations and ability to make cash distributions to its unitholders.

Crestwood Midstream does not have employees. Crestwood Midstream relies solely on officers and employees of Crestwood Holdings to operate and manage its business.

Crestwood Midstream's industry is highly competitive, and increased competitive pressure could adversely affect its ability to execute its growth strategy.

Crestwood Midstream competes with similar enterprises in its areas of operation. Crestwood Midstream's competitors may expand or construct gathering systems and associated infrastructure that would create additional competition for the services Crestwood Midstream provides its customers. Crestwood Midstream's ability to renew or replace existing contracts with its customers at rates sufficient to maintain current revenues and cash flow could be adversely affected by the activities of its competitors and its customers. All of these competitive pressures could have a material adverse effect on Crestwood Midstream's business, results of operations, financial condition and ability to make cash distributions to its unitholders.

Crestwood Midstream may conduct certain operations through joint ventures that may limit its operational flexibility.

Prior to January 8, 2013, Crestwood Midstream's operations in the Marcellus Shale region were conducted through joint venture arrangements, and Crestwood Midstream may enter additional joint ventures in the future. In a joint venture arrangement, Crestwood Midstream could have less operational flexibility, as actions must be taken in accordance with the applicable governing provisions of the joint venture. In certain cases Crestwood Midstream:

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• could have limited ability to influence or control certain day to day activities affecting the operations;

• could have limited control on the amount of capital expenditures that we are required to fund with respect to these operations;

• could be dependent on third parties to fund their required share of capital expenditures;

• may be subject to restrictions or limitations on its ability to sell or transfer our interests in the jointly owned assets; and

• may be forced to offer rights of participation to other joint venture participants in certain areas of mutual interest.

In addition, Crestwood Midstream's joint venture participants may have obligations that are important to the success of the joint venture, such as the obligation to pay substantial carried costs pertaining to the joint venture and to pay their share of capital and other costs of the joint venture. The performance and ability of the third parties to satisfy their obligations under joint venture arrangements is outside Crestwood Midstream's control. If these parties do not satisfy their obligations under these arrangements, Crestwood Midstream's business may be adversely affected. Crestwood Midstream's joint venture partners may be in a position to take actions contrary to our instructions or requests or contrary to Crestwood Midstream's policies or objectives, and disputes between Crestwood Midstream and its joint venture partners may result in delays, litigation or operational impasses. The risks described above or the failure to continue Crestwood Midstream's joint ventures or to resolve disagreements with Crestwood Midstream's joint venture partners could adversely affect Crestwood Midstream's ability to conduct business that is the subject of a joint venture, which could in turn negatively affect its financial condition and results of operations.

Crestwood Midstream is currently solely reliant on the performance of its midstream business and assets, and as a result of this lack of diversification, Crestwood Midstream's ability to make distributions to its unitholders could be adversely impacted.

Given the concentration inherent in Crestwood Midstream's business, in that it is entirely reliant on the revenues and cash flows generated from its midstream business and its assets, any adverse developments in the midstream energy industry could impact Crestwood Midstream's ability to generate sufficient cash flows, which could affect the level of distributions to its unitholders.

If Crestwood Midstream fails to maintain effective internal control over financial reporting, it may have material misstatements in its financial statements, and it may not be able to report its financial results in a timely and reliable manner.

Crestwood Midstream has established internal controls over financial reporting. However, internal controls over financial reporting may not prevent or detect misstatements because of their inherent limitations, including the possibility of human error, the circumvention or overriding of controls or fraud. Therefore, even effective internal controls can provide only reasonable assurance with respect to the preparation and fair presentation of financial statements. If Crestwood Midstream fails to maintain the adequacy of its internal controls, it may be unable to provide financial information in a timely and reliable manner. Any such difficulties or failure may have a material adverse effect on Crestwood Midstream's business, financial condition and operating results.

During the course of the preparation of its financial statements, Crestwood Midstream evaluates its internal controls to identify and remediate deficiencies in its internal controls over financial reporting. In the event Crestwood Midstream is unable to identify and correct deficiencies in its internal controls in a timely manner, Crestwood Midstream may not record, process, summarize and report financial information accurately and within the time periods required for its financial reporting under the terms of the agreements governing its indebtedness or within the required deadlines established by the SEC.

Failure to maintain effective internal control over financial reporting could result in investigations or sanctions by regulatory authorities, cause unitholders to lose confidence in our reported financial condition, lead to a default under its Credit Facility and otherwise materially adversely affect Crestwood Midstream's business, financial condition and results of operations.

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

Information previously provided in Form 8-K filed on June 19, 2013.

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Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

Item 6. Exhibits

3.1	Certificate of Limited Partnership of Inergy, L.P. (incorporated herein by reference to Exhibit 3.1 to Inergy, L.P.'s Registration Statement on Form S-1 (Registration No. 333-56976) filed on March 14, 2001)
3.1A	Certificate of Correction of Certificate of Limited Partnership of Inergy, L.P. (incorporated herein by reference to Exhibit 3.1 to Inergy, L.P.'s Form 10-Q filed on May 12, 2003)
3.2	Fourth Amended and Restated Agreement of Limited Partnership of Inergy, L.P. dated as of June 19, 2013 (incorporated herein by reference to Exhibit 10.1 to Inergy, L.P.'s Form 8-K filed on June 19, 2013)
3.3	Certificate of Formation of Inergy GP, LLC (incorporated herein by reference to Exhibit 3.5 to Inergy, L.P.'s Registration Statement on Form S-1/A (Registration No. 333-56976) filed on May 7, 2001)
3.4	First Amended and Restated Limited Liability Company Agreement of Inergy GP, LLC dated as of September 27, 2012 (incorporated herein by reference to Exhibit 3.1 to Inergy, L.P.'s Form 8-K filed on September 27, 2012)
*31.1	Certification of Chief Executive Officer of Inergy, L.P. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
*31.2	Certification of Chief Financial Officer of Inergy, L.P. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
*32.1	Certification of Chief Executive Officer of Inergy, L.P. pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
*32.2	Certification of Chief Financial Officer of Inergy, L.P. pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
**101.INS	XBRL Instance Document
**101.SCH	XBRL Taxonomy Extension Schema Document
**101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
**101.LAB	XBRL Taxonomy Extension Label Linkbase Document
**101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document
**101.DEF	XBRL Taxonomy Extension Definition Linkbase Document

*

Filed herewith

**

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

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SIGNATURE

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

		INERGY, L.P.
		By:	INERGY GP, LLC
			(its general partner)
Date:	August 7, 2013	By:	/s/ MICHAEL J. CAMPBELL
			Michael J. Campbell
			Senior Vice President and Chief Financial Officer
			(Duly Authorized Officer and Principal Financial Officer)

65

EX-31.1

Exhibit 31.1

CERTIFICATIONS

I, Robert G. Phillips, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Inergy, L.P. (the “registrant”);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over the financial reporting (as defined in Exchange Act Rules 13a-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: August 7, 2013

/s/ Robert G. Phillips

Robert G. Phillips

Chairman, President and Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATIONS

I, Michael J. Campbell, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Inergy, L.P. (the “registrant”);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over the financial reporting (as defined in Exchange Act Rules 13a-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: August 7, 2013

/s/ Michael J. Campbell

Michael J. Campbell

Senior Vice President and Chief Financial Officer

EX-32.1

Exhibit 32.1

Certification of the Chief Executive Officer

Pursuant to 18 U.S.C. Section 1350

As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the Quarterly Report of Inergy, L.P. (the “Company”) on Form 10-Q for the period ended June 30, 2013, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Robert G. Phillips, Chief Executive Officer of Inergy, L.P., certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Robert G. Phillips

Robert G. Phillips

Chief Executive Officer

August 7, 2013

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.2

Exhibit 32.2

Certification of the Chief Financial Officer

Pursuant to 18 U.S.C. Section 1350

As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the Quarterly Report of Inergy, L.P. (the “Company”) on Form 10-Q for the period ended June 30, 2013, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Michael J. Campbell, Chief Financial Officer of Inergy, L.P., certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Michael J. Campbell

Michael J. Campbell

Chief Financial Officer

August 7, 2013

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

XML

Segments

6 Months Ended

Jun. 30, 2013

Segment Reporting [Abstract]

Segments

Segments

In conjunction with the June 19, 2013 transactions described in Note 1, Inergy modified its segments and now our financial statements reflect three operating and reporting segments: (i) gathering and processing operations; (ii) NGL and crude services operations; and (iii) storage and transportation operations. Inergy's gathering and processing operations engage in the gathering, processing, treating, compression, transportation and sales of natural gas and the delivery of NGLs. Inergy's NGL and crude services operations provide NGLs and crude oil marketing, supply and logistics services to producers, refiners, petrochemical companies, marketers, and others that effectively provide flow assurances to our customers. Inergy's storage and transportation operations provide natural gas and NGL storage and transportation services to third parties, as well as the production and sale of salt products.

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

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

	Three Months Ended June 30, 2013
	Gathering and Processing Operations		NGL and Crude Services Operations		Storage and Transportation Operations		Intersegment Operations		Corporate Assets		Total
Gathering and processing revenues	$	71.1	$	—	$	—	$	—	$	—	$	71.1
Supply and logistics revenues	—		38.1		—		—		—		38.1
Storage and transportation revenues	—		—		9.7		—		—		9.7
Gross profit (excluding depreciation, amortization and accretion)	57.1		1.4		8.4		—		—		66.9
Identifiable assets	42.6		163.0		30.0		—		—		235.6
Goodwill	352.2		1,249.7		850.4		—		—		2,452.3
Property, plant and equipment	1,297.7		402.2		2,152.4		—		2.4		3,854.7
Cash expenditures for property, plant and equipment	56.0		0.3		3.5		—		—		59.8

	Three Months Ended June 30, 2012
	Gathering and Processing Operations		NGL and Crude Services Operations		Storage and Transportation Operations		Intersegment Operations		Corporate Assets		Total
Gathering and processing revenues	$	55.2	$	—	$	—	$	—	$	—	$	55.2
Supply and logistics revenues	—		—		—		—		—		—
Storage and transportation revenues	—		—		—		—		—		—
Gross profit (excluding depreciation, amortization and accretion)	47.8		—		—		—		—		47.8
Identifiable assets	35.0		—		—		—		—		35.0
Goodwill	348.1		—		—		—		—		348.1
Property, plant and equipment	1,087.9		—		—		—		—		1,087.9
Cash expenditures for property, plant and equipment	9.5		—		—		—		—		9.5

	Six Months Ended June 30, 2013
	Gathering and Processing Operations		NGL and Crude Services Operations		Storage and Transportation Operations		Intersegment Operations		Corporate Assets		Total
Gathering and processing revenues	$	143.5	$	—	$	—	$	—	$	—	$	143.5
Supply and logistics revenues	—		38.1		—		—		—		38.1
Storage and transportation revenues	—		—		9.7		—		—		9.7
Gross profit (excluding depreciation, amortization and accretion)	116.0		1.4		8.4		—		—		125.8
Identifiable assets	42.6		163.0		30.0		—		—		235.6
Goodwill	352.2		1,249.7		850.4		—		—		2,452.3
Property, plant and equipment	1,297.7		402.2		2,152.4		—		2.4		3,854.7
Cash expenditures for property, plant and equipment	80.3		0.3		3.5		—		—		84.1

	Six Months Ended June 30, 2012
	Gathering and Processing Operations		NGL and Crude Services Operations		Storage and Transportation Operations		Intersegment Operations		Corporate Assets		Total
Gathering and processing revenues	$	109.0	$	—	$	—	$	—	$	—	$	109.0
Supply and logistics revenues	—		—		—		—		—		—
Storage and transportation revenues	—		—		—		—		—		—
Gross profit (excluding depreciation, amortization and accretion)	92.6		—		—		—		—		92.6
Identifiable assets	35.0		—		—		—		—		35.0
Goodwill	348.1		—		—		—		—		348.1
Property, plant and equipment	1,087.9		—		—		—		—		1,087.9
Cash expenditures for property, plant and equipment	22.4		—		—		—		—		22.4

XML

Condensed Consolidating Financial Information (Condensed Consolidating Statements of Comprehensive Income) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Condensed Financial Statements, Captions [Line Items]
Net income (loss)	$ (4.5)	$ 8.3	$ (0.6)	$ 12.8
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	(4.7)	8.3	(0.8)	12.8
Parent Company
Condensed Financial Statements, Captions [Line Items]
Net income (loss)	(4.5)		(0.6)
Change in unrealized fair value on cash flow hedges (Note 2)	(0.2)		(0.2)
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	(4.7)		(0.8)
Guarantor Subsidiaries
Condensed Financial Statements, Captions [Line Items]
Net income (loss)	(2.5)		(2.5)
Change in unrealized fair value on cash flow hedges (Note 2)	0		0
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	(2.5)		(2.5)
Non-Guarantor Subsidiaries
Condensed Financial Statements, Captions [Line Items]
Net income (loss)	(2.5)		1.4
Change in unrealized fair value on cash flow hedges (Note 2)	0		0
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	(2.5)		1.4
Consolidation, Eliminations
Condensed Financial Statements, Captions [Line Items]
Net income (loss)	5.0		1.1
Change in unrealized fair value on cash flow hedges (Note 2)	0		0
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	5.0		1.1
Consolidated Entities
Condensed Financial Statements, Captions [Line Items]
Net income (loss)	(4.5)		(0.6)
Change in unrealized fair value on cash flow hedges (Note 2)	(0.2)		(0.2)
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	$ (4.7)		$ (0.8)

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Consolidated Statements of Operations (USD $) In Millions, except Share data in Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Revenues:
Gathering and processing	$ 71.1	$ 55.2	$ 143.5	$ 109.0
NGL and crude services	38.1	0	38.1	0
Storage and transportation	9.7	0	9.7	0
Total revenue	118.9	55.2	191.3	109.0
Cost of product/services sold (excluding depreciation, amortization and accretion as shown below):
Gathering and processing	14.0	7.4	27.5	16.4
NGL and crude services	36.7	0	36.7	0
Storage and transportation	1.3	0	1.3	0
Total cost of product sold	52.0	7.4	65.5	16.4
Expenses:
Operating and administrative	31.1	18.0	51.9	34.5
Depreciation, amortization and accretion	28.0	19.1	50.4	35.0
Total Expenses	59.1	37.1	102.3	69.5
Gain on contingent consideration	0	6.8	0	6.8
Operating income	7.8	17.5	23.5	29.9
Other income (expense):
Interest and debt expense, net	12.0	8.9	23.4	16.5
Income (loss) before income taxes	(4.2)	8.6	0.1	13.4
Provision for income taxes	0.3	0.3	0.7	0.6
Net income (loss)	(4.5)	8.3	(0.6)	12.8
Net (income) loss attributable to non-controlling partners	6.1	(4.9)	7.3	(6.1)
Net income attributable to Inergy, L.P.	1.6	3.4	6.7	6.7
Subordinated unitholders' interest in net income	0.1	0.4	0.6	0.7
Common unitholders' interest in net income	$ 1.5	$ 3.0	$ 6.1	$ 6.0
Net income per limited partner unit:
Basic (dollars per unit)	0.03	0.09	0.14	0.17
Diluted (dollars per unit)	0.03	0.09	0.14	0.17
Weighted-average limited partners’ units outstanding (in thousands):
Basic (units)	52,459	35,103	43,829	35,103
Dilutive (units)	4,388	4,388	4,388	4,388
Diluted (units)	56,847	39,491	48,217	39,491

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Certain Balance Sheet Information

6 Months Ended

Jun. 30, 2013

Balance Sheet Related Disclosures [Abstract]

Certain Balance Sheet Information

Certain Balance Sheet Information

Inventory consisted of the following at June 30, 2013 and December 31, 2012, respectively (in millions):

	June 30, 2013		December 31, 2012
NGLs	$	46.8	$	—
Parts, supplies and other	6.4		—
Total inventory	$	53.2	$	—

Property, plant and equipment consisted of the following at June 30, 2013 and December 31, 2012, respectively (in millions):

	June 30, 2013		December 31, 2012
Gathering systems	$	622.6	$	582.3
Processing plants and compression facilities	507.3		485.4
Plant equipment	659.5		—
Buildings, rights-of-way, easements and storage rights	102.8		66.4
Land	779.6		4.1
Pipelines	650.4		—
Vehicles	32.1		0.3
Construction in process	280.6		56.0
Base gas	109.1		—
Salt deposits	102.0		—
Office furniture and equipment	8.7		2.9
	3,854.7		1,197.4
Less: accumulated depreciation	126.5		95.0
Total property, plant and equipment, net	$	3,728.2	$	1,102.4

Inergy had capital lease assets of $11.6 million and $11.8 million included in property, plant and equipment at June 30, 2013 and December 31, 2012, respectively.

Intangible assets consisted of the following at June 30, 2013 and December 31, 2012, respectively (in millions):

	June 30, 2013		December 31, 2012
Customer accounts	$	239.0	$	—
Gas gathering, compression and processing contracts	813.1		813.0
Trademarks	34.0		—
Deferred financing and other costs	33.1		32.2
	1,119.2		845.2
Less: accumulated amortization	70.6		49.9
Total intangible assets, net	$	1,048.6	$	795.3

Assets Held for Sale

In June 2013, CMLP entered into an agreement to sell a cryogenic plant and associated equipment for approximately $11 million, net of fees. At June 30, 2013, the Company has classified these assets as held for sale at their historical book value of $6.7 million. The Company completed this sale on July 25, 2013.

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Business Acquisitions (Tables)

6 Months Ended

Jun. 30, 2013

Business Combinations [Abstract]

Schedule of Recognized Identified Assets Acquired and Liabilities Assumed

The following table summarizes the estimated fair values of the assets acquired and liabilities assumed at the acquisition date (in millions):

	June 19, 2013
Current assets	$	222.7
Property, plant and equipment	2,554.9
Intangible assets	273.0
Other assets	51.2
Total identifiable assets acquired	3,101.8
Current liabilities	205.5
Long-term debt	1,079.3
Other long-term liabilities	43.9
Total liabilities assumed	1,328.7
Net identifiable assets acquired	1,773.1
Goodwill	2,100.1
Net assets acquired	$	3,873.2

Business Acquisition, Pro Forma Information

The following table represents the pro forma consolidated statements of operations as if the Inergy reverse acquisition had been included in the consolidated results of the Company for the full three-month periods ended June 30, 2013 and 2012 and for the full six-month periods ended June 30, 2013 and 2012 (in millions, except per unit information):

	Pro Forma Consolidated Statement of Operations  (Unaudited)
	Three Months Ended  June 30,					Six Months Ended  June 30,
	2013			2012 (a)		2013			2012 (a)
Revenues	$	389.9		$	297.4	$	912.7		$	692.3
Net income (loss)	$	(37.1	)	$	18.9	$	(27.6	)	$	32.6
Net income (loss) per limited partner unit:
Basic	$	(0.51	)	$	0.25	$	(0.49	)	$	0.48
Diluted	$	(0.51	)	$	0.25	$	(0.49	)	$	0.48

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Related Party Transactions (Notes)

6 Months Ended

Jun. 30, 2013

Related Party Transactions [Abstract]

Related Party Transactions Disclosure

Related Party Transactions

Inergy enters into transactions with its affiliates within the ordinary course of business. For a further discussion of Inergy's affiliated transactions, see the Form 8-K as filed with the Securities and Exchange Commission on August 5, 2013. The following table shows revenues, cost of goods sold, operating and administrative expense and reimbursements from Inergy's affiliates for the three-month and six-month periods endedJune 30, 2013 and 2012, respectively (in millions):

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2013		2012		2013		2012
Gathering and processing revenues	$	24.6	$	28.2	$	50.2	$	58.8
Gathering and processing cost of goods sold	$	7.9	$	—	$	14.6	$	—
Operating and administrative expense	$	5.5	$	4.8	$	11.1	$	9.5
Reimbursements	$	0.3	$	0.3	$	0.5	$	0.5

The following table shows accounts receivable and accounts payable from Inergy's affiliates as of June 30, 2013 and December 31, 2012, respectively (in millions):

	June 30,  2013		December 31, 2012
Accounts receivable	$	20.9	$	23.8
Accounts payable	$	7.2	$	3.1

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Commitments and Contingencies (Detail) (USD $) In Millions, unless otherwise specified			6 Months Ended			0 Months Ended	1 Months Ended
	Jun. 30, 2013	Dec. 31, 2012	Jun. 30, 2013 Watkins Glen Ngl Development Project bbl	Jun. 30, 2013 Identified Growth Projects	Jun. 30, 2013 Other Growth and Maintenance Contractual Purchase Obligations	Sep. 23, 2011 Marc I Pipeline Anadarko	Jun. 30, 2010 Marc I Pipeline Anadarko	Jun. 30, 2013 Commodity
Purchase Commitment, Excluding Long-term Commitment [Line Items]
Firm purchase commitments				$ 24.0	$ 14.6			$ 179.0
Estimated Percentage Of Purchase Commitments Occur Within One Year								97.90%
Capital Lease Obligations	4.9	7.0
Counterparty Option To Purchase Maximum Ownership Interest						25.00%	25.00%
Accrued Liabilities, Environmental Compliance	0.3	0.2
Loss Contingency, Range of Possible Loss, Minimum	0.3
Loss Contingency, Range of Possible Loss, Maximum	0.4
Storage capacity barrels			2,100,000
Self-insurance reserves	19.9
Self-insurance reserve expected to be paid in next fiscal year	$ 17.2	$ 0

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Certain Balance Sheet Information (Intangible Assets) (Detail) (USD $) In Millions, unless otherwise specified											1 Months Ended
	Jun. 30, 2013	Dec. 31, 2012	Jun. 30, 2013 Customer accounts	Dec. 31, 2012 Customer accounts	Jun. 30, 2013 Gas gathering, compression and processing contracts	Dec. 31, 2012 Gas gathering, compression and processing contracts	Jun. 30, 2013 Trademarks	Dec. 31, 2012 Trademarks	Jun. 30, 2013 Deferred financing and other costs	Dec. 31, 2012 Deferred financing and other costs	Jun. 30, 2013 CMLP
Finite-Lived Intangible Assets [Line Items]
Intangible assets, Gross	$ 1,119.2	$ 845.2	$ 239.0	$ 0	$ 813.1	$ 813.0	$ 34.0	$ 0	$ 33.1	$ 32.2
Less: accumulated amortization	70.6	49.9
Total intangible assets, net	1,048.6	795.3
Assets Held-for-sale, at Carrying Value [Abstract]
Agreement to sell cryogenic plant and associated equipment, amount											11
Assets held for sale		$ 0									$ 6.7

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Long-Term Debt (Tables)

6 Months Ended

Jun. 30, 2013

Text Block [Abstract]

Components Of Long-Term Debt

Long-term debt consisted of the following at June 30, 2013 and December 31, 2012, respectively (in millions):

	June 30, 2013		December 31, 2012
NRGY credit agreement	$	340.3	$	—
NRGY senior unsecured notes	11.5		—
NRGY obligations under noncompetition agreements and notes to former owners of businesses acquired	2.9		—
CMLP credit facility	300.2		206.7
CMLP senior notes	350.0		350.0
CMLP premium on senior notes	1.3		1.5
CMM credit facility	127.4		127.0
NRGM credit facility	237.0		—
NRGM senior unsecured notes	500.0		—
Fair value adjustment of NRGM senior unsecured notes	5.0		—
Total debt	1,875.6		685.2
Less: current portion	2.5		—
Total long-term debt	$	1,873.1	$	685.2

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Risk Management (Tables)

6 Months Ended

Jun. 30, 2013

Risk Management - Notional Amounts and Terms of Companys Derivative Financial Instruments [Abstract]

Notional Amounts And Terms Of Company's Derivative Financial Instruments

The notional amounts and terms of the Company’s derivative financial instruments include the following at June 30, 2013 and December 31, 2012, respectively (in millions):

	June 30, 2013		December 31, 2012
	Fixed Price Payor	Fixed Price Receiver	Fixed Price Payor	Fixed Price Receiver
Propane, crude and heating oil (barrels)	4.8	5.8	—	—

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Long-Term Debt (Narrative) (Detail) (USD $)	6 Months Ended					6 Months Ended							6 Months Ended							6 Months Ended					6 Months Ended			1 Months Ended											6 Months Ended					6 Months Ended				6 Months Ended				1 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	May 22, 2013	Dec. 31, 2012	Dec. 07, 2012	Jun. 30, 2013 Inergy Midstream	Jun. 30, 2012 Inergy Midstream	Jun. 30, 2013 CMM Credit Facility [Member]	Jun. 30, 2013 Credit Agreement	Jun. 30, 2013 CMLP Credit Facility	Jun. 30, 2013 CMLP	Dec. 31, 2012 CMLP	Jun. 30, 2013 Senior Notes CMLP Senior Notes	Nov. 08, 2012 Senior Notes CMLP Senior Notes	Apr. 02, 2011 Senior Notes CMLP Senior Notes	Jun. 30, 2013 Revolving Loan Facility	Dec. 31, 2012 Revolving Loan Facility	Jun. 30, 2013 Nrgm Credit Facility	Dec. 31, 2012 Nrgm Credit Facility	Jun. 30, 2013 Minimum CMM Credit Facility [Member]	Jun. 30, 2013 Minimum Credit Agreement	Jun. 30, 2013 Minimum CMLP Credit Facility	Jun. 30, 2013 Minimum Senior Notes CMLP Senior Notes	Jun. 30, 2013 Maximum LIBO Rate	Jun. 30, 2013 Maximum CMM Credit Facility [Member]	Jun. 30, 2013 Maximum Credit Agreement	Jun. 30, 2013 Maximum CMLP Credit Facility	Mar. 31, 2013 CMM Credit Facility [Member] Revolving Loan Facility	Jun. 30, 2013 CMM Credit Facility [Member] Revolving Loan Facility	Dec. 31, 2012 CMM Credit Facility [Member] Revolving Loan Facility	Apr. 13, 2012 Revolving Loan Facility Amended and Restated	Jun. 30, 2013 Revolving Loan Facility Credit Agreement LIBO Rate, Adjustment	Jun. 30, 2013 Revolving Loan Facility Minimum LIBO Rate	Jun. 30, 2013 Revolving Loan Facility Minimum Credit Agreement LIBO Rate	Jun. 30, 2013 Revolving Loan Facility Minimum Credit Agreement Adjusted LIBO Rate	Jun. 30, 2013 Revolving Loan Facility Maximum LIBO Rate	Jun. 30, 2013 Revolving Loan Facility Maximum Credit Agreement LIBO Rate	Jun. 30, 2013 Revolving Loan Facility Maximum Credit Agreement Adjusted LIBO Rate	Jun. 30, 2013 Term Loan Facility Interest Rate Swaps Accounted For As Cash Flow Hedges Interest Rate Swaps Maturing 2015 derivative	Jun. 30, 2013 Nrgm Credit Facility	Mar. 31, 2013 Nrgm Credit Facility	Dec. 21, 2011 Nrgm Credit Facility Inergy Midstream	Jun. 30, 2013 Nrgm Credit Facility Adjusted LIBO Rate	Jun. 30, 2013 Nrgm Credit Facility Amended and Restated	Jun. 30, 2013 Nrgm Credit Facility Minimum	Mar. 31, 2013 Nrgm Credit Facility Minimum	Jun. 30, 2013 Nrgm Credit Facility Minimum Adjusted LIBO Rate	Jun. 30, 2013 Nrgm Credit Facility Maximum	Jun. 30, 2013 Nrgm Credit Facility Maximum Adjusted LIBO Rate	Jun. 30, 2013 CMLP Credit Facility	Dec. 31, 2012 CMLP Credit Facility	Nov. 30, 2012 CMLP Credit Facility Revolving Loan Facility Amended and Restated	Jun. 30, 2013 CMLP Credit Facility Maximum LIBO Rate	Dec. 31, 2012 CMLP Credit Facility Maximum LIBO Rate
Debt Instrument [Line Items]
Credit agreement outstanding carrying value																													$ 200,000,000		$ 550,000,000											$ 600,000,000										$ 550,000,000
Line of Credit Facility, Expiration Period																												5 years																								5 years
Debt Instrument, Interest Rate, Basis for Effective Rate																																								0.005				0.005
Variable interest rate																																1.00%		0.75%	1.75%		2.00%	3.00%					1.00%				1.75%		2.75%
Credit agreement outstanding carrying value											300,200,000	206,700,000				340,300,000	0	237,000,000	0										127,400,000	127,000,000
Line of Credit Facility, Interest Rate at Period End																								2.50%									1.95%			4.00%																	2.80%	2.50%
Debt, Weighted Average Interest Rate																														2.80%																				3.00%	2.80%
Credit Agreement amount available									166,500,000																				72,600,000																					110,600,000
Letters of credit outstanding									43,200,000																															2,000,000
Total funded debt to consolidated EBITDA (as defined in the Credit Agreement)								11.4	4.0	4.1										4.5	1.0	5.0			5.0	4.75	5.5
Consolidated EBITDA to consolidated interest expense (as defined in the Credit Agreement)								2.9	10	4.3										2.0	2.50	2.5
Repayments of Long-term Debt	21,500,000	0				15,500,000	0																			300,000,000
Number of interest rate swaps entered during period																																							6
Fixed rate, range low end	0.84%
Fixed rate, range high end	2.52%
Aggregate notional amount, cash flow hedges	225,000,000
Increase available borrowings																																								150,000,000
Senior Secured Leverage Ratio Maximum																																									1.3					3.75
Line of Credit Facility, Covenant Terms, Cumulative Issuance of Junior Debt																																									200,000,000
Credit facility sub-limit																												10,000,000												10,000,000	10,000,000
Sub-limit advances																												25,000,000												100,000,000	100,000,000
Remaining capacity																																								361,000,000
Senior Notes	11,500,000			0							350,000,000	350,000,000		150,000,000	200,000,000			500,000,000	0
Fixed Charge Coverage Ratio													3.9										1.75
Debt Instrument, Interest Rate, Stated Percentage	7.00%				6.00%										7.75%
Adjusted LIBO Rate, minimum																																								0.75%
Adjusted LIBO Rate, maximum																																								1.75%
Line of credit facility commitment fee percentage, minimum																																								0.30%
Line of credit facility commitment fee percentage, maximum																																								0.50%
Consolidated leverage ratio, maximum																																								4.10					5.00			5.50
Interest coverage ratio, maximum																																								6.80					2.50
Debt Instrument, Interest Rate, Effective Percentage Rate Range, Minimum																																								0.75%
Debt Instrument, Interest Rate, Effective Percentage Rate Range, Maximum																																								1.75%
Long-term Debt, Fair Value																		5,000,000	0
Debt Instruments, Covenant Compliance, Consent Soliciations, Consents Not Revoked, Value			$ 464,500,000
Debt Instruments, Covenant Compliance, Consent Soliciations, Consents Not Revoked, Percent			92.90%

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Summary of Significant Accounting Policies (Estimated Economic Lives Of Intangible Assets) (Detail)	6 Months Ended
	Jun. 30, 2013
Minimum | Customer accounts
Finite-Lived Intangible Assets [Line Items]
Intangible assets, weighted average useful life	8 years
Minimum | Trademarks
Finite-Lived Intangible Assets [Line Items]
Intangible assets, weighted average useful life	5 years
Minimum | Gathering and Processing Operations
Finite-Lived Intangible Assets [Line Items]
Intangible assets, weighted average useful life	5 years
Maximum | Customer accounts
Finite-Lived Intangible Assets [Line Items]
Intangible assets, weighted average useful life	12 years
Maximum | Trademarks
Finite-Lived Intangible Assets [Line Items]
Intangible assets, weighted average useful life	10 years
Maximum | Gathering and Processing Operations
Finite-Lived Intangible Assets [Line Items]
Intangible assets, weighted average useful life	20 years

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Business Acquisitions (Assets Acquired, Liabilities Assumed) (Details) (USD $) In Millions, unless otherwise specified	Jun. 30, 2013	Dec. 31, 2012	Dec. 07, 2012	Jun. 30, 2012
Business Combinations [Abstract]
Current assets			$ 222.7
Property, plant and equipment			2,554.9
Intangible assets			273.0
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets, Other			51.2
Total identifiable assets acquired			3,101.8
Current liabilities			205.5
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Long-term Debt			1,079.3
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Other			43.9
Total liabilities assumed			1,328.7
Net identifiable assets acquired			1,773.1
Goodwill	2,452.3	352.2	2,100.1	348.1
Net assets acquired			$ 3,873.2

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Segments (Summary Of Segment Information) (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013 segment	Jun. 30, 2012	Dec. 31, 2012	Dec. 07, 2012
Number of Operating Segments			3
Total revenue	$ 118.9	$ 55.2	$ 191.3	$ 109.0
Gross profit (excluding depreciation, amortization and accretion)	66.9	47.8	125.8	92.6
Identifiable assets	235.6	35.0	235.6	35.0
Goodwill	2,452.3	348.1	2,452.3	348.1	352.2	2,100.1
Property, plant and equipment	3,854.7	1,087.9	3,854.7	1,087.9	1,197.4
Cash expenditures for property, plant and equipment	59.8	9.5	84.1	22.4
Gathering and processing revenues
Total revenue	71.1	55.2	143.5	109.0
Supply and logistics revenues
Total revenue	38.1	0	38.1	0
Storage and transportation revenues
Total revenue	9.7	0	9.7	0
Gathering and Processing Operations
Gross profit (excluding depreciation, amortization and accretion)	57.1	47.8	116.0	92.6
Identifiable assets	42.6	35.0	42.6	35.0
Goodwill	352.2	348.1	352.2	348.1
Property, plant and equipment	1,297.7	1,087.9	1,297.7	1,087.9
Cash expenditures for property, plant and equipment	56.0	9.5	80.3	22.4
Gathering and Processing Operations | Gathering and processing revenues
Total revenue	71.1	55.2	143.5	109.0
Gathering and Processing Operations | Supply and logistics revenues
Total revenue	0	0	0	0
Gathering and Processing Operations | Storage and transportation revenues
Total revenue	0	0	0	0
NGL and Crude Services Operations
Gross profit (excluding depreciation, amortization and accretion)	1.4	0	1.4	0
Identifiable assets	163.0	0	163.0	0
Goodwill	1,249.7	0	1,249.7	0
Property, plant and equipment	402.2	0	402.2	0
Cash expenditures for property, plant and equipment	0.3	0	0.3	0
NGL and Crude Services Operations | Gathering and processing revenues
Total revenue	0	0	0	0
NGL and Crude Services Operations | Supply and logistics revenues
Total revenue	38.1	0	38.1	0
NGL and Crude Services Operations | Storage and transportation revenues
Total revenue	0	0	0	0
Storage and Transportation Operations
Gross profit (excluding depreciation, amortization and accretion)	8.4	0	8.4	0
Identifiable assets	30.0	0	30.0	0
Goodwill	850.4	0	850.4	0
Property, plant and equipment	2,152.4	0	2,152.4	0
Cash expenditures for property, plant and equipment	3.5	0	3.5	0
Storage and Transportation Operations | Gathering and processing revenues
Total revenue	0	0	0	0
Storage and Transportation Operations | Supply and logistics revenues
Total revenue	0	0	0	0
Storage and Transportation Operations | Storage and transportation revenues
Total revenue	9.7	0	9.7	0
Intersegment Operations
Gross profit (excluding depreciation, amortization and accretion)	0	0	0	0
Identifiable assets	0	0	0	0
Goodwill	0	0	0	0
Property, plant and equipment	0	0	0	0
Cash expenditures for property, plant and equipment	0	0	0	0
Intersegment Operations | Gathering and processing revenues
Total revenue	0	0	0	0
Intersegment Operations | Supply and logistics revenues
Total revenue	0	0	0	0
Intersegment Operations | Storage and transportation revenues
Total revenue	0	0	0	0
Corporate Assets
Gross profit (excluding depreciation, amortization and accretion)	0	0	0	0
Identifiable assets	0	0	0	0
Goodwill	0	0	0	0
Property, plant and equipment	2.4	0	2.4	0
Cash expenditures for property, plant and equipment	0	0	0	0
Corporate Assets | Gathering and processing revenues
Total revenue	0	0	0	0
Corporate Assets | Supply and logistics revenues
Total revenue	0	0	0	0
Corporate Assets | Storage and transportation revenues
Total revenue	$ 0	$ 0	$ 0	$ 0

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Partnership Organization and Basis of Presentation (Narrative) (Detail) (USD $) In Millions, except Share data, unless otherwise specified	3 Months Ended		6 Months Ended		0 Months Ended					6 Months Ended		6 Months Ended				0 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013 segment	Jun. 30, 2012	Jun. 05, 2013 Common Units	Jun. 05, 2013 Class D Units	May 05, 2013 CMLP	May 05, 2013 Crestwood Holdings Majority Shareholder	May 05, 2013 Inergy Midstream	Jun. 30, 2013 Inergy Midstream	May 05, 2013 CMLP	Jun. 30, 2013 CMLP First Distribution	Jun. 30, 2013 CMLP Second Distribution	Jun. 30, 2013 CMLP Third Distribution	Jun. 30, 2013 CMLP All distributions above the third target	Jun. 18, 2013 Subsequent Event Inergy Midstream Unit Distribution
Partnership Organization And Basis Of Presentation [Line Items]
Incentive Distribution, Distribution Per Unit										$ 0.37		$ 0.345	$ 0.375	$ 0.45
Incentive Distribution Rights, Percent										50.00%		1.80%	15.00%	25.00%	50.00%
Distribution Made to Limited Partner, Unit Distribution					137,105	21,588										56,400,000
Number of Operating Segments			3
Gathering and processing	$ 71.1	$ 55.2	$ 143.5	$ 109.0
Gathering and processing	14.0	7.4	27.5	16.4
Business Combination, Equity Interest Issued or Issuable, Conversion Ratio											107.00%
Payments to Acquire Businesses, Gross							$ 35	$ 10	$ 25

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Risk Management (Notional Amounts and Terms of Company's Derivative Financial Instruments) (Details)	Jun. 30, 2013 bbl	Dec. 31, 2012 bbl
Fixed Price Payor
Derivative [Line Items]
Propane, crude and heating oil (barrels)	4,800,000	0
Fixed Price Receiver
Derivative [Line Items]
Propane, crude and heating oil (barrels)	5,800,000	0

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Fair Value Measurements (Tables)

6 Months Ended

Jun. 30, 2013

Fair Value, Assets and Liabilities Measured on Recurring Basis [Abstract]

Assets And Liabilities Measured At Fair Value On Recurring Basis

	June 30, 2013
	Fair Value of Derivatives
	Level 1		Level 2		Level 3		Total		Designated as Hedges		Not Designated as Hedges		Netting Agreements(a)			Total
Assets
Assets from price risk management	$	0.1	$	21.1	$	—	$	21.2	$	—	$	21.2	$	(5.9	)	$	15.3
SPH units	6.6		—		—		6.6		—		—		—			6.6
Total assets at fair value	$	6.7	$	21.1	$	—	$	27.8	$	—	$	21.2	$	(5.9	)	$	21.9
Liabilities
Liabilities from price risk management	$	0.2	$	11.1	$	—	$	11.3	$	—	$	11.3	$	(3.3	)	$	8.0
Interest rate swaps	—		5.1		—		5.1		—		—		—			5.1
Total liabilities at fair value	$	0.2	$	16.2	$	—	$	16.4	$	—	$	11.3	$	(3.3	)	$	13.1

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Consolidated Statement of Partners' Capital (USD $) In Millions, unless otherwise specified	Total	Common Unit Capital	Non-Controlling Partners	Inergy Midstream	Inergy Midstream Common Unit Capital	Inergy Midstream Non-Controlling Partners	Crestwood Marcellus Midstream LLC	Crestwood Marcellus Midstream LLC Common Unit Capital	Crestwood Marcellus Midstream LLC Non-Controlling Partners	Class D Units	Class D Units Common Unit Capital	Class D Units Non-Controlling Partners	Class C Units	Class C Units Common Unit Capital	Class C Units Non-Controlling Partners
Balance at December 31, 2012 at Dec. 31, 2012	$ 1,550.7	$ 31.7	$ 1,519.0
Increase (Decrease) in Partners' Capital [Roll Forward]
Net proceeds from issuance of common units by Crestwood Midstream Partners LP				118.5	0	118.5				0	(126.3)	126.3	0	0.6	(0.6)
Change in interest in Crestwood Marcellus Midstream LLC							0	238.9	(238.9)
Invested capital from Inergy, L.P. net of debt (Note 4)	0						3,873.2	1,388.8	2,484.4
Unit-based compensation charges	2.0	0.2	1.8
Taxes paid for unit-based compensation vesting	(0.7)	0	(0.7)
Distributions	(57.7)	(9.3)	(48.4)				(129.0)	(129.0)	0				0	(0.1)	0.1
Change in Suburban Propane Partners, L.P. units	(0.2)	(0.2)	0
Other	(0.2)	(0.2)	0
Net income (loss)	(0.6)	6.7	(7.3)
Balance at June 30, 2013 at Jun. 30, 2013	$ 5,356.0	$ 1,401.8	$ 3,954.2

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Partnership Organization and Basis of Presentation

6 Months Ended

Jun. 30, 2013

Disclosure Partnership Organization And Basis Of Presentation Narrative [Abstract]

Partnership Organization and Basis of Presentation

Partnership Organization and Basis of Presentation

Organization

Inergy, L.P. (“Inergy”, "NRGY" or the “Company”), a Delaware limited partnership formed in March 2001, is an energy midstream company. Its common units are listed on the New York Stock Exchange (“NYSE”) under the symbol “NRGY.” Inergy is managed by its general partner, Inergy GP, LLC, which is indirectly owned by Crestwood Holdings LLC (“Crestwood Holdings”). The substantial majority of Crestwood Holdings is indirectly owned by First Reserve Management, LP, an energy-focused private equity fund (“FRC”).

Inergy conducts a significant part of its consolidated operations through two publicly-traded master limited partnerships, Inergy Midstream, L.P. (“Inergy Midstream” or “NRGM”) and Crestwood Midstream Partners LP (“Crestwood Midstream” or “CMLP”). These master limited partnerships are managed by their general partners, and Inergy owns the general partners of Inergy Midstream and Crestwood Midstream. Inergy therefore manages and controls Inergy Midstream, whose common units are listed on the NYSE under the symbol “NRGM,” and Crestwood Midstream, whose common units are listed on the NYSE under the symbol “CMLP.”

In addition to managing and controlling both NRGM and CMLP, Inergy also owns the incentive distribution rights (“IDRs”) of Inergy Midstream and Crestwood Midstream. The IDRs of Inergy Midstream entitle Inergy to receive 50% of all distributions paid by Inergy Midstream in excess of its initial quarterly distribution of $0.37 per common unit. The GP interest of CMLP entitles Inergy to receive 1.8% of all distributions paid by Crestwood Midstream. The IDRs of CMLP entitle Inergy to receive 15% of all distributions above the first target distribution ($0.345 per common unit), 25% of all distributions above the second target distribution ($0.375 per common unit) and thereafter 50% of all distributions above the third target distribution level of $0.45 per common unit.

The following diagram comprises a simplified depiction of our ownership structure as of June 30, 2013:

Unless otherwise indicated, references in this report to “we,” “us,” “our,” “ours,” “our company,” “Inergy,” “the Company” and similar terms refer to either Inergy, L.P. itself or Inergy, L.P. and its consolidated subsidiaries, as the context requires. Unless otherwise indicated, references to (i) Inergy Midstream refer to either Inergy Midstream, L.P. itself or Inergy Midstream, L.P. and its consolidated subsidiaries, and (ii) Crestwood Midstream refer to either Crestwood Midstream Partners LP itself or Crestwood Midstream Partners LP and its consolidated subsidiaries, in each case, as the context requires.

Business Combination

On May 5, 2013, Inergy and certain of its affiliates entered into a series of definitive agreements with Crestwood Holdings and certain of its affiliates under which, among other things, (i) Inergy agreed to distribute to its common unitholders all of the NRGM common units owned by Inergy; (ii) Crestwood Holdings agreed to acquire the owner of Inergy's general partner; (iii) Crestwood Holdings agreed to contribute ownership of CMLP's general partner and IDRs to Inergy in exchange for common and subordinated units of Inergy; and (iv) Crestwood Midstream agreed to merge with and into a subsidiary of Inergy Midstream in a merger in which CMLP unitholders will receive 1.07 NRGM common units for each CMLP common unit they own. As part of the merger, which is expected to close in 2013, CMLP's unaffiliated unitholders will also receive a one-time $35 million cash payment at the closing of the merger, $25 million of which will be payable by NRGM and $10 million of which will be payable by Crestwood Holdings.

On June 5, 2013, Crestwood Midstream's general partner distributed to a wholly-owned subsidiary of Crestwood Holdings LLC approximately 137,105 common units and approximately 21,588 Class D units of CMLP, representing all of the CMLP common and Class D units held by Crestwood Midstream's general partner.

On June 18, 2013, Inergy distributed to its unitholders approximately 56.4 million NRGM common units, representing all of the NRGM common units held by Inergy.

On June 19, 2013, Crestwood Holdings acquired the owner of Inergy's general partner and contributed to Inergy ownership of Crestwood Gas Services GP, LLC ("CMLP GP"), which owns 100% of the general partnership interests and IDRs of Crestwood Midstream. Crestwood Holdings and its ultimate parent company, FRC, acquired control of Inergy as a result of these transactions.

Description of Business

Inergy provides gathering, processing, storage and transportation solutions to customers in the crude oil, natural gas liquids (“NGLs”) and natural gas sectors of the energy industry. Inergy's financial statements reflect three operating and reporting segments: (i) gathering and processing; (ii) NGL and crude services; and (iii) storage and transportation.

Inergy's gathering and processing (“G&P) operations provide natural gas gathering, processing, treating, compression and transportation services to producers in unconventional shale plays in West Virginia, Texas, Arkansas, New Mexico and Louisiana. The consolidated assets reflected in this segment include rich gas gathering systems and processing plants in the Marcellus Shale, Barnett Shale, Granite Wash, and Avalon Shale plays, and dry gas gathering systems in the Barnett Shale, Fayetteville Shale, and Haynesville Shale plays.

Inergy's NGL and crude services operations provide NGL marketing, supply and logistics services to producers, refiners, petrochemical companies, marketers, and others customers. The consolidated assets reflected in this segment primarily include a crude oil loading and storage terminal (the “COLT Hub”), the West Coast operations, and a fleet of over-the-road truck and rail transports.

Inergy's storage and transportation operations provide natural gas and NGL storage and transportation services to third parties, as well as the production and sale of salt products. The consolidated assets reflected in this segment primarily include natural gas storage facilities in New York and Texas (the Stagecoach, Thomas Corners, Steuben, Seneca Lake and Tres Palacios storage facilities), natural gas transmission facilities in New York and Pennsylvania (the North-South Facilities, the MARC I Pipeline, and the East Pipeline), an NGL storage facility in New York (the Bath storage facility), and a solution-mining and salt production company in New York (US Salt).

Inergy owns and operates the Tres Palacios storage facility, a fractionation facility on the West Coast and an NGL supply and logistics business.

Basis of Presentation

These financial statements were originally the financial statements of CMLP GP, prior to being acquired by Inergy on June 19, 2013 as discussed above. Inergy's acquisition of CMLP GP was accounted for as a reverse acquisition under the purchase method of accounting in accordance with FASB Accounting Standard Codification Subtopic 805 - Business Combinations. The accounting for a reverse acquisition results in the legal acquiree (CMLP GP) being the acquiror for accounting purposes. Although CMLP GP was the surviving entity for accounting purposes, Inergy was the surviving entity for legal purposes, consequently, the name on these financial statements was changed from Crestwood Gas Services GP, LLC to Inergy, L.P.

On June 18, 2013, Inergy changed its fiscal year from September 30 to December 31 to adopt the fiscal year of CMLP GP.

The financial information contained herein as of June 30, 2013, and for the three-month and six-month periods endedJune 30, 2013 and 2012, is unaudited. Inergy believes this information has been prepared in accordance with accounting principles generally accepted in the United States for interim financial information and Article 10 of Regulation S-X. Inergy also believes this information includes all adjustments (consisting only of normal recurring adjustments) necessary to present fairly the financial position, results of operations and cash flows for the periods then ended.

The accompanying consolidated financial statements should be read in conjunction with the Form 10-K as filed with the Securities and Exchange Commission for the fiscal year ended September 30, 2012 as well as the Form 8-K/A filed August 5, 2013, containing consolidated financial statements related to CMLP GP.

The accompanying consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries, including among others Inergy Partners, LLC (“Inergy Partners”), Tres Palacios Gas Storage LLC (“TPGS”), IPCH Acquisition Corp. (“IPCHA”), Inergy Finance Corp., Inergy Operations, LLC, NRGM GP, LLC and CMLP GP. The accompanying consolidated financial statements also include the accounts of Inergy Midstream and Crestwood Midstream and each of their consolidated subsidiaries.

All significant intercompany transactions and balances have been eliminated in consolidation.

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Business Acquisitions

6 Months Ended

Jun. 30, 2013

Business Combinations [Abstract]

Business Acquisitions

Business Acquisitions

As described in Note 1, the Company's acquisition of CMLP GP was accounted for as a reverse acquisition under the purchase method of accounting in accordance with FASB Accounting Standard Codification Subtopic 805 - Business Combinations. This accounting treatment requires the accounting acquiree (Inergy) to have its assets and liabilities stated at fair value as well as any other purchase accounting adjustments as of the date of the acquisition, June 19, 2013. The fair value of Inergy was calculated based on the consolidated enterprise value of Inergy as of June 19, 2013. This consolidated enterprise value was based on the stock prices of NRGY and NRGM, the value of the outstanding senior notes based on quoted market prices for same or similar issuances and the value of the outstanding floating rate debt. Our preliminary purchase allocation is subject to material change pending the completion of the valuation of assets acquired and liabilities assumed.

The following table summarizes the estimated fair values of the assets acquired and liabilities assumed at the acquisition date (in millions):

	June 19, 2013
Current assets	$	222.7
Property, plant and equipment	2,554.9
Intangible assets	273.0
Other assets	51.2
Total identifiable assets acquired	3,101.8
Current liabilities	205.5
Long-term debt	1,079.3
Other long-term liabilities	43.9
Total liabilities assumed	1,328.7
Net identifiable assets acquired	1,773.1
Goodwill	2,100.1
Net assets acquired	$	3,873.2

The $2,100.1 million of goodwill is reflected in Inergy's NGL and crude services segment and storage and transportation segment. Goodwill recognized in the transaction relates primarily to synergies and new expansion opportunities expected upon completion of the integration of Inergy and CMLP GP.  Based on the preliminary purchase price allocation, amortization expenses relative to the intangible assets acquired are expected to be $28.9 million for each of the years ended December 31, 2013 through December 31, 2017.

The following table represents the pro forma consolidated statements of operations as if the Inergy reverse acquisition had been included in the consolidated results of the Company for the full three-month periods ended June 30, 2013 and 2012 and for the full six-month periods ended June 30, 2013 and 2012 (in millions, except per unit information):

	Pro Forma Consolidated Statement of Operations  (Unaudited)
	Three Months Ended  June 30,					Six Months Ended  June 30,
	2013			2012 (a)		2013			2012 (a)
Revenues	$	389.9		$	297.4	$	912.7		$	692.3
Net income (loss)	$	(37.1	)	$	18.9	$	(27.6	)	$	32.6
Net income (loss) per limited partner unit:
Basic	$	(0.51	)	$	0.25	$	(0.49	)	$	0.48
Diluted	$	(0.51	)	$	0.25	$	(0.49	)	$	0.48

(a) The three and six month periods ended June 30, 2012 have also been adjusted to reflect the contribution of Inergy's retail operations on August 1, 2012 as if that contribution had been removed from the consolidated results of operations at the beginning of each period presented.

These amounts have been calculated after applying the Company's accounting policies and adjusting the results of the Inergy reverse acquisition to reflect the depreciation and amortization that would have been charged assuming the preliminary fair value adjustments to property, plant and equipment and intangible assets had been made at the beginning of the current period. The purchase price allocation for the Inergy reverse acquisition has been prepared on a preliminary basis pending final asset valuation and asset rationalization, and changes are expected when additional information becomes available. Accordingly, the purchase accounting adjustments made in connection with the development of the unaudited pro forma are preliminary and subject to change.

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Summary of Significant Accounting Policies

6 Months Ended

Jun. 30, 2013

Text Block [Abstract]

Summary of Significant Accounting Policies

Summary of Significant Accounting Policies

Financial Instruments and Price Risk Management

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

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

Inergy had no derivatives identified as fair value hedges for accounting purposes in the three-month and six-month periods endedJune 30, 2012 and 2013.

Inergy also enters into derivative financial instruments that may qualify as cash flow hedges, which hedge the exposure of variability in expected future cash flows predominantly attributable to variable interest payments. These derivatives are recorded on the balance sheet at fair value as other assets or other long-term 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. In certain situations under the rules, the ineffective portion of the gain or loss is recognized as cost of product sold/services sold or interest expense in the current period. Inergy did not have any derivatives identified as cash flow hedges in the three and six-month periods ended June 30, 2012 and 2013.

Accumulated other comprehensive loss was $0.2 million at June 30, 2013. Included in accumulated other comprehensive loss at June 30, 2013 was a loss of $0.2 million attributable to Suburban Propane Partners, LP ("SPH") units. The SPH units were acquired by Inergy in August 2012 in conjunction with the disposition of its retail propane business.

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

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

Revenue Recognition

Inergy's gathering and processing operations gather, process, treat, compress, transport and sell natural gas pursuant to fixed-fee and percent-of-proceeds contracts. For fixed-fee contracts, Inergy recognizes revenues based on the volume of natural gas gathered, processed and treated or compressed. For percent-of-proceeds contracts, Inergy recognizes revenues based on the value of products sold to third parties. Inergy recognizes revenues for these services and products when all of the following criteria are met:

• services have been rendered or products delivered;

• persuasive evidence of an exchange arrangement exists;

• the price for services is fixed or determinable; and

• collectability is reasonably assured.

Sales of NGLs and salt are recognized at the time product is shipped or delivered to the customer depending on the sales terms. NGL processing and fractionation fees are recognized upon delivery of the product. Revenues from the COLT Hub are recognized when the contractual services are provided, such as loading of customer rail cars. Revenues from storage and transportation contracts are recognized during the period in which the storage and transportation services are provided, such as providing storage and transportation services during the period a firm service contract is in place.

Use of Estimates

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

Inventory

Inventory for NGL and crude services operations, which mainly consist of NGLs, are stated at the lower of cost or market and are computed using the average cost method. Inventory for storage and transportation operations are stated at the lower of cost or market and are computed predominantly using the average cost method. Inergy had no inventory at December 31, 2012.

Shipping and Handling Costs

Shipping and handling costs are recorded as part of cost of product/services sold at the time product is shipped or delivered to the customer.

Property, Plant and Equipment

Property, plant and equipment is recorded at its original cost of construction or, upon acquisition, at fair value of the assets acquired. For assets Inergy constructs, it capitalizes direct costs, such as labor and materials, and indirect costs, such as overhead and interest. Inergy capitalizes major units of property replacements or improvements and expenses minor items. Depreciation is computed by the straight-line method over the estimated useful lives of the assets, as follows:

	Years
Gathering systems	20
Processing plants and compression facilities	20 – 25
Buildings, rights-of-way, easements and storage rights	20 – 70
Office furniture and equipment	5 – 10
Vehicles	5
Pipelines	20
Base gas	10

Salt deposits are depleted utilizing the unit of production method.

Identifiable Intangible Assets

The Company has recorded certain identifiable intangible assets, including customer accounts, trademarks, deferred financing costs and gas gathering, compression and processing contracts. Customer accounts and trademarks have arisen from acquisitions. Deferred financing costs represent financing costs incurred in obtaining financing and are being amortized over the term of the related debt using the effective interest method. The Company recognizes acquired intangible asset separately 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.

Customer accounts and trademarks are generally amortized on a straight-line basis over their estimated economic lives, typically 8 years - 12 years and 5 years - 10 years, respectively. The gas gathering, compression and processing contracts are generally amortized based on the projected cash flows associated with the contracts, typically 5 years - 20 years.

Goodwill

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

Inergy completed its annual impairment test for each of its reporting units and determined that no impairment existed as of December 31, 2012. No indicators of impairment were identified requiring an interim impairment test during the six-month period ended June 30, 2013.

Income Taxes

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

Inergy is responsible for its portion of the Texas Margin tax that is included in Crestwood Holdings' consolidated Texas franchise tax return. Inergy's current tax liability will be assessed based on 0.7% of the gross revenue apportioned to Texas. The margin tax qualifies as an income tax under GAAP, which requires Inergy to recognize the impact of this tax on the temporary differences between the financial statement assets and liabilities and their tax basis attributable to such tax.

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

Sales Tax

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

Income Per Unit

Inergy calculates basic net income per limited partner unit by utilizing the two class method. Diluted net income per limited partner unit is computed by dividing net income attributable to the limited partners by the weighted-average number of units outstanding and the effect of dilutive units granted in the Inergy acquisition of CMLP GP. Net income attributable to the limited partners is determined by first allocating to Inergy, L.P. the earnings from the general partner and IDR interests from NRGM and CMLP with the remaining earnings allocated according to the capital accounts. The weighted average number of units outstanding is calculated based on the presumption that the common and subordinated units issued to acquire CMLP GP (the accounting predecessor) were outstanding for the entire period prior to the June 19, 2013 acquisition. On the date of the acquisition, all of NRGY's limited partner units are considered outstanding.

Accrued Additions to Property, Plant and Equipment

The Company has accrued for property, plant and equipment, including certain construction work in process relating to construction efforts on various growth projects. At June 30, 2013 and December 31, 2012, the Company had accrued $45.1 million and $9.2 million relating to property, plant and equipment classified as accrued expenses on the consolidated balance sheets.

Asset Retirement Obligations

An asset retirement obligation ("ARO") is an estimated liability for the cost to retire a tangible asset. Inergy records a liability for legal or contractual obligations to retire its long-lived assets associated with right-of-way contracts it holds and its facilities whether owned or leased. Inergy records a liability in the period the obligation is incurred and estimable. An ARO is initially recorded at its estimated fair value with a corresponding increase to property, plant and equipment. This increase in property, plant and equipment is then depreciated over the useful life of the asset to which that liability relates. An ongoing expense is recognized for changes in the value of the liability as a result of the passage of time, which Inergy records as depreciation, amortization and accretion expense on its consolidated statements of operations. The fair value of certain AROs could not be determined as settlement dates (or range of dates) associated with these assets were not estimable. The net AROs were $14.4 million and $14.0 million at June 30, 2013 and December 31, 2012, respectively, and are included in other long-term liabilities on the consolidated balance sheets.

Environmental Costs and Other Contingencies

Inergy recognizes liabilities for environmental and other contingencies when it has an exposure that indicates it is both probable that a liability has been incurred and the amount of loss can be reasonably estimated. Where the most likely outcome of a contingency can be reasonably estimated, Inergy accrues a liability for that amount. Where the most likely outcome cannot be estimated, a range of potential losses is established and if no one amount in that range is more likely than any other, the low end of the range is accrued.

Inergy records liabilities for environmental contingencies at their undiscounted amounts on its consolidated balance sheets as accrued expenses and other liabilities when environmental assessments indicate that remediation efforts are probable and costs can be reasonably estimated. Estimates of Inergy's liabilities are based on currently available facts and presently enacted laws and regulations, taking into consideration the likely effects of other societal and economic factors. These estimates are subject to revision in future periods based on actual costs or new circumstances. Inergy capitalizes costs that benefit future periods and recognize a current period charge in operation and maintenance expense when clean-up efforts do not benefit future periods.

Inergy evaluates potential recoveries of amounts from third parties, including insurance coverage, separately from its liability. Recovery is evaluated based on the solvency of the third party, among other factors. When recovery is assured, Inergy records and reports an asset separately from the associated liability on its consolidated balance sheet.

Accounting for Unit-Based Compensation

Unit-based compensation awards are valued at the closing market price of our common units on the date of grant, which reflects the fair value of such awards. For those awards that are settled in cash, the associated liability is remeasured at every balance sheet date through settlement, such that the vested portion of the liability is adjusted to reflect its revised fair value through compensation expense. Inergy generally recognizes the expense associated with the award over the vesting period. At the time of issuance of phantom units, management of the General Partner determines whether they will be settled in cash or settled in common units. Unit-based compensation awards at Inergy Midstream and Crestwood Midstream are fully reflected in these financial statements and are accounted for in the manner described above.

The amount of compensation expense recorded by the Company was $1.4 million and $0.5 million during the three months endedJune 30, 2013 and 2012, respectively, and $2.0 million and $1.0 million during the six months endedJune 30, 2013 and 2012, respectively.

Segment Information

There are certain accounting requirements that establish standards for reporting information about operating segments, as well as related disclosures about products and services, geographic areas and major customers. Further, they define operating segments as components of an enterprise for which separate financial information is available that is evaluated regularly by the chief operating decision maker in deciding how to allocate resources and assess performance. In determining its operating segments, Inergy examined the way it organizes its business internally for making operating decisions and assessing business performance. See Note 10 for disclosures related to Inergy’s three operating and reporting segments.

Fair Value

Cash and Cash Equivalents, Accounts Receivable and Accounts Payable

As of June 30, 2013 and December 31, 2012, the carrying amounts of cash and cash equivalents, accounts receivable (net of allowance for doubtful accounts) and accounts payable represent fair value due to their liquid and short-term nature.

Credit Facilities

The fair value of the Company's credit agreement and all of its credit facilities approximates their carrying amounts as of June 30, 2013 and December 31, 2012 due primarily to the variable nature of the interest rates of the instruments.

Senior Notes

Inergy estimates the fair value of its senior notes primarily based on quoted market prices for the same or similar issuances. This valuation methodology is considered level 2 in the fair value hierarchy. The following table reflects the carrying value and fair value of the senior notes (in millions):

	June 30, 2013				December 31, 2012
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Inergy senior unsecured notes	$	11.5	$	11.8	$	—	$	—
CMLP senior notes	$	351.3	$	362.5	$	351.5	$	365.9
NRGM senior unsecured notes	$	500.0	$	494.7	$	—	$	—

See Note 6 for a discussion of the Company's assets and liabilities recorded at fair value on the balance sheet.

Recently Issued Accounting Pronouncements

On December 16, 2011, the Financial Accounting Standards Board issued ASU No. 2011-11, “Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities.” This ASU requires disclosures to provide information to help reconcile differences in the offsetting requirements under U.S. Generally Accepted Accounting Principles and International Financial Reporting Standards. The disclosure requirements of this ASU mandate that entities disclose both gross and net information about financial instruments and transactions eligible for offset in the statement of financial position as well as instruments and transactions subject to an enforceable master netting arrangement or similar agreement. ASU No. 2011-11 also requires disclosure of collateral received and posted in connection with master netting arrangements or similar arrangements. The scope of this ASU includes derivative contracts, repurchase agreements, and securities borrowing and lending arrangements. Entities are required to apply the amendments of ASU No. 2011-11 for annual reporting periods beginning on or after January 1, 2013, and interim periods within those annual periods. All disclosures provided by those amendments are required to be provided retrospectively for all comparative periods presented. The Company adopted the effects of ASU No. 2011-11 on January 1, 2013.

On February 5, 2013, the FASB issued ASU No. 2013-02, “Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income.” This ASU amends and clarifies the disclosure requirements prescribed in ASU No. 2011-05, “Comprehensive Income (Topic 220): Presentation of Comprehensive Income.” ASU No. 2013-02 requires that entities present information about reclassification adjustments from accumulated other comprehensive income in their annual financial statements in a single note or on the face of the financial statements. Public entities will also have to provide this information in their interim financial statements. Specifically, entities must present, either in a single note or parenthetically on the face of the financial statements, the effect of significant amounts reclassified from each component of accumulated other comprehensive income based on its source and the income statement line items affected by the reclassification. If a component is not required to be reclassified to net income in its entirety, entities would instead cross reference to the related footnote for additional information.  The Company adopted the requirements of ASU No. 2013-02 on January 1, 2013 and presented the required information in a single note.

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Business Acquisitions (Pro Forma Revenues) (Details) (Rangeland Energy, LLC, USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Rangeland Energy, LLC
Business Acquisition [Line Items]
Revenue	$ 389.9	$ 297.4	$ 912.7	$ 692.3
Net income	$ (37.1)	$ 18.9	$ (27.6)	$ 32.6
Earnings Per Share, Basic	$ (0.51)	$ 0.25	$ (0.49)	$ 0.48
Earnings Per Share, Diluted	$ (0.51)	$ 0.25	$ (0.49)	$ 0.48

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Segments (Tables)

6 Months Ended

Jun. 30, 2013

Segment Reporting [Abstract]

Summary Of Segment Information

evenues, gross profit, identifiable assets, goodwill, property, plant and equipment and cash expenditures for property, plant and equipment for each of Inergy's reporting segments are presented below (in millions):

	Three Months Ended June 30, 2013
	Gathering and Processing Operations		NGL and Crude Services Operations		Storage and Transportation Operations		Intersegment Operations		Corporate Assets		Total
Gathering and processing revenues	$	71.1	$	—	$	—	$	—	$	—	$	71.1
Supply and logistics revenues	—		38.1		—		—		—		38.1
Storage and transportation revenues	—		—		9.7		—		—		9.7
Gross profit (excluding depreciation, amortization and accretion)	57.1		1.4		8.4		—		—		66.9
Identifiable assets	42.6		163.0		30.0		—		—		235.6
Goodwill	352.2		1,249.7		850.4		—		—		2,452.3
Property, plant and equipment	1,297.7		402.2		2,152.4		—		2.4		3,854.7
Cash expenditures for property, plant and equipment	56.0		0.3		3.5		—		—		59.8

	Three Months Ended June 30, 2012
	Gathering and Processing Operations		NGL and Crude Services Operations		Storage and Transportation Operations		Intersegment Operations		Corporate Assets		Total
Gathering and processing revenues	$	55.2	$	—	$	—	$	—	$	—	$	55.2
Supply and logistics revenues	—		—		—		—		—		—
Storage and transportation revenues	—		—		—		—		—		—
Gross profit (excluding depreciation, amortization and accretion)	47.8		—		—		—		—		47.8
Identifiable assets	35.0		—		—		—		—		35.0
Goodwill	348.1		—		—		—		—		348.1
Property, plant and equipment	1,087.9		—		—		—		—		1,087.9
Cash expenditures for property, plant and equipment	9.5		—		—		—		—		9.5

	Six Months Ended June 30, 2013
	Gathering and Processing Operations		NGL and Crude Services Operations		Storage and Transportation Operations		Intersegment Operations		Corporate Assets		Total
Gathering and processing revenues	$	143.5	$	—	$	—	$	—	$	—	$	143.5
Supply and logistics revenues	—		38.1		—		—		—		38.1
Storage and transportation revenues	—		—		9.7		—		—		9.7
Gross profit (excluding depreciation, amortization and accretion)	116.0		1.4		8.4		—		—		125.8
Identifiable assets	42.6		163.0		30.0		—		—		235.6
Goodwill	352.2		1,249.7		850.4		—		—		2,452.3
Property, plant and equipment	1,297.7		402.2		2,152.4		—		2.4		3,854.7
Cash expenditures for property, plant and equipment	80.3		0.3		3.5		—		—		84.1

	Six Months Ended June 30, 2012
	Gathering and Processing Operations		NGL and Crude Services Operations		Storage and Transportation Operations		Intersegment Operations		Corporate Assets		Total
Gathering and processing revenues	$	109.0	$	—	$	—	$	—	$	—	$	109.0
Supply and logistics revenues	—		—		—		—		—		—
Storage and transportation revenues	—		—		—		—		—		—
Gross profit (excluding depreciation, amortization and accretion)	92.6		—		—		—		—		92.6
Identifiable assets	35.0		—		—		—		—		35.0
Goodwill	348.1		—		—		—		—		348.1
Property, plant and equipment	1,087.9		—		—		—		—		1,087.9
Cash expenditures for property, plant and equipment	22.4		—		—		—		—		22.4

XML

Summary of Significant Accounting Policies (Narrative) (Detail) (USD $) In Millions, unless otherwise specified	6 Months Ended		12 Months Ended	3 Months Ended		6 Months Ended
	Jun. 30, 2013 segment derivative	Jun. 30, 2012	Dec. 31, 2012	Jun. 30, 2013 Unit based compensation	Jun. 30, 2012 Unit based compensation	Jun. 30, 2013 Unit based compensation	Jun. 30, 2012 Unit based compensation	Jun. 30, 2013 Texas State and Local Jurisdiction	Jun. 30, 2013 SPH Units
Summary Of Significant Accounting Policies [Line Items]
Derivative, Number of Instruments Held	0
Accumulated other comprehensive income (loss)	$ (0.2)
Accumulated Other Comprehensive Income (Loss), Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges, Effect Net of Tax									(0.2)
Percentage of gross income from qualifying sources required to be subject to federal income tax, minimum	90.00%
Effective Income Tax Rate Reconciliation, Other than Income Taxes, Statutory Income Tax Rate, Percent								0.70%
Construction in Progress Expenditures Incurred but Not yet Paid	45.1		9.2
Asset Retirement Obligations, Noncurrent	14.4		14.0
Unit-based compensation expense	$ 2.0	$ 1.0		$ 1.4	$ 0.5	$ 2.0	$ 1.0
Number of Operating Segments	3

XML

Certain Balance Sheet Information (Property, Plant And Equipment) (Detail) (USD $) In Millions, unless otherwise specified	Jun. 30, 2013	Dec. 31, 2012	Jun. 30, 2012
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 3,854.7	$ 1,197.4	$ 1,087.9
Less: accumulated depreciation	126.5	95.0
Property, plant and equipment, net	3,728.2	1,102.4
Capital Leased Assets, Gross	11.6	11.8
Gathering systems
Property, Plant and Equipment [Line Items]
Property, plant and equipment	622.6	582.3
Processing plants and compression facilities
Property, Plant and Equipment [Line Items]
Property, plant and equipment	507.3	485.4
Plant equipment
Property, Plant and Equipment [Line Items]
Property, plant and equipment	659.5	0
Building and improvements
Property, Plant and Equipment [Line Items]
Property, plant and equipment	102.8	66.4
Land
Property, Plant and Equipment [Line Items]
Property, plant and equipment	779.6	4.1
Pipelines
Property, Plant and Equipment [Line Items]
Property, plant and equipment	650.4	0
Vehicles
Property, Plant and Equipment [Line Items]
Property, plant and equipment	32.1	0.3
Construction in process
Property, Plant and Equipment [Line Items]
Property, plant and equipment	280.6	56.0
Base gas
Property, Plant and Equipment [Line Items]
Property, plant and equipment	109.1	0
Salt deposits
Property, Plant and Equipment [Line Items]
Property, plant and equipment	102.0	0
Office furniture and equipment
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 8.7	$ 2.9

XML

Subsequent Events (Detail) (Subsequent Event, USD $) In Millions, except Share data, unless otherwise specified	0 Months Ended			0 Months Ended			0 Months Ended
	Jun. 18, 2013	Apr. 26, 2013	Jun. 24, 2013 Interest in Unidentified Entity [Member]	Jul. 19, 2013 Subsidiary Issuer [Member] Interest in Unidentified Entity [Member]	Jul. 19, 2013 Crestwood Niobrara LLC [Member] Interest in Unidentified Entity [Member]	Jun. 24, 2013 Crestwood Niobrara LLC [Member] Interest in Unidentified Entity [Member]	Apr. 26, 2013 Cash distribution	Apr. 26, 2013 Cash distribution Inergy	Apr. 26, 2013 Cash distribution Inergy Midstream	Jun. 18, 2013 Unit Distribution Inergy Midstream	Apr. 26, 2013 Inergy Cash distribution Inergy Midstream	Jul. 19, 2013 CMLP Credit Facility Interest in Unidentified Entity [Member]	Jul. 19, 2013 Capital Contributions Commitments [Member] Maximum Crestwood Niobrara LLC [Member] Interest in Unidentified Entity [Member]
Subsequent Event [Line Items]
Declared distribution date		Jul. 25, 2013
Distribution declared per unit							$ 0.3025	$ 0.130	$ 0.1725		$ 0.40
Distribution payable date							Aug. 14, 2013
Record Date							Aug. 07, 2013
Distribution Made to Limited Partner, Unit Distribution										56,400,000
Distribution Made to Limited Partner, Unit Distribution, Per Unit	0.432052
Business Acquisition, Percentage of Voting Interests Acquired						50.00%
Business Combination, Consideration Transferred			$ 108
Debt Instrument, Increase, Additional Borrowings												27
Other Significant Noncash Transaction, Value of Consideration Received				81
Other Commitment, Percentage of Contributions					75.00%
Other Commitment													$ 69

XML

Related Party Transactions (Details) (Affiliated Entity, USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012	Dec. 31, 2012
Affiliated Entity
Related Party Transaction [Line Items]
Gathering and processing revenues	$ 24.6	$ 28.2	$ 50.2	$ 58.8
Gathering and processing cost of goods sold	7.9	0	14.6	0
Operating and administrative expense	5.5	4.8	11.1	9.5
Reimbursements	0.3	0.3	0.5	0.5
Related Party Transaction, Due from (to) Related Party [Abstract]
Accounts receivable	20.9		20.9		23.8
Accounts payable	$ 7.2		$ 7.2		$ 3.1

XML

Long-Term Debt (Components Of Long-Term Debt) (Detail) (USD $) In Millions, unless otherwise specified	Jun. 30, 2013	Dec. 31, 2012
Debt Instrument [Line Items]
Senior Notes	$ 11.5	$ 0
Obligations under noncompetition agreements and notes to former owners of businesses acquired	2.9	0
Total debt	1,875.6	685.2
Less: current portion	(2.5)	0
Total long-term debt	1,873.1	685.2
Revolving Loan Facility
Debt Instrument [Line Items]
Credit agreement outstanding carrying value	340.3	0
CMLP
Debt Instrument [Line Items]
Credit agreement outstanding carrying value	300.2	206.7
Senior Notes	350.0	350.0
Premium on senior notes	1.3	1.5
Nrgm Credit Facility
Debt Instrument [Line Items]
Credit agreement outstanding carrying value	237.0	0
Senior Notes	500.0	0
Liabilities, Fair Value Adjustment	$ 5.0	$ 0

XML

Consolidated Balance Sheets (Parenthetical) (USD $) In Millions, except Share data, unless otherwise specified	Jun. 30, 2013	Dec. 31, 2012
Allowance for doubtful accounts	$ 1.3	$ 0
Common units, issued	171,109,549	39,491,002
Common units, outstanding	171,109,549	39,491,002
Class B
Common units, issued	0	0
Common units, outstanding	0	0

XML

Long-Term Debt

6 Months Ended

Jun. 30, 2013

Text Block [Abstract]

Long-Term Debt

Long-Term Debt

Long-term debt consisted of the following at June 30, 2013 and December 31, 2012, respectively (in millions):

	June 30, 2013		December 31, 2012
NRGY credit agreement	$	340.3	$	—
NRGY senior unsecured notes	11.5		—
NRGY obligations under noncompetition agreements and notes to former owners of businesses acquired	2.9		—
CMLP credit facility	300.2		206.7
CMLP senior notes	350.0		350.0
CMLP premium on senior notes	1.3		1.5
CMM credit facility	127.4		127.0
NRGM credit facility	237.0		—
NRGM senior unsecured notes	500.0		—
Fair value adjustment of NRGM senior unsecured notes	5.0		—
Total debt	1,875.6		685.2
Less: current portion	2.5		—
Total long-term debt	$	1,873.1	$	685.2

At June 30, 2013, each of Inergy, Inergy Midstream, Crestwood Midstream and Crestwood Marcellus Midstream LLC (CMM), a wholly-owned subsidiary of Crestwood Midstream, was in compliance with the debt covenants in their respective credit facilities and senior notes, as described below.

Inergy and its subsidiaries do not provide credit support or guarantee any amounts outstanding under NRGM's or CMLP's credit facilities or senior notes. NRGM, CMLP and their respective subsidiaries do not provide credit support or guarantee any amounts outstanding under Inergy's credit facility or senior notes.

NRGY Credit Facility

Inergy utilizes a secured credit facility ("NRGY Credit Facility") with an aggregate revolving loan facility of $550 million to fund working capital requirements and as a source of capital to fund capital expenditures and acquisitions. All borrowings under the NRGY Credit Facility are generally secured by substantially all of Inergy's assets and the equity interests in all of Inergy's wholly owned subsidiaries, and loans thereunder bear interest, at Inergy's option, subject to certain limitations, at a rate equal to the following:

• the Alternate Base Rate, which is defined as the higher of (i) the federal funds rate plus 0.50%; (ii) JP Morgan's prime rate; or (iii) the Adjusted LIBO Rate plus 1%; plus a margin varying from 0.75% to 2.00%; or

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

At June 30, 2013, the balance outstanding under the NRGY Credit Facility was $340.3 million. The interest rates of the NRGY Credit Facility are based on prime rate and LIBOR plus the applicable spreads, resulting in interest rates which were between 1.95% and 4.00% at June 30, 2013. Availability under the NRGY Credit Facility amounted to $166.5 million at June 30, 2013. Outstanding standby letters of credit under the credit facility amounted to $43.2 million at June 30, 2013.

The credit agreement governing the NRGY Credit Facility contains various covenants and restrictive provisions that limit its ability to, among other things: incur additional debt; make distributions on or redeem or repurchase units; make certain investments and acquisitions; incur or permit certain liens to exist; enter into certain types of transactions with affiliates; merge, consolidate or amalgamate with another company; and transfer or otherwise dispose of assets.

The NRGY Credit Facility contains the following financial covenants:

• the ratio of Inergy's total funded debt (as defined in the credit agreement) to consolidated EBITDA (as defined in the credit agreement) for the four fiscal quarters most recently ended must be no greater than 4.75 to 1.0; and

• the ratio of Inergy's consolidated EBITDA to consolidated interest expense (as defined in the credit agreement), for the four fiscal quarters then most recently ended, must not be less than 2.50 to 1.0.

At June 30, 2013, the total funded debt to consolidated EBITDA was approximately 4.0 to 1.0 and consolidated EBITDA to consolidated interest expense was approximately 10.0 to 1.0.

On May 23, 2013, Inergy obtained from its lenders certain waivers and consents necessary to consummate the transactions that resulted in Crestwood Holdings' acquisition of its general partner and its acquisition of the general partner of Crestwood Midstream. Inergy also amended its credit agreement to, among other things, (i) require Inergy to prepay up to $300 million in aggregate principal amount of borrowings outstanding under the NRGY Credit Facility with net proceeds received by Inergy or its subsidiaries from asset dispositions or insurance proceeds (“Net Proceeds”), (ii) automatically reduce the lenders' revolving loan commitments by an amount equal to the Net Proceeds, and (iii) permit the sale of assets from Inergy to its subsidiaries and to Inergy Midstream and its subsidiaries.

Inergy has entered into six interest rate swaps that mature in 2016 to hedge our exposure to variable interest payments due under the NRGY Credit Facility. These swap agreements require Inergy to pay the counterparty an amount based on fixed rates from 0.84% to 2.52% due quarterly on an aggregate notional amount of $225.0 million. In exchange, the counterparty is required to make quarterly floating interest rate payments on the same date to Inergy based on the three-month LIBOR applied to the same aggregate notional amount of $225.0 million.

NRGY Senior Notes

Inergy has $11.5 million in outstanding senior notes, the majority of which mature on October 1, 2018 and have a coupon rate of 7%. The outstanding senior notes do not contain any financial covenants.

CMLP Credit Facility

In November 2012, CMLP entered into an amended and restated $550 millionfive-year revolving credit facility (“CMLP Credit Facility”). The CMLP Credit Facility is available to fund acquisitions, working capital and internal growth projects and for general partnership purposes. The credit facility includes sub-limits up to $10 million and $100 million for swing loans and letters of credit, respectively.

Borrowings under the CMLP Credit Facility are generally secured by liens on substantially all of the assets of CMLP and its wholly owned subsidiaries, except CMM and its consolidated subsidiaries. The CMLP Credit Agreement is fully and unconditionally guaranteed, jointly and severally, by CMLP's wholly owned subsidiaries other than CMM.

Borrowings under the CMLP Credit Facility bear interest at LIBOR plus an applicable margin or a base rate as defined in the CMLP credit agreement. Under the terms of the CMLP Credit Facility, the applicable margin under LIBOR borrowings was 2.8% and 2.5% at June 30, 2013 and December 31, 2012, respectively. The weighted-average interest rate as of June 30, 2013 and December 31, 2012 was 3.0% and 2.8%, respectively. At June 30, 2013 and December 31, 2012, the balance outstanding under the CMLP Credit Facility was $300.2 million and $206.7 million, respectively. As a result, CMLP had approximately $110.6 million of remaining capacity under the CMLP Credit Facility at June 30, 2013, subject to compliance with any applicable covenants under such facility.

The credit facility requires CMLP to maintain:

• a ratio of consolidated trailing twelve-month EBITDA (as defined in its credit facility) to net interest expense of not less than 2.5 to 1.0; and

• a ratio of total indebtedness to consolidated trailing twelve-month EBITDA (as defined in its credit facility) of not more than 5.0 to 1.0, or not more than 5.5 to 1.0 for up to nine months following certain acquisitions.

At June 30, 2013, consolidated trailing twelve-month EBITDA to net interest expense was 4.1 to 1.0 and total indebtedness to consolidated trailing twelve-month EBITDA was 4.3 to 1.0.

The CMLP Credit Facility contains restrictive covenants that, among other things, prohibit the declaration or payment of distributions by CMLP if a default then exists or would result therefrom, and otherwise limits the amount of distributions that CMLP can make.

CMLP Senior Notes

In April 2011, CMLP and Crestwood Midstream Finance Corporation (“Crestwood Finance” and together with CMLP, the “CMLP Issuers”) issued $200 million in a private offering in aggregate principal amount of their 7.75% Senior Notes due 2019 (the “Initial CMLP Notes”). On November 14, 2012, the CMLP Issuers issued and sold an additional $150 million in a private offering in aggregate principal amount of their 7.75% Senior Notes due 2019 (the “Additional CMLP Notes,” and together with the Initial CMLP Notes, the “CMLP Notes”). The CMLP Notes will mature on April 1, 2019, and interest is payable semi-annually in arrears on April 1 and October 1 of each year. Interest payments commenced on October 1, 2011 and April 1, 2013 for the Initial CMLP Notes and the Additional CMLP Notes, respectively, noting that interest payable on the Additional CMLP Notes' April 1, 2013 payment date commenced accruing on October 1, 2012.

In general, the CMLP Notes are fully and unconditionally guaranteed, joint and severally, on a senior unsecured basis by CMLP's subsidiaries (other than Crestwood Finance and CMM and its subsidiaries). The indenture contains customary release provisions, such as (i) disposition of all or substantially all the assets of, or the capital stock of, a guarantor subsidiary to a third person if the disposition complies with the indenture; (ii) designation of a guarantor subsidiary as an Unrestricted Subsidiary in accordance with its indentures; (iii) legal or covenant defeasance of a series of senior notes, or satisfaction and discharge of the related indenture; and (iv) guarantor subsidiary ceases to guarantee any other indebtedness of CMLP or any other guarantor subsidiary, provided it no longer guarantees indebtedness under the CMLP Credit Facility. CMLP has no independent assets or operations, and Crestwood Finance is a 100% finance subsidiary of CMLP.

The indenture restricts the ability of CMLP and its subsidiaries to, among other things, sell assets; pay distributions on, redeem or repurchase CMLP units, redeem or repurchase subordinated debt; make investments; incur or guarantee additional indebtedness or issue preferred units; create or incur certain liens; enter into agreements that restrict distributions or other payments to CMLP from its restricted subsidiaries; consolidate, merge or transfer all or substantially all of CMLP's assets; and, engage in affiliate transactions; create unrestricted subsidiaries. These restrictions are subject to a number of important exceptions and qualifications, and many of these restrictions will terminate when the senior notes are rated investment grade and no default under the indenture has occurred and is continuing.

The CMLP Notes require CMLP to maintain a ratio of our consolidated trailing twelve-month EBITDA (as defined in the indenture governing the senior notes) to fixed charges of at least 1.75 to 1.0, which at June 30, 2013 was 3.9 to 1.0.

CMM Credit Facility

In March 2012, CMM entered into a $200 million, revolving five-year credit facility (“CMM Credit Facility”). The CMM Credit Facility is available to fund CMM's continued build out of its Marcellus gathering systems. The credit facility includes sub-limits up to $10 million and $25 million for swing loans and letters of credit, respectively. The CMM Credit Facility is secured by all of CMM's assets.

At June 30, 2013, the balance outstanding under the CMM Credit Facility was $127.4 million. At December 31, 2012, the balance outstanding under the CMM Credit Facility was $127.0 million. There were no outstanding standby letters of credit under the CMM Credit Facility at June 30, 2013. As a result, CMM had approximately $72.6 million of remaining capacity at June 30, 2013, subject to compliance with any applicable covenants under such facility.

Borrowings under the CMM Credit Facility bear interest at LIBOR plus an applicable margin or base rate, as defined in the credit agreement governing the CMM Credit Facility. Under the terms of the CMM Credit Facility, the applicable margin under LIBOR was 2.5% at June 30, 2013 and December 31, 2012. The weighted-average interest rate as of June 30, 2013 and December 31, 2012 was 2.8%.

The CMM Credit Facility requires CMM to maintain:

• a ratio of trailing twelve-month EBITDA (as defined in the credit agreement) to net interest expense of not less than 2.0 to 1.0; and

• a ratio of total indebtedness to trailing twelve-month EBITDA (as defined in the credit agreement) of not more than 4.5 to 1.0, or not more than 5.0 to 1.0 for up to nine months following certain acquisitions.

At June 30, 2013, trailing twelve-month EBITDA to net interest expense was 11.4 to 1.0 and total indebtedness to trailing twelve-month EBITDA was 2.9 to 1.0.

The CMM Credit Facility contains restrictive covenants that, among other things, prohibit the declaration or payment of distributions by CMM if a default then exists or would result therefrom, and otherwise limits the amount of distributions that CMM can make.

NRGM Credit Facility

Inergy Midstream utilizes a $600.0 million revolving credit facility (“NRGM Credit Facility”). The NRGM Credit Facility is available to fund acquisitions, working capital and internal growth projects and for general partnership purposes. The NRGM Credit Facility has an accordion feature that allows Inergy Midstream to increase the available borrowings under the facility by up to $150.0 million, subject to the lenders' agreement and the satisfaction of certain conditions. In addition, its credit facility includes a sub-limit up to $10 million for same-day swing line advances and a sub-limit up to $100 million for letters of credit.

At June 30, 2013, the balance outstanding under the NRGM Credit Facility was $237.0 million. Outstanding standby letters of credit under the NRGM Credit Facility amounted to $2.0 million at June 30, 2013. As a result, Inergy Midstream had approximately $361.0 million of remaining capacity at June 30, 2013, subject to compliance with any applicable covenants under such facility.

Borrowings under the NRGM Credit Facility are generally secured by liens on substantially all of the assets of, and pledges of the equity interests in, Inergy Midstream's subsidiaries. The NRGM Credit Facility is fully and unconditionally guaranteed, jointly and severally, by Inergy Midstream's subsidiaries. The credit agreement governing the NRGM Credit Facility contains various covenants and restrictive provisions that limit its ability to, among other things: incur additional debt; make distributions on or redeem or repurchase units; make certain investments and acquisitions; incur or permit certain liens to exist; enter into certain types of transactions with affiliates; merge, consolidate or amalgamate with another company; and transfer or otherwise dispose of assets.

The NRGM Credit Facility requires maintenance of a consolidated leverage ratio (as defined in its credit agreement) of not more than 5.00 to 1.0 (subject to increase to 5.50 to 1.0 following certain permitted acquisitions, as indicated above) and an interest coverage ratio (as defined in its credit agreement) of not less than 2.50 to 1.0. The NRGM Credit Facility also requires maintenance of a senior secured leverage ratio (as defined in its credit agreement) of not more than 3.75 to 1.0 on and after the cumulative issuance of $200 million or more of permitted junior debt. At June 30, 2013, the consolidated leverage ratio was 4.1 to 1.0, the interest coverage ratio was 6.8 to 1.0 and the senior secured leverage ratio was 1.3 to 1.0.

Borrowings under the NRGM Credit Facility (other than swing loans) will bear interest at its option at either:

• the Alternate Base Rate, which is defined as the highest of (i) the federal funds rate plus 0.50%; (ii) JP Morgan's prime rate; or (iii) the Adjusted LIBO Rate plus 1%; plus a margin varying from 0.75% to 1.75% depending on Inergy Midstream's most recent total leverage ratio; or

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

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

NRGM Senior Notes

At June 30, 2013, the balance outstanding on the Inergy Midstream 6.0% Senior Notes due 2020 (the “NRGM Notes”) was $500.0 million. The Company recorded a $5.0 million adjustment in conjunction with the Inergy reverse acquisition to adjust the debt to fair value. The senior notes will mature on December 15, 2020, and interest is payable semi-annually in arrears on June 15 and December 15 of each year.

In general, the NRGM Notes are fully and unconditionally guaranteed, joint and severally, on a senior unsecured basis by Inergy Midstream's subsidiaries (other than Finance Corp.). The indenture contains customary release provisions, such as (i) disposition of all or substantially all the assets of, or the capital stock of, a guarantor subsidiary to a third person if the disposition complies with the indenture; (ii) designation of a guarantor subsidiary as an Unrestricted Subsidiary in accordance with our indentures; (iii) legal or covenant defeasance of a series of senior notes, or satisfaction and discharge of the related indenture; and (iv) guarantor subsidiary ceases to guarantee any other indebtedness of ours or any other guarantor subsidiary, provided it no longer guarantees indebtedness under the NRGM Credit Facility. Inergy Midstream has no independent assets or operations, and Finance Corp. is a 100% finance subsidiary of Inergy Midstream.

The indenture restricts the ability of Inergy Midstream and its subsidiaries to, among other things, sell assets; pay distributions on, redeem or repurchase NRGM units, redeem or repurchase subordinated debt; make investments; incur or guarantee additional indebtedness or issue preferred units; create or incur certain liens; enter into agreements that restrict distributions or other payments to Inergy Midstream from its restricted subsidiaries; consolidate, merge or transfer all or substantially all of Inergy Midstream's assets; and, engage in affiliate transactions; create unrestricted subsidiaries. These restrictions are subject to a number of important exceptions and qualifications, and many of these restrictions will terminate when the senior notes are rated investment grade and no default under the indenture has occurred and is continuing.

On May 14, 2013, Inergy Midstream commenced a consent solicitation for the purpose of amending the indenture to ensure that the consummation of the Crestwood business combination would not constitute a “Change of Control” thereunder, which would have entitled the NRGM note holders to require Inergy Midstream to repurchase the senior notes. The consent solicitation was conditioned on the receipt of consents from holders of record on the record date of a majority in aggregate principal amount of the NRGM Notes. On May 22, 2013, following its receipt of the requisite consents, Inergy Midstream entered into a second supplemental indenture memorializing the requested changes to the indenture. As part of the consent solicitation, consents were delivered and not revoked by holders of approximately $464.5 million in aggregate principal amount (or 92.9%) of the NRGM Notes.

XML

Consolidated Statements of Comprehensive Income (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Net income (loss)	$ (4.5)	$ 8.3	$ (0.6)	$ 12.8
Change in Suburban Propane Partners, L.P. units (Note 2)	(0.2)	0	(0.2)	0
Comprehensive income (loss)	$ (4.7)	$ 8.3	$ (0.8)	$ 12.8

XML

Consolidated Balance Sheets (USD $) In Millions, unless otherwise specified	Jun. 30, 2013	Dec. 31, 2012
Assets
Cash and cash equivalents	$ 2.7	$ 0.1
Accounts receivable, less allowance for doubtful accounts of $1.3 million at June 30, 2013	182.4	45.4
Inventory (Note 3)	53.2	0
Assets from price risk management activities	15.3	0
Prepaid expenses and other current assets	22.5	4.9
Assets held for sale (Note 3)		0
Total current assets	282.8	50.4
Property, plant and equipment (Note 3)	3,854.7	1,197.4
Less: accumulated depreciation	126.5	95.0
Property, plant and equipment, net	3,728.2	1,102.4
Intangible assets (Note 3)	1,119.2	845.2
Less: accumulated amortization	70.6	49.9
Intangible assets, net	1,048.6	795.3
Goodwill	2,452.3	352.2
Other assets	53.8	1.3
Total assets	7,565.7	2,301.6
Current liabilities:
Accounts payable	151.6	5.4
Accrued expenses and other liabilities	115.5	43.1
Liabilities from price risk management activities	8.0	0
Current portion of long-term debt (Note 7)	2.5	0
Total current liabilities	277.6	48.5
Long-term debt, less current portion (Note 7)	1,873.1	685.2
Other long-term liabilities	39.0	17.2
Deferred income taxes	20.0	0
Partners’ capital (Note 8):
Limited partner unitholders (171,109,549 and 39,491,002 limited partner units issued and outstanding at June 30, 2013 and December 31, 2012, respectively)	1,401.8	31.7
Total Inergy, L.P. partners’ capital	1,401.8	31.7
Interest of non-controlling partners in subsidiaries	3,954.2	1,519.0
Total partners’ capital	5,356.0	1,550.7
Total liabilities and partners’ capital	$ 7,565.7	$ 2,301.6

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Condensed Consolidating Financial Information (Condensed Consolidating Balance Sheet) (Detail) (USD $) In Millions, unless otherwise specified	Jun. 30, 2013	Dec. 31, 2012	Jun. 30, 2012	Dec. 31, 2011
Current assets:
Cash and cash equivalents	$ 2.7	$ 0.1	$ 8.7	$ 0.8
Accounts receivable	182.4	45.4
Inventory	53.2	0
Total current assets	282.8	50.4
Property, plant and equipment, net	3,728.2	1,102.4
Other assets	53.8	1.3
Total assets	7,565.7	2,301.6
Current liabilities:
Accounts payable	151.6	5.4
Total current liabilities	277.6	48.5
Long-term liabilities:
Long-term debt, less current portion (Note 7)	1,873.1	685.2
Other long-term liabilities	39.0	17.2
Partners' capital	1,401.8	31.7
Interest of non-controlling partners in subsidiary	3,954.2	1,519.0
Total partners’ capital	5,356.0	1,550.7
Total liabilities and partners’ capital	7,565.7	2,301.6
Parent Company
Current assets:
Cash and cash equivalents	0.1	0
Accounts receivable	0
Inventory	0
Other	0
Total current assets	0.1
Property, plant and equipment, net	0
Goodwill and intangible assets, net	0
Investment in subsidiary	1,782.6
Other assets	0
Total assets	1,782.7
Current liabilities:
Accounts payable	0
Other	1.6
Total current liabilities	1.6
Long-term liabilities:
Long-term debt, less current portion (Note 7)	354.2
Other long-term liabilities	25.1
Total long-term liabilities	379.3
Partners' capital	1,401.8
Interest of non-controlling partners in subsidiary	0
Total partners’ capital	1,401.8
Total liabilities and partners’ capital	1,782.7
Guarantor Subsidiaries
Current assets:
Cash and cash equivalents	1.3	0
Accounts receivable	111.7
Inventory	47.6
Other	21.2
Total current assets	181.8
Property, plant and equipment, net	816.7
Goodwill and intangible assets, net	928.9
Investment in subsidiary	0
Other assets	29.3
Total assets	1,956.7
Current liabilities:
Accounts payable	132.6
Other	39.5
Total current liabilities	172.1
Long-term liabilities:
Long-term debt, less current portion (Note 7)	0
Other long-term liabilities	17.2
Total long-term liabilities	17.2
Partners' capital	1,767.4
Interest of non-controlling partners in subsidiary	0
Total partners’ capital	1,767.4
Total liabilities and partners’ capital	1,956.7
Non-Guarantor Subsidiaries
Current assets:
Cash and cash equivalents	1.3	0.1
Accounts receivable	70.7
Inventory	5.6
Other	24.5
Total current assets	102.1
Property, plant and equipment, net	2,911.5
Goodwill and intangible assets, net	2,572.0
Investment in subsidiary	0
Other assets	24.5
Total assets	5,610.1
Current liabilities:
Accounts payable	19.0
Other	86.1
Total current liabilities	105.1
Long-term liabilities:
Long-term debt, less current portion (Note 7)	1,518.9
Other long-term liabilities	16.7
Total long-term liabilities	1,535.6
Partners' capital	15.2
Interest of non-controlling partners in subsidiary	3,954.2
Total partners’ capital	3,969.4
Total liabilities and partners’ capital	5,610.1
Consolidation, Eliminations
Current assets:
Cash and cash equivalents	0	0
Accounts receivable	0
Inventory	0
Other	(1.2)
Total current assets	(1.2)
Property, plant and equipment, net	0
Goodwill and intangible assets, net	0
Investment in subsidiary	(1,782.6)
Other assets	0
Total assets	(1,783.8)
Current liabilities:
Accounts payable	0
Other	(1.2)
Total current liabilities	(1.2)
Long-term liabilities:
Long-term debt, less current portion (Note 7)	0
Other long-term liabilities	0
Total long-term liabilities	0
Partners' capital	(1,782.6)
Interest of non-controlling partners in subsidiary	0
Total partners’ capital	(1,782.6)
Total liabilities and partners’ capital	(1,783.8)
Consolidated Entities
Current assets:
Cash and cash equivalents	2.7	0.1
Accounts receivable	182.4
Inventory	53.2
Other	44.5
Total current assets	282.8
Property, plant and equipment, net	3,728.2
Goodwill and intangible assets, net	3,500.9
Investment in subsidiary	0
Other assets	53.8
Total assets	7,565.7
Current liabilities:
Accounts payable	151.6
Other	126.0
Total current liabilities	277.6
Long-term liabilities:
Long-term debt, less current portion (Note 7)	1,873.1
Other long-term liabilities	59.0
Total long-term liabilities	1,932.1
Partners' capital	1,401.8
Interest of non-controlling partners in subsidiary	3,954.2
Total partners’ capital	5,356.0
Total liabilities and partners’ capital	$ 7,565.7

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Related Party Transactions (Tables)

6 Months Ended

Jun. 30, 2013

Related Party Transactions [Abstract]

Schedule of Related Party Transactions

The following table shows revenues, cost of goods sold, operating and administrative expense and reimbursements from Inergy's affiliates for the three-month and six-month periods endedJune 30, 2013 and 2012, respectively (in millions):

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2013		2012		2013		2012
Gathering and processing revenues	$	24.6	$	28.2	$	50.2	$	58.8
Gathering and processing cost of goods sold	$	7.9	$	—	$	14.6	$	—
Operating and administrative expense	$	5.5	$	4.8	$	11.1	$	9.5
Reimbursements	$	0.3	$	0.3	$	0.5	$	0.5

Schedule of Related Party Receivables and Payables

The following table shows accounts receivable and accounts payable from Inergy's affiliates as of June 30, 2013 and December 31, 2012, respectively (in millions):

	June 30,  2013		December 31, 2012
Accounts receivable	$	20.9	$	23.8
Accounts payable	$	7.2	$	3.1

XML

Certain Balance Sheet Information (Tables)

6 Months Ended

Jun. 30, 2013

Balance Sheet Related Disclosures [Abstract]

Inventories

Inventory consisted of the following at June 30, 2013 and December 31, 2012, respectively (in millions):

	June 30, 2013		December 31, 2012
NGLs	$	46.8	$	—
Parts, supplies and other	6.4		—
Total inventory	$	53.2	$	—

Property, Plant And Equipment

Property, plant and equipment consisted of the following at June 30, 2013 and December 31, 2012, respectively (in millions):

	June 30, 2013		December 31, 2012
Gathering systems	$	622.6	$	582.3
Processing plants and compression facilities	507.3		485.4
Plant equipment	659.5		—
Buildings, rights-of-way, easements and storage rights	102.8		66.4
Land	779.6		4.1
Pipelines	650.4		—
Vehicles	32.1		0.3
Construction in process	280.6		56.0
Base gas	109.1		—
Salt deposits	102.0		—
Office furniture and equipment	8.7		2.9
	3,854.7		1,197.4
Less: accumulated depreciation	126.5		95.0
Total property, plant and equipment, net	$	3,728.2	$	1,102.4

Intangible Assets

Intangible assets consisted of the following at June 30, 2013 and December 31, 2012, respectively (in millions):

	June 30, 2013		December 31, 2012
Customer accounts	$	239.0	$	—
Gas gathering, compression and processing contracts	813.1		813.0
Trademarks	34.0		—
Deferred financing and other costs	33.1		32.2
	1,119.2		845.2
Less: accumulated amortization	70.6		49.9
Total intangible assets, net	$	1,048.6	$	795.3

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Risk Management (Narrative) (Detail) (USD $)	6 Months Ended
	Jun. 30, 2013
Derivative [Line Items]
Collateral posted for commodity derivative instruments	$ 5,100,000
Commodity contract
Derivative [Line Items]
Aggregate fair value of commodity derivative instruments	2,500,000
Collateral posted for commodity derivative instruments	800,000.0
NYMEX margin deposit
Derivative [Line Items]
NYMEX margin deposit	$ 4,100,000
Price Risk Contracts | Maximum
Derivative [Line Items]
Derivative, Remaining Maturity	28 months
Derivative Contracts, Contracts Expiring in Next Twleve Months, Percent	96.80%

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Condensed Consolidating Financial Information (Condensed Consolidating Statements Of Cash Flows) (Detail) (USD $) In Millions, unless otherwise specified	6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012
Cash flows from operating activities	$ 57.4	$ 42.2
Cash flows from investing activities:
Acquisitions, net of cash acquired	6.1	(376.8)
Purchases of property, plant and equipment	(84.1)	(22.4)
Net cash used in investing activities	(78.0)	(399.2)
Cash flows from financing activities:
Proceeds from the issuance of long-term debt	41.8	0
Principal payments on long-term debt	(21.5)	0
Distributions	(21.1)	(6.1)
Distributions paid to non-controlling partners	(48.4)	(39.4)
Net proceeds from the issuance of common units	118.5	103.0
Contributions from partners	0	(247.2)
Net cash provided by financing activities	23.2	364.9
Net increase in cash	2.6	7.9
Cash at beginning of period	0.1	0.8
Cash at end of period	2.7	8.7
Parent Company
Cash flows from operating activities	0
Cash flows from investing activities:
Acquisitions, net of cash acquired	0.1
Purchases of property, plant and equipment	0
Net cash used in investing activities	0.1
Cash flows from financing activities:
Proceeds from the issuance of long-term debt	0
Principal payments on long-term debt	0
Distributions	0
Distributions paid to non-controlling partners	0
Net proceeds from the issuance of common units	0
Other	0
Net cash provided by financing activities	0
Net increase in cash	0.1
Cash at beginning of period	0
Cash at end of period	0.1
Guarantor Subsidiaries
Cash flows from operating activities	(9.5)
Cash flows from investing activities:
Acquisitions, net of cash acquired	5.0
Purchases of property, plant and equipment	(0.5)
Net cash used in investing activities	4.5
Cash flows from financing activities:
Proceeds from the issuance of long-term debt	41.8
Principal payments on long-term debt	(21.5)
Distributions	(11.8)
Distributions paid to non-controlling partners	0
Net proceeds from the issuance of common units	0
Other	(2.2)
Net cash provided by financing activities	6.3
Net increase in cash	1.3
Cash at beginning of period	0
Cash at end of period	1.3
Non-Guarantor Subsidiaries
Cash flows from operating activities	66.9
Cash flows from investing activities:
Acquisitions, net of cash acquired	1.0
Purchases of property, plant and equipment	(83.6)
Net cash used in investing activities	(82.6)
Cash flows from financing activities:
Proceeds from the issuance of long-term debt	326.7
Principal payments on long-term debt	(238.5)
Distributions	(9.3)
Distributions paid to non-controlling partners	(177.4)
Net proceeds from the issuance of common units	118.5
Other	(3.1)
Net cash provided by financing activities	16.9
Net increase in cash	1.2
Cash at beginning of period	0.1
Cash at end of period	1.3
Consolidation, Eliminations
Cash flows from operating activities	0
Cash flows from investing activities:
Acquisitions, net of cash acquired	0
Purchases of property, plant and equipment	0
Net cash used in investing activities	0
Cash flows from financing activities:
Proceeds from the issuance of long-term debt	0
Principal payments on long-term debt	0
Distributions	0
Distributions paid to non-controlling partners	0
Net proceeds from the issuance of common units	0
Other	0
Net cash provided by financing activities	0
Net increase in cash	0
Cash at beginning of period	0
Cash at end of period	0
Consolidated Entities
Cash flows from operating activities	57.4
Cash flows from investing activities:
Acquisitions, net of cash acquired	6.1
Purchases of property, plant and equipment	(84.1)
Net cash used in investing activities	(78.0)
Cash flows from financing activities:
Proceeds from the issuance of long-term debt	368.5
Principal payments on long-term debt	(260.0)
Distributions	(21.1)
Distributions paid to non-controlling partners	(177.4)
Net proceeds from the issuance of common units	118.5
Other	(5.3)
Net cash provided by financing activities	23.2
Net increase in cash	2.6
Cash at beginning of period	0.1
Cash at end of period	$ 2.7

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Business Acquisitions (Narrative) (Details) (USD $) In Millions, unless otherwise specified	Jun. 30, 2013	Dec. 31, 2012	Dec. 07, 2012	Jun. 30, 2012
Business Acquisition [Line Items]
Goodwill	$ 2,452.3	$ 352.2	$ 2,100.1	$ 348.1
Rangeland Energy, LLC
Finite-Lived Intangible Assets, Net, Amortization Expense, Fiscal Year Maturity [Abstract]
2013	28.9
2014	28.9
2015	28.9
2016	28.9
2017 and thereafter	$ 28.9

XML

Summary of Significant Accounting Policies (Senior Notes) (Details) (USD $) In Millions, unless otherwise specified	Jun. 30, 2013	Dec. 31, 2012
Debt Instrument [Line Items]
Senior Notes	$ 11.5	$ 0
Notes Payable, Fair Value Disclosure	11.8	0
Nrgm Credit Facility
Debt Instrument [Line Items]
Senior Notes	500.0	0
Notes Payable, Fair Value Disclosure	494.7	0
CMLP | Senior Notes
Debt Instrument [Line Items]
Senior Notes	351.3	351.5
Notes Payable, Fair Value Disclosure	$ 362.5	$ 365.9

XML

Certain Balance Sheet Information (Inventories) (Detail) (USD $) In Millions, unless otherwise specified	Jun. 30, 2013	Dec. 31, 2012
Inventory [Line Items]
Inventory	$ 53.2	$ 0
NGLs
Inventory [Line Items]
Inventory	46.8	0
Parts, supplies and other
Inventory [Line Items]
Inventory	$ 6.4	$ 0

XML

Risk Management

6 Months Ended

Jun. 30, 2013

Risk Management - Notional Amounts and Terms of Companys Derivative Financial Instruments [Abstract]

Risk Management

Risk Management

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

Commodity Derivative Instruments and Price Risk Management

Risk Management Activities

Inergy sells NGLs to energy related businesses and may use a variety of financial and other instruments including forward contracts involving physical delivery of NGLs. Inergy will enter into offsetting positions to economically hedge against the exposure its customer contracts create, however does not designate these instruments as hedging instruments for accounting purposes. These instruments are marked to market with the changes in the market value reflected in cost of product/services sold. Inergy attempts to balance its contractual portfolio in terms of notional amounts and timing of performance and delivery obligations. This balance in the contractual portfolio significantly reduces the volatility in cost of product/services sold related to these instruments.

Fair Value Hedging Activity

Inergy will enter into derivative instruments to hedge its exposure to fluctuating commodity prices that results from maintaining its NGL inventory. Inergy may choose to designate these instruments as fair value hedges for accounting purposes. This accounting treatment requires the fair value changes in both the derivative instruments and the hedged inventory to be recorded in cost of product/services sold.

A significant amount of inventory held in bulk storage facilities is hedged as it is not expected to be sold in the immediate future and is therefore exposed to fluctuations in commodity prices.

Inergy did not have any derivative instruments designated as fair value hedges for accounting purposes in the three and six month periods ended June 30, 2013 and 2012.

Commodity Price and Credit Risk

Notional Amounts and Terms

The notional amounts and terms of the Company’s derivative financial instruments include the following at June 30, 2013 and December 31, 2012, respectively (in millions):

	June 30, 2013		December 31, 2012
	Fixed Price Payor	Fixed Price Receiver	Fixed Price Payor	Fixed Price Receiver
Propane, crude and heating oil (barrels)	4.8	5.8	—	—

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

All contracts subject to price risk had a maturity of twenty-eight months or less; however, 96.8% of the contracts expire within twelve months.

Credit Risk

Inherent in the Company's contractual portfolio are certain credit risks. Credit risk is the risk of loss from nonperformance by suppliers, customers or financial counterparties to a contract. Inergy takes an active role in managing credit risk and has established control procedures, which are reviewed on an ongoing basis. The Company attempts to minimize credit risk exposure through credit policies and periodic monitoring procedures as well as through customer deposits, letters of credit and entering into netting agreements that allow for offsetting counterparty receivable and payable balances for certain financial transactions, as deemed appropriate. The counterparties associated with assets from price risk management activities as of June 30, 2013 were energy marketers and propane retailers, resellers and dealers. There were no activities associated with assets from price risk management at December 31, 2012.

Certain of the Company's derivative instruments have credit limits that require the Company to post collateral. The amount of collateral required to be posted is a function of the net liability position of the derivative as well as the Company's established credit limit with the respective counterparty. If the Company's credit rating were to change, the counterparties could require the Company to post additional collateral. The amount of additional collateral that would be required to be posted would vary depending on the extent of change in the Company's credit rating as well as the requirements of the individual counterparty. The aggregate fair value of all commodity derivative instruments with credit-risk-related contingent features that are in a liability position on June 30, 2013, is $2.5 million for which the Company has posted $0.8 million of collateral in the normal course of business. The Company has posted $4.1 million of NYMEX margin deposit in the normal course of business. The Company has received collateral of $5.1 million in the normal course of business. All collateral amounts have been netted against the asset or liability with the respective counterparty.

XML

Condensed Consolidating Financial Information (Tables)

6 Months Ended

Jun. 30, 2013

Text Block [Abstract]

Condensed Consolidating Balance Sheet

Condensed Consolidating Balance Sheet
June 30, 2013
(in millions)
	Parent		Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	0.1	$	1.3	$	1.3	$	—		$	2.7
Accounts receivable	—		111.7		70.7		—			182.4
Inventories	—		47.6		5.6		—			53.2
Other current assets	—		21.2		24.5		(1.2		)	44.5
Total current assets	0.1		181.8		102.1		(1.2		)	282.8
Property, plant and equipment, net	—		816.7		2,911.5		—			3,728.2
Goodwill and intangible assets, net	—		928.9		2,572.0		—			3,500.9
Investment in subsidiary	1,782.6		—		—		(1,782.6		)	—
Other assets	—		29.3		24.5		—			53.8
Total assets	$	1,782.7	$	1,956.7	$	5,610.1	$	(1,783.8	)	$	7,565.7
Liabilities and partners' capital
Current liabilities:
Accounts payable	$	—	$	132.6	$	19.0	$	—		$	151.6
Other current liabilities	1.6		39.5		86.1		(1.2		)	126.0
Total current liabilities	1.6		172.1		105.1		(1.2		)	277.6
Long-term liabilities:
Long-term debt, less current portion	354.2		—		1,518.9		—			1,873.1
Other long-term liabilities	25.1		17.2		16.7		—			59.0
Total long-term liabilities	379.3		17.2		1,535.6		—			1,932.1
Partners' capital	1,401.8		1,767.4		15.2		(1,782.6		)	1,401.8
Interest of non-controlling partners in subsidiary	—		—		3,954.2		—			3,954.2
Total partners' capital	1,401.8		1,767.4		3,969.4		(1,782.6		)	5,356.0
Total liabilities and partners' capital	$	1,782.7	$	1,956.7	$	5,610.1	$	(1,783.8	)	$	7,565.7

Condensed Consolidating Statements of Operations
Three Months Ended June 30, 2013
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Revenues:
Gathering and processing	$	—		$	—		$	71.1		$	—		$	71.1
NGL and crude services	—			38.1			—			—			38.1
Storage and transportation	—			1.1			9.0			(0.4		)	9.7
	—			39.2			80.1			(0.4		)	118.9
Cost of product/services sold (excluding depreciation, amortization and accretion as shown below):
Gathering and processing	—			—			14.0			—			14.0
NGL and crude services	—			36.5			0.2			—			36.7
Storage and transportation	—			0.6			1.1			(0.4		)	1.3
	—			37.1			15.3			(0.4		)	52.0
Expenses:
Operating and administrative	—			2.5			28.6			—			31.1
Depreciation, amortization and accretion	—			2.1			25.9			—			28.0
Operating income (loss)	—			(2.5		)	10.3			—			7.8
Other income (expense):
Interest and debt expense, net	0.5			—			(12.5		)	—			(12.0		)
Equity in net income of subsidiary	(5.0		)	—			—			5.0			—
Income (loss) before income taxes	(4.5		)	(2.5		)	(2.2		)	5.0			(4.2		)
Provision for income taxes	—			—			0.3			—			0.3
Net income (loss)	(4.5		)	(2.5		)	(2.5		)	5.0			(4.5		)
Net loss attributable to non-controlling partners in subsidiary	—			—			6.1			—			6.1
Net income (loss) attributable to partners	$	(4.5	)	$	(2.5	)	$	3.6		$	5.0		$	1.6

Condensed Consolidating Statements of Operations

Condensed Consolidating Statements of Operations
Three Months Ended June 30, 2013
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Revenues:
Gathering and processing	$	—		$	—		$	71.1		$	—		$	71.1
NGL and crude services	—			38.1			—			—			38.1
Storage and transportation	—			1.1			9.0			(0.4		)	9.7
	—			39.2			80.1			(0.4		)	118.9
Cost of product/services sold (excluding depreciation, amortization and accretion as shown below):
Gathering and processing	—			—			14.0			—			14.0
NGL and crude services	—			36.5			0.2			—			36.7
Storage and transportation	—			0.6			1.1			(0.4		)	1.3
	—			37.1			15.3			(0.4		)	52.0
Expenses:
Operating and administrative	—			2.5			28.6			—			31.1
Depreciation, amortization and accretion	—			2.1			25.9			—			28.0
Operating income (loss)	—			(2.5		)	10.3			—			7.8
Other income (expense):
Interest and debt expense, net	0.5			—			(12.5		)	—			(12.0		)
Equity in net income of subsidiary	(5.0		)	—			—			5.0			—
Income (loss) before income taxes	(4.5		)	(2.5		)	(2.2		)	5.0			(4.2		)
Provision for income taxes	—			—			0.3			—			0.3
Net income (loss)	(4.5		)	(2.5		)	(2.5		)	5.0			(4.5		)
Net loss attributable to non-controlling partners in subsidiary	—			—			6.1			—			6.1
Net income (loss) attributable to partners	$	(4.5	)	$	(2.5	)	$	3.6		$	5.0		$	1.6

Condensed Consolidating Statements of Operations
Six Months Ended June 30, 2013
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Revenues:
Gathering and processing	$	—		$	—		$	143.5		$	—		$	143.5
NGL and crude services	—			38.1			—			—			38.1
Storage and transportation	—			1.1			9.0			(0.4		)	9.7
	—			39.2			152.5			(0.4		)	191.3
Cost of product/services sold (excluding depreciation, amortization and accretion as shown below):
Gathering and processing	—			—			27.5			—			27.5
NGL and crude services	—			36.5			0.2			—			36.7
Storage and transportation	—			0.6			1.1			(0.4		)	1.3
	—			37.1			28.8			(0.4		)	65.5
Expenses:
Operating and administrative	—			2.5			49.4			—			51.9
Depreciation, amortization and accretion	—			2.1			48.3			—			50.4
Operating income (loss)	—			(2.5		)	26.0			—			23.5
Other income (expense):
Interest and debt expense, net	0.5			—			(23.9		)	—			(23.4		)
Equity in net income of subsidiary	(1.1		)	—			—			1.1			—
Income (loss) before income taxes	(0.6		)	(2.5		)	2.1			1.1			0.1
Provision for income taxes	—			—			0.7			—			0.7
Net income (loss)	(0.6		)	(2.5		)	1.4			1.1			(0.6		)
Net loss attributable to non-controlling partners in subsidiary	—			—			7.3			—			7.3
Net income (loss) attributable to partners	$	(0.6	)	$	(2.5	)	$	8.7		$	1.1		$	6.7

Condensed Consolidating Statements of Comprehensive Income

Condensed Consolidating Statements of Comprehensive Income
Three Months Ended June 30, 2013
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations		Consolidated
Net income (loss)	$	(4.5	)	$	(2.5	)	$	(2.5	)	$	5.0	$	(4.5	)
Change in Suburban Propane Partners LP units	(0.2		)	—			—			—		(0.2		)
Comprehensive income (loss)	$	(4.7	)	$	(2.5	)	$	(2.5	)	$	5.0	$	(4.7	)

Condensed Consolidating Statements of Comprehensive Income
Six Months Ended June 30, 2013
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries		Eliminations		Consolidated
Net income (loss)	$	(0.6	)	$	(2.5	)	$	1.4	$	1.1	$	(0.6	)
Change in Suburban Propane Partners LP units	(0.2		)	—			—		—		(0.2		)
Comprehensive income (loss)	$	(0.8	)	$	(2.5	)	$	1.4	$	1.1	$	(0.8	)

Condensed Consolidating Statements of Cash Flows

Condensed Consolidating Statements of Cash Flows
Six Months Ended June 30, 2013
(in millions)
	Parent		Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations		Consolidated
Cash flows from operating activities	$	—	$	(9.5	)	$	66.9		$	—	$	57.4
Cash flows from investing activities
Acquisitions, net of cash acquired	0.1		5.0			1.0			—		6.1
Purchases of property, plant and equipment	—		(0.5		)	(83.6		)	—		(84.1		)
Net cash provided by (used in) investing activities	0.1		4.5			(82.6		)	—		(78.0		)
Cash flows from financing activities:
Proceeds from the issuance of long-term debt	—		41.8			326.7			—		368.5
Principal payments on long-term debt	—		(21.5		)	(238.5		)	—		(260.0		)
Distributions paid	—		(11.8		)	(9.3		)	—		(21.1		)
Distributions paid to non-controlling partners	—		—			(177.4		)	—		(177.4		)
Net proceeds from the issuance of common units	—		—			118.5			—		118.5
Other	—		(2.2		)	(3.1		)	—		(5.3		)
Net cash provided by financing activities	—		6.3			16.9			—		23.2
Net increase in cash	0.1		1.3			1.2			—		2.6
Cash at beginning of period	—		—			0.1			—		0.1
Cash at end of period	$	0.1	$	1.3		$	1.3		$	—	$	2.7

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Fair Value Measurements (Assets And Liabilities Measured At Fair Value On Recurring Basis) (Detail) (USD $) In Millions, unless otherwise specified	Jun. 30, 2013
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets from price risk management	$ 15.3
SPH units	6.6
Total assets at fair value	21.9
Liabilities from price risk management	8.0
Interest rate swaps	5.1
Total liabilities at fair value	13.1
Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets from price risk management	0.1
SPH units	6.6
Total assets at fair value	6.7
Liabilities from price risk management	0.2
Interest rate swaps	0
Total liabilities at fair value	0.2
Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets from price risk management	21.1
SPH units	0
Total assets at fair value	21.1
Liabilities from price risk management	11.1
Interest rate swaps	5.1
Total liabilities at fair value	16.2
Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets from price risk management	0
SPH units	0
Total assets at fair value	0
Liabilities from price risk management	0
Interest rate swaps	0
Total liabilities at fair value	0
Total
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets from price risk management	21.2
SPH units	6.6
Total assets at fair value	27.8
Liabilities from price risk management	11.3
Interest rate swaps	5.1
Total liabilities at fair value	16.4
Designated as Hedges
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets from price risk management	0
SPH units	0
Total assets at fair value	0
Liabilities from price risk management	0
Interest rate swaps	0
Total liabilities at fair value	0
Not Designated as Hedges
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets from price risk management	21.2
SPH units	0
Total assets at fair value	21.2
Liabilities from price risk management	11.3
Interest rate swaps	0
Total liabilities at fair value	11.3
Netting Agreements
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets from price risk management	(5.9)	[1]
SPH units	0	[1]
Total assets at fair value	(5.9)	[1]
Liabilities from price risk management	(3.3)	[1]
Interest rate swaps	0	[1]
Total liabilities at fair value	$ (3.3)	[1]

[1] June 30, 2013 Fair Value of Derivatives Level 1 Level 2 Level 3 Total Designatedas Hedges NotDesignatedas Hedges NettingAgreements(a) TotalAssets Assets from price risk management$0.1 $21.1 $— $21.2 $— $21.2 $(5.9) $15.3SPH units6.6 — — 6.6 — — — 6.6Total assets at fair value$6.7 $21.1 $— $27.8 $— $21.2 $(5.9) $21.9 Liabilities Liabilities from price risk management$0.2 $11.1 $— $11.3 $— $11.3 $(3.3) $8.0Interest rate swaps— 5.1 — 5.1 — — — 5.1Total liabilities at fair value$0.2 $16.2 $— $16.4 $— $11.3 $(3.3) $13.1

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Commitments and Contingencies

6 Months Ended

Jun. 30, 2013

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Commitments and Contingencies

Purchase Commitments

Inergy periodically enters into agreements with suppliers to purchase fixed quantities of NGLs, distillates and natural gas at fixed prices. At June 30, 2013, the total of these firm purchase commitments was $179.0 million, 97.9% of which will occur over the course of the next twelve months. The Company also enters into non-binding agreements with suppliers to purchase quantities of NGLs, distillates and natural gas at variable prices at future dates at the then prevailing market prices.

Inergy and Inergy Midstream entered into certain purchase commitments in connection with the identified growth projects primarily related to the Watkins Glen NGL development project, the COLT Hub expansion project, and certain upgrades to the US Salt facility. The Watkins Glen NGL development project entails the conversion of certain caverns created by US Salt into 2.1 million barrels of NGL storage.  The COLT Hub expansion project primarily includes an expansion of receiving, storage, and take-away capacity via interconnecting pipelines, storage tanks, and rail facilities. At June 30, 2013, the total of Inergy's and Inergy Midstream's storage and transportation operations' firm purchase commitments was approximately $24.0 million. The gathering and processing segment also has purchase commitments of approximately $14.6 million related to other growth and maintenance contractual purchase obligations, as well as environmental obligations. The majority of the purchases associated with these commitments are expected to occur over the course of the next twelve months.

Capital Leases

The Company has auto leases, a compressor, and a treating facility that are accounted for as capital leases. The terms of the agreements vary from 2013 until 2016. Inergy's capital lease liabilities were $4.9 million and $7.0 million at June 30, 2013 and December 31, 2012, respectively, and are included in accrued expenses and other liabilities and other long-term liabilities on the consolidated balance sheets.

Legal Proceedings

Inergy is periodically involved in litigation proceedings. If Inergy determines that a negative outcome is probable and the amount of loss is reasonably estimable, then it accrues the estimated amount. The results of litigation proceedings cannot be predicted with certainty; however, management believes that Inergy does not have material potential liability in connection with these proceedings that would have a significant financial impact on its consolidated financial condition, results of operations or cash flows. However, Inergy could incur judgments, enter into settlements or revise its expectations regarding the outcome of certain matters, and such developments could have a material adverse effect on Inergy's results of operations or cash flows in the period in which the amounts are paid and/or accrued.

Any loss estimates are inherently subjective, based on currently available information, and are subject to management's judgment and various assumptions. Due to the inherently subjective nature of these estimates and the uncertainty and unpredictability surrounding the outcome of legal proceedings, actual results may differ materially from any amounts that have been accrued.

Five putative class action lawsuits challenging the Crestwood-Inergy merger have been filed, four in federal court in the United States District Court for the Southern District of Texas: (i) Abraham Knoll v. Robert G. Phillips, et al. (Case No. 4:13-cv-01528); (ii) Greg Podell v. Crestwood Midstream Partners, LP, et al. (Case No. 4:13-cv-01599); (iii) Johnny Cooper v. Crestwood Midstream Partners LP, et al. (Case No. 4:13-cv-01660); and (iv) Steven Elliot LLC v. Robert G. Phillips, et al. (Case No. 4:13-cv-01763), and one in Delaware Chancery Court, Hawley v. Crestwood Midstream Partners LP, et al. (Case No. 8689-VCL).  All of the cases name Crestwood, Crestwood Gas Services GP LLC, Crestwood Holdings LLC, the current and former directors of Crestwood Gas Services GP LLC, Inergy, L.P., Inergy Midstream, L.P., NRGM GP, LLC, and Intrepid Merger Sub, LLC as defendants.  All of the suits are brought by a purported holder of common units of Crestwood, both individually and on behalf of a putative class consisting of holders of common units of Crestwood.  The lawsuits generally allege, among other things, that the directors of Crestwood Gas Services GP LLC breached their fiduciary duties to holders of common units of Crestwood by agreeing to a transaction with inadequate consideration and unfair terms and pursuant to an inadequate process.  The lawsuits further allege that Inergy, L.P., Inergy Midstream, L.P., NRGM GP, LLC, and Intrepid Merger Sub, LLC aided and abetted the Crestwood directors in the alleged breach of their fiduciary duties.  The lawsuits seek, in general, (i) injunctive relief enjoining the merger, (ii) in the event the merger is consummated, rescission or an award of rescissory damages, (iii) an award of plaintiffs' costs, including reasonable attorneys' and experts' fees, (iv) the accounting by the defendants to the plaintiffs for all damages caused by the defendants, and (v) such further equitable relief as the court deems just and proper.  Certain of the actions also assert claims of inadequate disclosure under Sections 14(a) and 20(a) of the Securities Exchange Act of 1934, and the Elliot case also names Citigroup Global Markets Inc. as an alleged aider and abettor.  The plaintiff in the Hawley action in Delaware filed a motion for expedited proceedings but subsequently withdrew that motion and then filed a stipulation voluntarily dismissing the action without prejudice, which has been granted by the Court, such that the Hawley action has now been dismissed.  The plaintiffs in the Knoll, Podell, Cooper, and Elliot actions filed an unopposed motion to consolidate these four cases, which the Court granted.  The plaintiff in the Elliot action filed a motion for expedited discovery, which remains pending. These lawsuits are at a preliminary stage. Crestwood, Inergy Midstream and the other defendants believe that these lawsuits are without merit and intend to defend against them vigorously.

In June 2010, Inergy Midstream and CNYOG entered into a letter of intent with Anadarko Petroleum Corporation (“Anadarko”) which contemplated that, subject to certain conditions, Anadarko may exercise an option to acquire up to a 25% ownership interest in the MARC I pipeline. On September 23, 2011, Anadarko filed a complaint against the Company and CNYOG in the Court of Common Pleas in Lycoming County, Pennsylvania (Cause No. 11-01697) alleging that (i) Anadarko had an option to acquire, and timely exercised its option to acquire, a 25% ownership interest in the MARC I pipeline, (ii) the Company refused to enter into definitive agreements under which Anadarko would acquire a 25% interest in the pipeline and, by doing so, the Company breached the letter of intent, and (iii) by refusing to enter into definitive agreements, the Company breached a duty of good faith and fair dealing in connection with the letter of intent. Based on these allegations, Anadarko seeks various remedies, including specific performance of the letter of intent and monetary damages. 

The Company filed its answer to Anadarko's complaint on January 17, 2012 and discovery is ongoing. The Company believes that Anadarko's claims are without merit and intends to vigorously defend themselves in the lawsuit. Because this litigation is in the early stages of the proceedings, the Company is unable to estimate a reasonably possible loss or range of loss in this matter. Moreover, the Company believes that it has meritorious defenses that it intends to assert.

Regulatory Compliance

In the ordinary course of our business, Inergy is subject to various laws and regulations. In the opinion of Inergy's management, compliance with current laws and regulations will not have a material effect on its results of operations, cash flows or financial condition.

Environmental Compliance

Inergy's operations are subject to stringent and complex laws and regulations pertaining to health, safety, and the environment. Inergy is subject to laws and regulations at the federal, state and local levels that relate to air and water quality, hazardous and solid waste management and disposal and other environmental matters. The cost of planning, designing, constructing and operating Inergy's facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures. At June 30, 2013, Inergy had accrued approximately $0.3 million for environmental matters, which was based on Inergy's undiscounted estimate of amounts it will spend on environmental compliance and remediation. Inergy estimates that its potential liability for reasonably possible outcomes related to its environmental exposures could range from approximately $0.3 million to $0.4 million. Inergy had $0.2 million accrued for environmental matters at December 31, 2012.

Self-Insurance

Inergy utilizes third-party insurance subject to varying retention levels of self-insurance, which management considers prudent. Such self-insurance relates to losses and liabilities primarily associated with medical claims, workers' compensation claims and general, product, vehicle and environmental liability. Losses are accrued based upon management's estimates of the aggregate liability for claims incurred using certain assumptions followed in the insurance industry and based on past experience. The primary assumption utilized is actuarially determined loss development factors. The loss development factors are based primarily on historical data. Inergy's self insurance reserves could be affected if future claim developments differ from the historical trends. Inergy believes changes in health care costs, trends in health care claims of its employee base, accident frequency and severity and other factors could materially affect the estimate for these liabilities. Inergy continually monitors changes in employee demographics, incident and claim type and evaluates its insurance accruals and adjusts its accruals based on its evaluation of these qualitative data points. Inergy is liable for the development of claims for its disposed retail propane operations, provided they were reported prior to August 1, 2012. At June 30, 2013, Inergy's self-insurance reserves were $19.9 million. The Company estimates that $17.2 million of this balance will be paid subsequent to June 30, 2014. As such, $17.2 million has been classified in other long-term liabilities on the consolidated balance sheets. There were no self-insurance reserves at December 31, 2012.

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Fair Value Measurements

6 Months Ended

Jun. 30, 2013

Fair Value, Assets and Liabilities Measured on Recurring Basis [Abstract]

Fair Value Measurements

Fair Value Measurements

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

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

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

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

As of June 30, 2013, the Company held certain assets and liabilities that are required to be measured at fair value on a recurring basis. These included the Company’s derivative instruments related to heating oil, crude oil, NGLs and interest rates. The Company’s derivative instruments consist of forwards, swaps, futures, physical exchanges and options.

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

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

The Company’s OTC options are valued based on the Black Scholes option pricing model that considers time value and volatility of the underlying commodity. The inputs utilized in the model are based on publicly available information as well as broker quotes. These options have been categorized as level 2.

The assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company's assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

The following tables set forth by level within the fair value hierarchy the Company's assets and liabilities that were accounted for at fair value on a recurring basis at June 30, 2013 (in millions):

	June 30, 2013
	Fair Value of Derivatives
	Level 1		Level 2		Level 3		Total		Designated as Hedges		Not Designated as Hedges		Netting Agreements(a)			Total
Assets
Assets from price risk management	$	0.1	$	21.1	$	—	$	21.2	$	—	$	21.2	$	(5.9	)	$	15.3
SPH units	6.6		—		—		6.6		—		—		—			6.6
Total assets at fair value	$	6.7	$	21.1	$	—	$	27.8	$	—	$	21.2	$	(5.9	)	$	21.9
Liabilities
Liabilities from price risk management	$	0.2	$	11.1	$	—	$	11.3	$	—	$	11.3	$	(3.3	)	$	8.0
Interest rate swaps	—		5.1		—		5.1		—		—		—			5.1
Total liabilities at fair value	$	0.2	$	16.2	$	—	$	16.4	$	—	$	11.3	$	(3.3	)	$	13.1

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

The Company had no assets or liabilities recorded at fair value at December 31, 2012.

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Consolidated Statements of Cash Flows (USD $) In Millions, unless otherwise specified	6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012
Operating activities
Net income (loss)	$ (0.6)	$ 12.8
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and depletion	31.6	23.0
Amortization and accretion	18.8	12.0
Amortization of deferred financing costs	2.2	2.5
Amortization of bond premium	(0.1)	0
Market adjustment on interest rate swaps	(0.9)	0
Gain on contingent consideration	0	(6.8)
Unit-based compensation charges	2.0	1.0
Provision for doubtful accounts	0.1	0
Changes in operating assets and liabilities, net of effects from acquisitions:
Accounts receivable	(3.7)	4.2
Inventory	(4.7)	0
Prepaid expenses and other current assets	0	(0.5)
Accounts payable, accrued expenses and other liabilities	12.7	(6.0)
Net cash provided by operating activities	57.4	42.2
Investing activities
Acquisitions, net of cash acquired	6.1	(376.8)
Purchases of property, plant and equipment	(84.1)	(22.4)
Net cash used in investing activities	(78.0)	(399.2)
Financing activities
Proceeds from the issuance of long-term debt	41.8	0
Principal payments on long-term debt	(21.5)	0
Contributions from partners	0	247.2
Distributions	(21.1)	(6.1)
Distributions paid to non-controlling partners	(48.4)	(39.4)
Distributions for additional interest in Crestwood Marcellus Midstream LLC	(129.0)	0
Payments on capital leases	(2.2)	(1.4)
Payments for deferred financing costs	(0.1)	(6.5)
Net proceeds from issuance of Crestwood Midstream Partners LP common units	118.5	103.0
Taxes paid for unit-based compensation vesting	(3.0)	(0.4)
Net cash provided by financing activities	23.2	364.9
Net increase in cash	2.6	7.9
Cash at beginning of period	0.1	0.8
Cash at end of period	2.7	8.7
Supplemental schedule of noncash investing and financing activities
Net change to property, plant and equipment through accounts payable and accrued expenses	25.9	1.1
Acquisitions, net of cash acquired:
Current assets	216.6	0
Property, plant and equipment	2,554.9	95.1
Intangible assets	273.0	312.4
Goodwill	2,100.1	0
Other assets	51.2	0
Current liabilities	(205.5)	(12.7)
Debt	(1,079.3)	(18.0)
Invested capital of Inergy, L.P., net of debt (Note 4)	(3,873.2)	0
Other liabilities	(43.9)	0
Total acquisitions, net of cash acquired	(6.1)	376.8
Inergy Midstream
Financing activities
Proceeds from the issuance of long-term debt	9.8	0
Principal payments on long-term debt	(15.5)	0
CMLP
Financing activities
Proceeds from the issuance of long-term debt	247.5	223.7
Principal payments on long-term debt	(154.0)	(174.7)
Crestwood Marcellus Midstream LLC
Financing activities
Proceeds from the issuance of long-term debt	69.4	21.0
Principal payments on long-term debt	(69.0)	(1.5)
Contributions from partners	$ (3,873.2)

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Condensed Consolidating Financial Information (Condensed Consolidating Statements Of Operations) (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Revenues:
Gathering and processing	$ 71.1	$ 55.2	$ 143.5	$ 109.0
Total revenue	118.9	55.2	191.3	109.0
Cost of product/services sold (excluding depreciation, amortization and accretion as shown below):
Gathering and processing	14.0	7.4	27.5	16.4
Total cost of product sold	52.0	7.4	65.5	16.4
Expenses:
Operating and administrative	31.1	18.0	51.9	34.5
Depreciation, amortization and accretion	28.0	19.1	50.4	35.0
Total Expenses	59.1	37.1	102.3	69.5
Gain on contingent consideration	0	6.8	0	6.8
Operating income	7.8	17.5	23.5	29.9
Other income (expense):
Income (loss) before income taxes	(4.2)	8.6	0.1	13.4
Provision for income taxes	0.3	0.3	0.7	0.6
Net income (loss)	(4.5)	8.3	(0.6)	12.8
Net income attributable to non-controlling partners in subsidiary	6.1	(4.9)	7.3	(6.1)
Net income attributable to Inergy, L.P.	1.6	3.4	6.7	6.7
Parent Company
Revenues:
Gathering and processing	0		0
Marketing, supply and logistics	0		0
Storage and transportation	0		0
Total revenue	0		0
Cost of product/services sold (excluding depreciation, amortization and accretion as shown below):
Gathering and processing	0		0
Marketing, supply and logistics	0		0
Storage and transportation	0		0
Total cost of product sold	0		0
Expenses:
Operating and administrative	0		0
Depreciation, amortization and accretion	0		0
Operating income	0		0
Other income (expense):
Interest expense, net	(0.5)		(0.5)
Equity in net income of subsidiary	(5.0)		(1.1)
Income (loss) before income taxes	(4.5)		(0.6)
Provision for income taxes	0		0
Net income (loss)	(4.5)		(0.6)
Net income attributable to non-controlling partners in subsidiary	0		0
Net income attributable to Inergy, L.P.	(4.5)		(0.6)
Guarantor Subsidiaries
Revenues:
Gathering and processing	0		0
Marketing, supply and logistics	38.1		38.1
Storage and transportation	1.1		1.1
Total revenue	39.2		39.2
Cost of product/services sold (excluding depreciation, amortization and accretion as shown below):
Gathering and processing	0		0
Marketing, supply and logistics	36.5		36.5
Storage and transportation	0.6		0.6
Total cost of product sold	37.1		37.1
Expenses:
Operating and administrative	2.5		2.5
Depreciation, amortization and accretion	2.1		2.1
Operating income	(2.5)		(2.5)
Other income (expense):
Interest expense, net	0		0
Equity in net income of subsidiary	0		0
Income (loss) before income taxes	(2.5)		(2.5)
Provision for income taxes	0		0
Net income (loss)	(2.5)		(2.5)
Net income attributable to non-controlling partners in subsidiary	0		0
Net income attributable to Inergy, L.P.	(2.5)		(2.5)
Non-Guarantor Subsidiaries
Revenues:
Gathering and processing	71.1		143.5
Marketing, supply and logistics	0		0
Storage and transportation	9.0		9.0
Total revenue	80.1		152.5
Cost of product/services sold (excluding depreciation, amortization and accretion as shown below):
Gathering and processing	14.0		27.5
Marketing, supply and logistics	0.2		0.2
Storage and transportation	1.1		1.1
Total cost of product sold	15.3		28.8
Expenses:
Operating and administrative	28.6		49.4
Depreciation, amortization and accretion	25.9		48.3
Operating income	10.3		26.0
Other income (expense):
Interest expense, net	12.5		23.9
Equity in net income of subsidiary	0		0
Income (loss) before income taxes	(2.2)		2.1
Provision for income taxes	0.3		0.7
Net income (loss)	(2.5)		1.4
Net income attributable to non-controlling partners in subsidiary	6.1		7.3
Net income attributable to Inergy, L.P.	3.6		8.7
Consolidation, Eliminations
Revenues:
Gathering and processing	0		0
Marketing, supply and logistics	0		0
Storage and transportation	(0.4)		(0.4)
Total revenue	(0.4)		(0.4)
Cost of product/services sold (excluding depreciation, amortization and accretion as shown below):
Gathering and processing	0		0
Marketing, supply and logistics	0		0
Storage and transportation	(0.4)		(0.4)
Total cost of product sold	(0.4)		(0.4)
Expenses:
Operating and administrative	0		0
Depreciation, amortization and accretion	0		0
Operating income	0		0
Other income (expense):
Interest expense, net	0		0
Equity in net income of subsidiary	5.0		1.1
Income (loss) before income taxes	5.0		1.1
Provision for income taxes	0		0
Net income (loss)	5.0		1.1
Net income attributable to non-controlling partners in subsidiary	0		0
Net income attributable to Inergy, L.P.	5.0		1.1
Consolidated Entities
Revenues:
Gathering and processing	71.1		143.5
Marketing, supply and logistics	38.1		38.1
Storage and transportation	9.7		9.7
Total revenue	118.9		191.3
Cost of product/services sold (excluding depreciation, amortization and accretion as shown below):
Gathering and processing	14.0		27.5
Marketing, supply and logistics	36.7		36.7
Storage and transportation	1.3		1.3
Total cost of product sold	52.0		65.5
Expenses:
Operating and administrative	31.1		51.9
Depreciation, amortization and accretion	28.0		50.4
Operating income	7.8		23.5
Other income (expense):
Interest expense, net	12.0		23.4
Equity in net income of subsidiary	0		0
Income (loss) before income taxes	(4.2)		0.1
Provision for income taxes	0.3		0.7
Net income (loss)	(4.5)		(0.6)
Net income attributable to non-controlling partners in subsidiary	6.1		7.3
Net income attributable to Inergy, L.P.	$ 1.6		$ 6.7

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Partners' Capital (Narrative) (Detail) (USD $) In Millions, except Share data, unless otherwise specified	0 Months Ended				6 Months Ended	3 Months Ended		6 Months Ended				0 Months Ended	6 Months Ended	1 Months Ended	3 Months Ended	0 Months Ended
	Apr. 05, 2013	Apr. 05, 2013 CMLP	Mar. 22, 2013 CMLP	Aug. 09, 2013 CMLP Cash distribution	Jun. 30, 2013 Inergy Midstream	Jun. 30, 2013 Limited Partner [Member]	Jun. 30, 2012 Limited Partner [Member]	Jun. 30, 2013 Limited Partner [Member]	Jun. 30, 2012 Limited Partner [Member]	Jun. 30, 2013 Class C Units	Mar. 31, 2013 Class C Units	Jun. 05, 2013 Class D Units	Jun. 30, 2013 Class D Units	Jan. 31, 2013 Class D Units CMLP	Mar. 31, 2013 Class D Units CMLP	Jun. 18, 2013 Subsequent Event	Apr. 26, 2013 Subsequent Event	Apr. 26, 2013 Subsequent Event Cash distribution	Apr. 26, 2013 Subsequent Event Inergy Midstream Cash distribution	Jun. 18, 2013 Subsequent Event Inergy Midstream Unit Distribution	Apr. 26, 2013 Subsequent Event Inergy Cash distribution
Distribution Made to Member or Limited Partner [Line Items]
Units sold in public offering			4,500,000
Price per unit, gross			23.90
Price per unit, net			23.00
Net proceeds from public offering		$ 15.5	$ 103.5		$ 118.5					$ 0			$ 0
Convertible Units, Units Issued upon Conversion											1
Undewriters option for additional units	675,000
Distribution Made to Member or Limited Partner, Share Distribution														6,190,469	151,238
Distribution Made to Member or Limited Partner, Cash Distributions Paid						27.4	18.2	48.4	36.1
General partner ownership percentage														65.00%
Declared distribution date																	Jul. 25, 2013
Distribution declared per unit				$ 0.51														$ 0.3025	$ 0.1725		$ 0.130
Distribution Made to Member or Limited Partner, Cash Distributions Declared				$ 27.5
Distribution Made to Member or Limited Partner, Distribution Date																		Aug. 14, 2013
Record Date																		Aug. 07, 2013
Distribution Made to Limited Partner, Unit Distribution, Per Unit																0.432052
Distribution Made to Limited Partner, Unit Distribution												21,588								56,400,000

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Summary of Significant Accounting Policies (Estimated Useful Lives Of Property, Plant And Equipment) (Detail)	6 Months Ended
	Jun. 30, 2013
Processing plants and compression facilities | Minimum
Property, Plant and Equipment [Line Items]
Property, plant and equipment, useful life	20 years
Processing plants and compression facilities | Maximum
Property, Plant and Equipment [Line Items]
Property, plant and equipment, useful life	25 years
Gathering systems | Minimum
Property, Plant and Equipment [Line Items]
Property, plant and equipment, useful life	20 years
Gathering systems | Maximum
Property, Plant and Equipment [Line Items]
Property, plant and equipment, useful life	20 years
Building and improvements | Minimum
Property, Plant and Equipment [Line Items]
Property, plant and equipment, useful life	20 years
Building and improvements | Maximum
Property, Plant and Equipment [Line Items]
Property, plant and equipment, useful life	70 years
Office furniture and equipment | Minimum
Property, Plant and Equipment [Line Items]
Property, plant and equipment, useful life	5 years
Office furniture and equipment | Maximum
Property, Plant and Equipment [Line Items]
Property, plant and equipment, useful life	10 years
Vehicles | Minimum
Property, Plant and Equipment [Line Items]
Property, plant and equipment, useful life	5 years
Vehicles | Maximum
Property, Plant and Equipment [Line Items]
Property, plant and equipment, useful life	5 years
Pipelines | Minimum
Property, Plant and Equipment [Line Items]
Property, plant and equipment, useful life	20 years
Pipelines | Maximum
Property, Plant and Equipment [Line Items]
Property, plant and equipment, useful life	20 years
Base gas
Property, Plant and Equipment [Line Items]
Property, plant and equipment, useful life	10 years

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Condensed Consolidating Financial Information

6 Months Ended

Jun. 30, 2013

Text Block [Abstract]

Condensed Consolidating Financial Information

Condensed Consolidating Financial Information

Inergy is a holding company and owns no operating assets and has no significant operations independent of its subsidiaries. Obligations under its outstanding senior notes and credit agreement listed in Note 7 are jointly and severally guaranteed by Inergy's wholly owned domestic subsidiaries. NRGM and CMLP and each of their wholly owned subsidiaries do not guarantee Inergy's senior notes or credit agreement.

As discussed in Note 1, the accounting for Inergy's acquisition of CMLP GP results in the historical Inergy operations being acquired on June 19, 2013. Inergy's senior notes are thus not included in the financial statements prior to June 19, 2013. CMLP GP (the accounting predecessor) does not guarantee any debt. Therefore, the condensed consolidated financial statements do not include 2012 financial information.

The tables below present condensed consolidated financial statements for Inergy (parent) on a stand-alone, unconsolidated basis, and its combined guarantor and combined non-guarantor subsidiaries as of June 30, 2013 and for the three-month and six-month periods endedJune 30, 2013. The financial information may not necessarily be indicative of the results of operations, cash flows or financial position had the subsidiaries operated as independent entities.

Condensed Consolidating Balance Sheet
June 30, 2013
(in millions)
	Parent		Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	0.1	$	1.3	$	1.3	$	—		$	2.7
Accounts receivable	—		111.7		70.7		—			182.4
Inventories	—		47.6		5.6		—			53.2
Other current assets	—		21.2		24.5		(1.2		)	44.5
Total current assets	0.1		181.8		102.1		(1.2		)	282.8
Property, plant and equipment, net	—		816.7		2,911.5		—			3,728.2
Goodwill and intangible assets, net	—		928.9		2,572.0		—			3,500.9
Investment in subsidiary	1,782.6		—		—		(1,782.6		)	—
Other assets	—		29.3		24.5		—			53.8
Total assets	$	1,782.7	$	1,956.7	$	5,610.1	$	(1,783.8	)	$	7,565.7
Liabilities and partners' capital
Current liabilities:
Accounts payable	$	—	$	132.6	$	19.0	$	—		$	151.6
Other current liabilities	1.6		39.5		86.1		(1.2		)	126.0
Total current liabilities	1.6		172.1		105.1		(1.2		)	277.6
Long-term liabilities:
Long-term debt, less current portion	354.2		—		1,518.9		—			1,873.1
Other long-term liabilities	25.1		17.2		16.7		—			59.0
Total long-term liabilities	379.3		17.2		1,535.6		—			1,932.1
Partners' capital	1,401.8		1,767.4		15.2		(1,782.6		)	1,401.8
Interest of non-controlling partners in subsidiary	—		—		3,954.2		—			3,954.2
Total partners' capital	1,401.8		1,767.4		3,969.4		(1,782.6		)	5,356.0
Total liabilities and partners' capital	$	1,782.7	$	1,956.7	$	5,610.1	$	(1,783.8	)	$	7,565.7

Condensed Consolidating Statements of Operations
Three Months Ended June 30, 2013
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Revenues:
Gathering and processing	$	—		$	—		$	71.1		$	—		$	71.1
NGL and crude services	—			38.1			—			—			38.1
Storage and transportation	—			1.1			9.0			(0.4		)	9.7
	—			39.2			80.1			(0.4		)	118.9
Cost of product/services sold (excluding depreciation, amortization and accretion as shown below):
Gathering and processing	—			—			14.0			—			14.0
NGL and crude services	—			36.5			0.2			—			36.7
Storage and transportation	—			0.6			1.1			(0.4		)	1.3
	—			37.1			15.3			(0.4		)	52.0
Expenses:
Operating and administrative	—			2.5			28.6			—			31.1
Depreciation, amortization and accretion	—			2.1			25.9			—			28.0
Operating income (loss)	—			(2.5		)	10.3			—			7.8
Other income (expense):
Interest and debt expense, net	0.5			—			(12.5		)	—			(12.0		)
Equity in net income of subsidiary	(5.0		)	—			—			5.0			—
Income (loss) before income taxes	(4.5		)	(2.5		)	(2.2		)	5.0			(4.2		)
Provision for income taxes	—			—			0.3			—			0.3
Net income (loss)	(4.5		)	(2.5		)	(2.5		)	5.0			(4.5		)
Net loss attributable to non-controlling partners in subsidiary	—			—			6.1			—			6.1
Net income (loss) attributable to partners	$	(4.5	)	$	(2.5	)	$	3.6		$	5.0		$	1.6

Condensed Consolidating Statements of Operations
Six Months Ended June 30, 2013
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Revenues:
Gathering and processing	$	—		$	—		$	143.5		$	—		$	143.5
NGL and crude services	—			38.1			—			—			38.1
Storage and transportation	—			1.1			9.0			(0.4		)	9.7
	—			39.2			152.5			(0.4		)	191.3
Cost of product/services sold (excluding depreciation, amortization and accretion as shown below):
Gathering and processing	—			—			27.5			—			27.5
NGL and crude services	—			36.5			0.2			—			36.7
Storage and transportation	—			0.6			1.1			(0.4		)	1.3
	—			37.1			28.8			(0.4		)	65.5
Expenses:
Operating and administrative	—			2.5			49.4			—			51.9
Depreciation, amortization and accretion	—			2.1			48.3			—			50.4
Operating income (loss)	—			(2.5		)	26.0			—			23.5
Other income (expense):
Interest and debt expense, net	0.5			—			(23.9		)	—			(23.4		)
Equity in net income of subsidiary	(1.1		)	—			—			1.1			—
Income (loss) before income taxes	(0.6		)	(2.5		)	2.1			1.1			0.1
Provision for income taxes	—			—			0.7			—			0.7
Net income (loss)	(0.6		)	(2.5		)	1.4			1.1			(0.6		)
Net loss attributable to non-controlling partners in subsidiary	—			—			7.3			—			7.3
Net income (loss) attributable to partners	$	(0.6	)	$	(2.5	)	$	8.7		$	1.1		$	6.7

Condensed Consolidating Statements of Comprehensive Income
Three Months Ended June 30, 2013
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations		Consolidated
Net income (loss)	$	(4.5	)	$	(2.5	)	$	(2.5	)	$	5.0	$	(4.5	)
Change in Suburban Propane Partners LP units	(0.2		)	—			—			—		(0.2		)
Comprehensive income (loss)	$	(4.7	)	$	(2.5	)	$	(2.5	)	$	5.0	$	(4.7	)

Condensed Consolidating Statements of Comprehensive Income
Six Months Ended June 30, 2013
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries		Eliminations		Consolidated
Net income (loss)	$	(0.6	)	$	(2.5	)	$	1.4	$	1.1	$	(0.6	)
Change in Suburban Propane Partners LP units	(0.2		)	—			—		—		(0.2		)
Comprehensive income (loss)	$	(0.8	)	$	(2.5	)	$	1.4	$	1.1	$	(0.8	)

Condensed Consolidating Statements of Cash Flows
Six Months Ended June 30, 2013
(in millions)
	Parent		Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations		Consolidated
Cash flows from operating activities	$	—	$	(9.5	)	$	66.9		$	—	$	57.4
Cash flows from investing activities
Acquisitions, net of cash acquired	0.1		5.0			1.0			—		6.1
Purchases of property, plant and equipment	—		(0.5		)	(83.6		)	—		(84.1		)
Net cash provided by (used in) investing activities	0.1		4.5			(82.6		)	—		(78.0		)
Cash flows from financing activities:
Proceeds from the issuance of long-term debt	—		41.8			326.7			—		368.5
Principal payments on long-term debt	—		(21.5		)	(238.5		)	—		(260.0		)
Distributions paid	—		(11.8		)	(9.3		)	—		(21.1		)
Distributions paid to non-controlling partners	—		—			(177.4		)	—		(177.4		)
Net proceeds from the issuance of common units	—		—			118.5			—		118.5
Other	—		(2.2		)	(3.1		)	—		(5.3		)
Net cash provided by financing activities	—		6.3			16.9			—		23.2
Net increase in cash	0.1		1.3			1.2			—		2.6
Cash at beginning of period	—		—			0.1			—		0.1
Cash at end of period	$	0.1	$	1.3		$	1.3		$	—	$	2.7

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Partners' Capital

6 Months Ended

Jun. 30, 2013

Partners' Capital Account, Distributions [Abstract]

Partners' Capital

Partners’ Capital

Common Unit Offering

On March 22, 2013, CMLP completed a public offering of 4,500,000 common units, representing limited partner interests in CMLP at a price of $23.90 per common unit ($23.00 per common unit, net of underwriting discounts) providing net proceeds of approximately $103.5 million. CMLP granted the underwriters a 30 day option to purchase up to 675,000 additional common units if the underwriters sold more than 4,500,000 common units in the offering. The underwriters exercised this option on April 5, 2013, providing net proceeds of approximately $15.5 million. The net proceeds from these transactions were used to reduce indebtedness under each of the CMM and CMLP Credit Facilities.

Limited Partner Unit Issuances

On April 1, 2013, CMLP's outstanding Class C units converted to common units on a one-for-one basis. Prior to the conversion of CMLP's Class C units to common, CMLP had the option to pay distributions to our Class C unitholders with cash or by issuing additional Paid-in-Kind Class C units, based upon the volume weighted-average price of CMLP's common units for the 10 trading days immediately preceding the date the distribution was declared. The unitholders of the converted units received a quarterly cash distribution for the period ended March 31, 2013 although the Class C units were not converted until April 1, 2013.

In January 2013, CMLP issued 6,190,469 Class D units, representing limited partner interests, to Crestwood Holdings in connection with its acquisition of Crestwood Holdings' 65% interest in CMM. The Class D units are similar in certain respects to CMLP's common units and Class C units, except that CMLP has the option to pay distributions to its Class D unitholders with cash or by issuing additional Paid-in-Kind Class D units based on the volume weighted-average price of CMLP's common units for the 10 trading days immediately preceding the date the distribution is declared. CMLP issued 151,238 additional Class D units in lieu of paying cash quarterly distributions on CMLP's Class D units attributable to the three months ended March 31, 2013. In March 2014, CMLP's outstanding Class D units will convert to common units.

Quarterly Distributions of Available Cash

CMLP paid cash distributions to its common unitholders of $27.4 million and $48.4 million during the three and six months ended June 30, 2013, and $18.2 million and $36.1 million during the three and six months ended June 30, 2012. CMLP also declared a $0.51 per common unit cash distribution payable on August 9, 2013, which is estimated to be $27.5 million.

On July 25, 2013, Inergy declared a distribution of $0.130 per limited partner unit to be paid on August 14, 2013, to unitholders of record on August 7, 2013 with respect to the second calendar quarter of 2013. On June 18, 2013, Inergy completed the pro rata distribution to its unitholders of approximately 56.4 million common units of Inergy Midstream at a distribution rate of 0.432052 NRGM unit for each Inergy limited partner unit owned on the record date. As a result, Inergy’s quarterly cash distribution of $0.130 reflects the NRGM unit distribution. Inergy investors who received, and continue to own through August 7, 2013, NRGM common units distributed by Inergy will receive total quarterly cash distributions of $0.3025 per Inergy unit, consisting of the $0.130 per unit to be paid directly by Inergy and approximately $0.1725 per Inergy unit to be paid by NRGM, based upon NRGM’s declared quarterly distribution of $0.40 per NRGM common unit.

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Summary of Significant Accounting Policies (Tables)

6 Months Ended

Jun. 30, 2013

Text Block [Abstract]

Estimated Useful Lives Of Property, Plant And Equipment

Depreciation is computed by the straight-line method over the estimated useful lives of the assets, as follows:

	Years
Gathering systems	20
Processing plants and compression facilities	20 – 25
Buildings, rights-of-way, easements and storage rights	20 – 70
Office furniture and equipment	5 – 10
Vehicles	5
Pipelines	20
Base gas	10

Schedule of Carrying and Fair Values of Senior Notes [Table Text Block]

The following table reflects the carrying value and fair value of the senior notes (in millions):

	June 30, 2013				December 31, 2012
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Inergy senior unsecured notes	$	11.5	$	11.8	$	—	$	—
CMLP senior notes	$	351.3	$	362.5	$	351.5	$	365.9
NRGM senior unsecured notes	$	500.0	$	494.7	$	—	$	—

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Subsequent Events

6 Months Ended

Jun. 30, 2013

Subsequent Events [Abstract]

Subsequent Events

Subsequent Events

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

On July 25, 2013, Inergy declared a distribution of $0.130 per limited partner unit to be paid on August 14, 2013, to unitholders of record on August 7, 2013. On June 18, 2013, Inergy completed the pro rata distribution to its unitholders of approximately 56.4 million common units of Inergy Midstream at a distribution rate of 0.432052 NRGM unit for each Inergy limited partner unit owned on the record date. As a result, Inergy’s quarterly cash distribution of $0.130 reflects the NRGM unit distribution. Inergy investors who received, and continue to own through August 7, 2013, NRGM common units distributed by Inergy will receive total quarterly cash distributions of $0.3025 per Inergy unit, consisting of the $0.130 per unit to be paid directly by Inergy and approximately $0.1725 per Inergy unit to be paid by NRGM, based upon NRGM’s declared quarterly distribution of $0.40 per NRGM common unit.

On June 24, 2013, Crestwood Niobrara LLC, CMLP's consolidated subsidiary, entered into an agreement with RKI Exploration and Production LLC (RKI), an affiliate of CMLP GP, to purchase RKI's 50% interest in a gathering system located in the Powder River Basin Niobrara play for approximately $108 million. This acquisition closed on July 19, 2013, and was funded through CMLP's contribution of approximately $27 million to Crestwood Niobrara (which was borrowed under the CMLP Credit Facility) and an additional $81 million was obtained through Crestwood Niobrara's issuance of a preferred interest to a subsidiary of General Electric Capital Corporation and GE Structured Finance, Inc. (collectively, GE EFS).

Crestwood Niobrara will fund 75% of future capital contributions to the gathering system joint venture through additional preferred interest issuances to GE EFS (up to a maximum of $69 million), with the remainder to be funded through CMLP's capital contributions to Crestwood Niobrara. CMLP serves as the managing member of Crestwood Niobrara and CMLP has the ability to redeem GE EFS's preferred security in either cash or CMLP common units, subject to certain restrictions.

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Document and Entity Information	6 Months Ended
	Jun. 30, 2013
Entity Information [Line Items]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2013
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	Q2
Trading Symbol	NRGY
Entity Registrant Name	INERGY L P
Entity Central Index Key	0001136352
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding	0

XML

Summary of Significant Accounting Policies (Policies)

6 Months Ended

Jun. 30, 2013

Text Block [Abstract]

Financial Instruments and Price Risk Management

Financial Instruments and Price Risk Management

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

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

Inergy had no derivatives identified as fair value hedges for accounting purposes in the three-month and six-month periods endedJune 30, 2012 and 2013.

Inergy also enters into derivative financial instruments that may qualify as cash flow hedges, which hedge the exposure of variability in expected future cash flows predominantly attributable to variable interest payments. These derivatives are recorded on the balance sheet at fair value as other assets or other long-term 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. In certain situations under the rules, the ineffective portion of the gain or loss is recognized as cost of product sold/services sold or interest expense in the current period. Inergy did not have any derivatives identified as cash flow hedges in the three and six-month periods ended June 30, 2012 and 2013.

Accumulated other comprehensive loss was $0.2 million at June 30, 2013. Included in accumulated other comprehensive loss at June 30, 2013 was a loss of $0.2 million attributable to Suburban Propane Partners, LP ("SPH") units. The SPH units were acquired by Inergy in August 2012 in conjunction with the disposition of its retail propane business.

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

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

Revenue Recognition

Revenue Recognition

Inergy's gathering and processing operations gather, process, treat, compress, transport and sell natural gas pursuant to fixed-fee and percent-of-proceeds contracts. For fixed-fee contracts, Inergy recognizes revenues based on the volume of natural gas gathered, processed and treated or compressed. For percent-of-proceeds contracts, Inergy recognizes revenues based on the value of products sold to third parties. Inergy recognizes revenues for these services and products when all of the following criteria are met:

• services have been rendered or products delivered;

• persuasive evidence of an exchange arrangement exists;

• the price for services is fixed or determinable; and

• collectability is reasonably assured.

Sales of NGLs and salt are recognized at the time product is shipped or delivered to the customer depending on the sales terms. NGL processing and fractionation fees are recognized upon delivery of the product. Revenues from the COLT Hub are recognized when the contractual services are provided, such as loading of customer rail cars. Revenues from storage and transportation contracts are recognized during the period in which the storage and transportation services are provided, such as providing storage and transportation services during the period a firm service contract is in place.

Use of Estimates

Use of Estimates

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

Inventories

Inventory

Inventory for NGL and crude services operations, which mainly consist of NGLs, are stated at the lower of cost or market and are computed using the average cost method. Inventory for storage and transportation operations are stated at the lower of cost or market and are computed predominantly using the average cost method. Inergy had no inventory at December 31, 2012.

Shipping and Handling Costs

Shipping and Handling Costs

Shipping and handling costs are recorded as part of cost of product/services sold at the time product is shipped or delivered to the customer.

Property, Plant and Equipment

Accrued Additions to Property, Plant and Equipment

The Company has accrued for property, plant and equipment, including certain construction work in process relating to construction efforts on various growth projects. At June 30, 2013 and December 31, 2012, the Company had accrued $45.1 million and $9.2 million relating to property, plant and equipment classified as accrued expenses on the consolidated balance sheets.

Property, Plant and Equipment

Property, plant and equipment is recorded at its original cost of construction or, upon acquisition, at fair value of the assets acquired. For assets Inergy constructs, it capitalizes direct costs, such as labor and materials, and indirect costs, such as overhead and interest. Inergy capitalizes major units of property replacements or improvements and expenses minor items. Depreciation is computed by the straight-line method over the estimated useful lives of the assets, as follows:

	Years
Gathering systems	20
Processing plants and compression facilities	20 – 25
Buildings, rights-of-way, easements and storage rights	20 – 70
Office furniture and equipment	5 – 10
Vehicles	5
Pipelines	20
Base gas	10

Salt deposits are depleted utilizing the unit of production method.

Identifiable Intangible Assets

Identifiable Intangible Assets

The Company has recorded certain identifiable intangible assets, including customer accounts, trademarks, deferred financing costs and gas gathering, compression and processing contracts. Customer accounts and trademarks have arisen from acquisitions. Deferred financing costs represent financing costs incurred in obtaining financing and are being amortized over the term of the related debt using the effective interest method. The Company recognizes acquired intangible asset separately 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.

Goodwill

Goodwill

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

Inergy completed its annual impairment test for each of its reporting units and determined that no impairment existed as of December 31, 2012. No indicators of impairment were identified requiring an interim impairment test during the six-month period ended June 30, 2013.

Income Taxes

Income Taxes

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

Inergy is responsible for its portion of the Texas Margin tax that is included in Crestwood Holdings' consolidated Texas franchise tax return. Inergy's current tax liability will be assessed based on 0.7% of the gross revenue apportioned to Texas. The margin tax qualifies as an income tax under GAAP, which requires Inergy to recognize the impact of this tax on the temporary differences between the financial statement assets and liabilities and their tax basis attributable to such tax.

Sales Tax

Sales Tax

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

Income Per Unit

Income Per Unit

Inergy calculates basic net income per limited partner unit by utilizing the two class method. Diluted net income per limited partner unit is computed by dividing net income attributable to the limited partners by the weighted-average number of units outstanding and the effect of dilutive units granted in the Inergy acquisition of CMLP GP. Net income attributable to the limited partners is determined by first allocating to Inergy, L.P. the earnings from the general partner and IDR interests from NRGM and CMLP with the remaining earnings allocated according to the capital accounts. The weighted average number of units outstanding is calculated based on the presumption that the common and subordinated units issued to acquire CMLP GP (the accounting predecessor) were outstanding for the entire period prior to the June 19, 2013 acquisition. On the date of the acquisition, all of NRGY's limited partner units are considered outstanding.

Asset Retirement Obligations

Asset Retirement Obligations

An asset retirement obligation ("ARO") is an estimated liability for the cost to retire a tangible asset. Inergy records a liability for legal or contractual obligations to retire its long-lived assets associated with right-of-way contracts it holds and its facilities whether owned or leased. Inergy records a liability in the period the obligation is incurred and estimable. An ARO is initially recorded at its estimated fair value with a corresponding increase to property, plant and equipment. This increase in property, plant and equipment is then depreciated over the useful life of the asset to which that liability relates. An ongoing expense is recognized for changes in the value of the liability as a result of the passage of time, which Inergy records as depreciation, amortization and accretion expense on its consolidated statements of operations. The fair value of certain AROs could not be determined as settlement dates (or range of dates) associated with these assets were not estimable. The net AROs were $14.4 million and $14.0 million at June 30, 2013 and December 31, 2012, respectively, and are included in other long-term liabilities on the consolidated balance sheets.

Environmental Costs and Other Contingencies

Inergy recognizes liabilities for environmental and other contingencies when it has an exposure that indicates it is both probable that a liability has been incurred and the amount of loss can be reasonably estimated. Where the most likely outcome of a contingency can be reasonably estimated, Inergy accrues a liability for that amount. Where the most likely outcome cannot be estimated, a range of potential losses is established and if no one amount in that range is more likely than any other, the low end of the range is accrued.

Inergy records liabilities for environmental contingencies at their undiscounted amounts on its consolidated balance sheets as accrued expenses and other liabilities when environmental assessments indicate that remediation efforts are probable and costs can be reasonably estimated. Estimates of Inergy's liabilities are based on currently available facts and presently enacted laws and regulations, taking into consideration the likely effects of other societal and economic factors. These estimates are subject to revision in future periods based on actual costs or new circumstances. Inergy capitalizes costs that benefit future periods and recognize a current period charge in operation and maintenance expense when clean-up efforts do not benefit future periods.

Inergy evaluates potential recoveries of amounts from third parties, including insurance coverage, separately from its liability. Recovery is evaluated based on the solvency of the third party, among other factors. When recovery is assured, Inergy records and reports an asset separately from the associated liability on its consolidated balance sheet.

Accounting For Unit-Based Compensation

Accounting for Unit-Based Compensation

Unit-based compensation awards are valued at the closing market price of our common units on the date of grant, which reflects the fair value of such awards. For those awards that are settled in cash, the associated liability is remeasured at every balance sheet date through settlement, such that the vested portion of the liability is adjusted to reflect its revised fair value through compensation expense. Inergy generally recognizes the expense associated with the award over the vesting period. At the time of issuance of phantom units, management of the General Partner determines whether they will be settled in cash or settled in common units. Unit-based compensation awards at Inergy Midstream and Crestwood Midstream are fully reflected in these financial statements and are accounted for in the manner described above.

The amount of compensation expense recorded by the Company was $1.4 million and $0.5 million during the three months endedJune 30, 2013 and 2012, respectively, and $2.0 million and $1.0 million during the six months endedJune 30, 2013 and 2012, respectively.

Segment Information

Segment Information

There are certain accounting requirements that establish standards for reporting information about operating segments, as well as related disclosures about products and services, geographic areas and major customers. Further, they define operating segments as components of an enterprise for which separate financial information is available that is evaluated regularly by the chief operating decision maker in deciding how to allocate resources and assess performance. In determining its operating segments, Inergy examined the way it organizes its business internally for making operating decisions and assessing business performance. See Note 10 for disclosures related to Inergy’s three operating and reporting segments.

Fair Value

Fair Value

Cash and Cash Equivalents, Accounts Receivable and Accounts Payable

As of June 30, 2013 and December 31, 2012, the carrying amounts of cash and cash equivalents, accounts receivable (net of allowance for doubtful accounts) and accounts payable represent fair value due to their liquid and short-term nature.

Credit Facilities

The fair value of the Company's credit agreement and all of its credit facilities approximates their carrying amounts as of June 30, 2013 and December 31, 2012 due primarily to the variable nature of the interest rates of the instruments.

Senior Notes

Inergy estimates the fair value of its senior notes primarily based on quoted market prices for the same or similar issuances. This valuation methodology is considered level 2 in the fair value hierarchy. The following table reflects the carrying value and fair value of the senior notes (in millions):

	June 30, 2013				December 31, 2012
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Inergy senior unsecured notes	$	11.5	$	11.8	$	—	$	—
CMLP senior notes	$	351.3	$	362.5	$	351.5	$	365.9
NRGM senior unsecured notes	$	500.0	$	494.7	$	—	$	—

See Note 6 for a discussion of the Company's assets and liabilities recorded at fair value on the balance sheet.

Recently Issued Accounting Pronouncements

Recently Issued Accounting Pronouncements

On December 16, 2011, the Financial Accounting Standards Board issued ASU No. 2011-11, “Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities.” This ASU requires disclosures to provide information to help reconcile differences in the offsetting requirements under U.S. Generally Accepted Accounting Principles and International Financial Reporting Standards. The disclosure requirements of this ASU mandate that entities disclose both gross and net information about financial instruments and transactions eligible for offset in the statement of financial position as well as instruments and transactions subject to an enforceable master netting arrangement or similar agreement. ASU No. 2011-11 also requires disclosure of collateral received and posted in connection with master netting arrangements or similar arrangements. The scope of this ASU includes derivative contracts, repurchase agreements, and securities borrowing and lending arrangements. Entities are required to apply the amendments of ASU No. 2011-11 for annual reporting periods beginning on or after January 1, 2013, and interim periods within those annual periods. All disclosures provided by those amendments are required to be provided retrospectively for all comparative periods presented. The Company adopted the effects of ASU No. 2011-11 on January 1, 2013.

On February 5, 2013, the FASB issued ASU No. 2013-02, “Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income.” This ASU amends and clarifies the disclosure requirements prescribed in ASU No. 2011-05, “Comprehensive Income (Topic 220): Presentation of Comprehensive Income.” ASU No. 2013-02 requires that entities present information about reclassification adjustments from accumulated other comprehensive income in their annual financial statements in a single note or on the face of the financial statements. Public entities will also have to provide this information in their interim financial statements. Specifically, entities must present, either in a single note or parenthetically on the face of the financial statements, the effect of significant amounts reclassified from each component of accumulated other comprehensive income based on its source and the income statement line items affected by the reclassification. If a component is not required to be reclassified to net income in its entirety, entities would instead cross reference to the related footnote for additional information.  The Company adopted the requirements of ASU No. 2013-02 on January 1, 2013 and presented the required information in a single note.