Crestwood Equity Partners (CEQP+) 10-K 2012 FY Annual report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

x	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the fiscal year ended September 30, 2012

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: 001-35377

INERGY MIDSTREAM, L.P.

(Exact name of registrant as specified in its charter)

Delaware	20-1647837
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

Two Brush Creek Boulevard, Suite 200, Kansas City, Missouri 64112

(Address of principal executive offices) (Zip Code)

(816) 842-8181

(Registrant’s telephone number including area code)

SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:

Title of Each Class	Name of Each Exchange on Which Registered
Common Units representing limited partnership interests	The New York Stock Exchange

SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: None

Indicate by check mark if registrant is a well-known seasoned issuer, as defined by Rule 405 of the Securities Act.    Yes  ¨    No  x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act.     Yes  ¨    No  x

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

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

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  x

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 ¨		Accelerated filer ¨
Non-accelerated filer x	(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  x

As of March 30, 2012, the last business day of the registrant's most recently completed second fiscal quarter, the aggregate market value of the registrant's common units held by non-affiliates of the registrant was $382.1 million based on a closing price of $20.91 per common unit as reported on the New York Stock Exchange on such date.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the following documents are incorporated by reference into the indicated parts of this report: None.

INERGY MIDSTREAM, L.P.

INDEX TO ANNUAL REPORT ON FORM 10-K

		Page
	PART I
Item 1.	Business	1
Item 1A.	Risk Factors	15
Item 1B.	Unresolved Staff Comments	31
Item 2.	Properties	32
Item 3.	Legal Proceedings	32
Item 4.	Mine Safety Disclosures	32
	PART II
Item 5.	Market for the Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities	33
Item 6.	Selected Financial Data	34
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	37
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	48
Item 8.	Financial Statements and Supplementary Data	49
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	49
Item 9A.	Controls and Procedures	49
Item 9B.	Other Information	49
	PART III
Item 10.	Directors, Executive Officers and Corporate Governance	50
Item 11.	Executive Compensation	53
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters	55
Item 13.	Certain Relationships, Related Transactions and Director Independence	56
Item 14.	Principal Accountant Fees and Services	61
	PART IV
Item 15.	Exhibits and Financial Statement Schedules	62

GLOSSARY

The terms below are common to our industry and used throughout this report.

/d	per day
Balancing services	Services pursuant to which natural gas storage customers pay fees to help balance and true up their deliveries to, or takeaways of natural gas from, storage facilities.
Barrel (bbl)	One barrel of petroleum products equal to 42 U.S. gallons.
Base gas	A quantity of natural gas held within the confines of the natural gas storage facility and used for pressure support and to maintain a minimum facility pressure. May consist of injected base gas or native base gas. Also known as cushion gas.
Bcf	One billion cubic feet of natural gas. A standard volume measure of natural gas products.
Cycle	A complete withdrawal and injection of working gas.
Dth	One dekatherm of natural gas.
FERC	Federal Energy Regulatory Commission.
Firm service	Services pursuant to which customers receive an assured, or “firm”, right to (i) in the context of storage service, store product in the storage facility or (ii) in the context of transportation service, transport product through a pipeline, over a defined period of time.
GAAP	Generally Accepted Accounting Principles.
Gas storage capacity	The maximum volume of natural gas that can be cost-effectively injected into a storage facility and extracted during the normal operation of the storage facility. Gas storage capacity excludes base gas.
Hub	Geographic location of a natural gas storage facility and multiple pipeline interconnections.
Hub services	With respect to our natural gas operations, the following services: (i) interruptible storage services, (ii) firm and interruptible park and loan services, (iii) interruptible wheeling services, and (iv) balancing services.
Injection rate	The rate at which a customer is permitted to inject natural gas into a natural gas storage facility.
Interruptible service	Services pursuant to which customers receive only limited assurances regarding the availability of (i) with respect to natural gas storage services, capacity and deliverability in storage facilities or (ii) with respect to natural gas transportation services, capacity and deliverability from receipt points to delivery points. Customers pay fees for interruptible services based on their actual utilization of the storage or transportation assets.
Local distribution companies (LDCs)	The local gas utility companies that transport natural gas from interstate and intrastate pipelines to retail and industrial customers through small-diameter distribution pipelines.
Liquefied natural gas (LNG)	Natural gas that has been cooled to minus 161 degrees Celsius for transportation, typically by ship. The cooling process reduces the volume of natural gas by 600 times.
Mcf	One thousand cubic feet of natural gas. We have converted throughput numbers from a heating value number to a volumetric number based upon a conversion factor of 1 MMbtu equals 1 Mcf.
MMbtu	One million British thermal units, which is approximately equal to one Mcf. One British thermal unit is equivalent to an amount of heat required to raise the temperature of one pound of water by one degree.
MMcf	One million cubic feet of natural gas.
Natural gas	A gaseous mixture of hydrocarbon compounds, the primary one being methane, but other components include ethane, propane and butane.
Natural Gas Act	Federal law enacted in 1938 that established the FERC's authority to regulate interstate pipelines.
Natural gas liquids (NGLs)	Those hydrocarbons in natural gas that are separated from the natural gas as liquids through the process of absorption, condensation, adsorption or other methods in natural gas processing or cycling plants. Natural gas liquids include natural gas plant liquids (primarily ethane, propane, butane and isobutane) and lease condensate (primarily pentanes produced from natural gas at lease separators and field facilities).
Park and loan services	Services pursuant to which natural gas storage customers receive the right to store natural gas in (park), or borrow natural gas from (loan), storage facilities on a seasonal basis.
Reservoir	An underground formation that originally contained crude oil or natural gas, or both.

Salt cavern	A man-made cavern developed in a salt dome or salt beds by leaching or mining of the salt.
Wheeling	The transportation of natural gas from one pipeline to another pipeline through the pipeline facilities of a natural gas storage facility. The gas does not flow into or out of actual storage, but merely uses the surface facilities of the storage operation.
Wheeling services	Services pursuant to which natural gas customers pay fees for the limited right to move a volume of natural gas from one interconnection point through storage and redelivering the natural gas to another interconnection point.
Withdrawal rate	The rate at which a customer is permitted to withdraw gas from a natural gas storage facility.
Working gas	Natural gas in a storage facility in excess of base gas. Working gas may or may not be completely withdrawn during any particular withdrawal season.
Working gas storage capacity	See gas storage capacity (above).

PART I

Item 1. Business.

Unless the context requires otherwise, references to “we,” “us,” “our,” “our company,” “Inergy Midstream” and like terms refer to Inergy Midstream, L.P. and its consolidated subsidiaries. Unless otherwise indicated, information contained herein is reported as of September 30, 2012.

Introduction

Inergy Midstream, L.P. is a publicly-traded Delaware limited partnership formed in November 2011. We are a predominantly fee-based, growth-oriented partnership that develops, acquires, owns and operates midstream energy assets. We are headquartered in Kansas City, Missouri, and our common units representing limited partner interests are listed on the New York Stock Exchange under the symbol “NRGM”.

We conduct business through our subsidiaries, which own and operate natural gas and NGL storage and transportation facilities and a salt production business located in the Northeast region of the United States. We have two reporting segments: (i) storage and transportation and (ii) salt. Our storage and transportation reporting segment includes four natural gas storage facilities with an aggregate working gas storage capacity of approximately 41.0 Bcf; natural gas pipeline facilities with 905 MMcf/d of transportation capacity; and a 1.5 million barrel NGL storage facility. Our salt reporting segment includes the assets and operations of our wholly-owned subsidiary, US Salt, LLC ("US Salt"), a leading solution mining and salt production company.

Our primary business objective is to increase the cash distributions that we pay to our unitholders by growing our business through the development, acquisition and operation of additional midstream assets situated near major shale production and end user demand centers. An integral part of our growth strategy entails the continued development of our platform of interconnected natural gas assets in the Northeast that can be operated as an integrated storage and transportation hub. We expect our growth strategy to reflect our desire to diversify our operations, in terms of both our geographic footprint and the type of midstream services we provide to customers.

Consistent with our growth and diversification goals, on November 3, 2012, we entered into an agreement to acquire Rangeland Energy, LLC (“Rangeland Energy”) for $425 million, subject to certain performance goals and working capital adjustments.  Rangeland Energy owns and operates an integrated crude oil rail and truck terminal, storage and pipeline facilities (the “COLT Hub”) located in Williams County, North Dakota in the heart of the Bakken and Three Forks shale oil-producing region.  The Colt Hub primarily consists of 720,000 barrels of crude oil storage, two 8,700-foot rail loops, an eight-bay truck unloading rack, and 21-mile bidirectional crude oil pipeline that connects the terminal to crude oil gathering systems and crude oil interstate pipelines.  We expect to complete the Rangeland Energy acquisition in calendar 2012.  See “Recent Developments” for additional information.

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Ownership Structure

The diagram below reflects a simplified version of our ownership structure:

We were formed by Inergy, L.P. ("Inergy") on November 14, 2011. We were formed by converting Inergy Midstream, LLC from a Delaware limited liability company into a Delaware limited partnership named Inergy Midstream, L.P. This conversion occurred as part of our initial public offering, which closed December 21, 2011. Our non-economic general partner interest is held by NRGM GP, LLC, which we refer to as our "general partner" and which is indirectly owned by Inergy. Inergy also indirectly owns all of our incentive distribution rights ("IDRs") and directly owns approximately 75% of our common units representing limited partnership interests as of September 30, 2012.

Our Assets

Storage and Transportation

We own and operate four high-performance natural gas storage facilities located in New York and Pennsylvania that have an aggregate working gas storage capacity of approximately 41.0 Bcf, which we believe makes us the largest independent natural gas storage provider in the Northeast. Our storage facilities have low maintenance costs, long useful lives and comparatively high cycling capabilities. The interconnectivity of our storage facilities with interstate pipelines offers flexibility to shippers in the Northeast, and our facilities are located in close proximity to the Northeast demand market and a prolific supply source, the Marcellus shale. Our natural gas storage facilities, all of which generate fee-based revenues, include:

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• Stagecoach, a multi-cycle, depleted reservoir storage facility located approximately 150 miles northwest of New York City in Tioga County, New York and Bradford County, Pennsylvania. Stagecoach, which is owned and operated by our subsidiary, Central New York Oil And Gas Company, L.L.C. ("CNYOG"), has 26.25 Bcf of certificated working gas capacity. Its 24-mile, 30-inch diameter south pipeline lateral connects the storage facility to Tennessee Gas Pipeline's ("TGP") 300 Line, and its 10-mile, 20-inch diameter north pipeline lateral connects to the Millennium Pipeline ("Millennium"). As of September 30, 2012, 100% of Stagecoach's available storage capacity is contracted;

• Thomas Corners, a multi-cycle, depleted reservoir storage facility in Steuben County, New York. Thomas Corners, which is owned and operated our subsidiary, by Arlington Storage Company, LLC ("ASC"), has 7.0 Bcf of certificated working gas capacity. Its 8-mile, 12-inch diameter pipeline lateral connects the storage facility to TGP's 400 Line, and its 7.5-mile, 8-inch diameter pipeline lateral connects to Millennium. As of September 30, 2012, 100% of Thomas Corners' available storage capacity is contracted;

• Steuben, a single-turn, depleted reservoir storage facility in Schuyler County, New York. Steuben, which is owned and operated by our subsidiary, Steuben Gas Storage Company ("Steuben Gas Storage"), has 6.2 Bcf of certificated working gas capacity. Its 12.5-mile, 12-inch diameter pipeline lateral connects the storage facility to the Dominion Transmission Inc. ("Dominion") system, and a 6-inch diameter pipeline measuring less than one mile connects our Steuben and Thomas Corners storage facilities. As of September 30, 2012, 100% of Steuben's available storage capacity is contracted; and

• Seneca Lake, a multi-cycle, bedded salt storage facility in Schuyler County, New York. Seneca Lake, which is owned and operated by ASC, has 1.45 Bcf of certificated working gas capacity. Its 19-mile, 16-inch diameter pipeline lateral connects the storage facility to Millennium and Dominion's system. We acquired the Seneca Lake facility from New York State Electric & Gas Corporation ("NYSEG") on July 13, 2011. As of September 30, 2012, 100% of Seneca Lake's available storage capacity is contracted.

The following provides additional information about our natural gas storage facilities:

Facility Name/ Location	Cycling Capability (Number of Cycles per Year)	Certificated Working Gas Storage Capacity (Bcf)	Maximum Injection Rate (MMcf/d)	Maximum Withdrawal Rate (MMcf/d)	Pipeline Connections
Stagecoach Tioga County, NY; Bradford County, PA	2x	26.25	250	500	TGP's 300 Line; Millennium; Transco's Leidy Line(1)
Thomas Corners Steuben County, NY	2x	7.0	70	140	TGP's 400 Line; Millennium; Dominion(2)
Seneca Lake Schuyler County, NY	12x(3)	1.45	72.5	145	Dominion; Millennium
Steuben Steuben County, NY	1x	6.3	30	60	TGP's 400 Line; Millennium; Dominion(4)
Total		41.0	422.5	845

(1) Stagecoach's south lateral will be connected to Transco's Leidy Line as a result of our MARC I Pipeline.

(2) Thomas Corners is connected to Dominion indirectly through our Steuben facility.

(3) Seneca Lake was designed for 12-turn service, but we operate it as a nine-turn high-deliverability storage facility.

(4) Steuben is connected to TGP and Millennium indirectly through our Thomas Corners facility.

Our NGL storage assets include the Bath storage facility, a 1.5 million barrel NGL storage facility located near Bath, New York. The facility is located approximately 210 miles northwest of New York City. It is supported by both rail and truck terminal facilities capable of loading and unloading 23 railcars per day and approximately 70 truck transports per day. Our Bath storage facility generates fee-based revenues, and as of September 30, 2012, 100% of its available storage capacity is sold to an affiliate, Inergy Services, LLC ("Inergy Services").

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We own natural gas transportation facilities located in New York and Pennsylvania. These facilities have low maintenance costs and long useful lives, and they are located in or near the Marcellus shale. Throughput on our transportation assets can also be expanded at relatively low capital costs. Our natural gas transportation facilities include:

• North-South Facilities, which include compression and appurtenant facilities installed to expand transportation capacity on the Stagecoach north and south pipeline laterals. The bi-directional facilities, which are owned and operated by CNYOG, provide 325 MMcf/d of firm interstate transportation service to shippers. The North-South Facilities, which were placed into service on December 1, 2011, generate fee-based revenues under a negotiated rate structure authorized by the FERC;

• MARC I Pipeline, a 39-mile, 30-inch diameter interstate natural gas pipeline that connects the Stagecoach south lateral and TGP's 300 Line in Bradford County, Pennsylvania, with Transcontinental Gas Pipe Line Company, LLC's ("Transco") Leidy Line in Lycoming County, Pennsylvania. The bi-directional pipeline, which is owned and operated by CNYOG, will provide 550 MMcf/d of interstate transportation capacity. It includes a 16,360 horsepower gas-fired compressor station in the vicinity of the Transco interconnection, and a 15,000 horsepower electric-powered compressor station at the proposed interconnection between the Stagecoach south lateral and TGP's 300 Line. We expect to place the MARC I Pipeline into service on December 1, 2012, and it will generate fee-based revenues under a negotiated rate structure authorized by the FERC; and

• East Pipeline,a 37.5 mile, 12-inch diameter natural gas intrastate pipeline located in New York, which transports 30 MMcf/d of natural gas from Dominion to the Binghamton, New York city gate. The pipeline, which is owned and operated by Inergy Pipeline East, LLC ("IPE"), runs within three miles of our Stagecoach north lateral's point of interconnection with Millennium. The East Pipeline generates fee-based revenues under a negotiated rate structure authorized by the New York State Public Service Commission ("NYPSC"). We acquired the East Pipeline (formerly known as the Seneca Lake east pipeline) from NYSEG on July 13, 2011 as part of our acquisition of the Seneca Lake natural gas storage facility.

The following provides additional information about our natural gas transportation facilities:

Facility Name	Pipeline Diameter (Inches)	Design Capacity (MMcf/d)	Pipeline Connections
North-South Facilities	20 (North lateral); 30 (South lateral)	560 (North lateral); 728 (South lateral)	Millennium (North lateral); TGP's 300 Line (South lateral)
MARC I Pipeline (1)	30	550	Stagecoach South Lateral; TGP's 300 Line; Transco's Leidy Line
East Pipeline	12	30	Dominion

(1) The MARC I Pipeline is expected to be placed into commercial service December 1, 2012.

Salt

We own US Salt, an industry-leading solution mining and salt production company located on the shores of Seneca Lake near Watkins Glen in Schuyler County, New York. US Salt is located in close proximity to our Seneca Lake natural gas storage facility and our Watkins Glen NGL storage development project. It is one of five major solution mined salt manufacturers in the United States, producing evaporated salt products for food, industrial, pharmaceutical and water conditioning uses. US Salt produces and sells more than 300,000 tons of evaporated salt each year, and the solution mining process used by US Salt creates salt caverns that can be converted into natural gas and NGL storage capacity.

We transferred US Salt to Inergy on November 25, 2011 in connection with our initial public offering. On May 14, 2012, we re-acquired US Salt from Inergy for a total purchase price of $192.5 million, including $182.5 million in cash and 473,707 common units.

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Growth Projects

MARC I Pipeline

In August 2010, we requested FERC authorization to construct, own and operate the MARC I Pipeline, a 39-mile bi-directional interstate natural gas pipeline that runs through Bradford, Sullivan and Lycoming Counties, Pennsylvania. Before doing so, we entered into binding precedent agreements with four shippers under which they agreed to subscribe for 550 MMcf/d of firm transportation service on the MARC I Pipeline for a period of 10 years. At that time, we expected to receive a FERC certificate order authorizing our pipeline by mid-summer 2011 and to place the pipeline into service by July 2012. Our development plans have taken longer than anticipated due to regulatory delays and legal challenges, however, and the MARC I Pipeline is scheduled to be placed into service on December 1, 2012. As of September 30, 2012, we have incurred aggregate capital costs of approximately $213.5 million for development and construction of the MARC I Pipeline.

In October 2012, the MARC I shippers requested that their volumetric commitments be reduced from 550 MMcf/d to 450 MMcf/d. Under our precedent agreements, the shippers could terminate their contractual obligations if the pipeline was not placed into service on or before October 1, 2012. In response to the request, we agreed to reduce the shippers' volumetric requirements from 550 MMcf/d to 450 MMcf/d and the shippers agreed not to terminate their contracts if the MARC I Pipeline is placed into service on or before January 1, 2013. We have received FERC authorization to place the pipeline into interim service and we are working to complete the final commissioning activity before requesting FERC authorization to place the pipeline into full commercial service on December 1, 2012. We expect to sell all or substantially all of the 100 MMcf/d of turned-back capacity at or near rates payable by the releasing MARC I shippers. If we are unable to sell any such capacity on a firm basis under long-term contracts, then we expect to sell the capacity on an interruptible basis until market conditions support the execution of long-term contracts at acceptable rates.

Watkins Glen NGL Storage Development Project

We are developing a 2.1 million barrel NGL storage facility near Watkins Glen, New York, using existing cavern capacity created by US Salt's solution-mining process. Propane and butane are expected to be stored in these caverns seasonally. The facility will be supported by rail and truck terminal facilities capable of loading and unloading 32 railcars per day and 45 truck transports per day, and will connect with TEPPCO's NGL interstate pipeline. We have entered into a five-year contract with an affiliate, Inergy Services, under which Inergy Services will effectively market the facility's storage capacity for our economic benefit under a pass-through revenue arrangement.

We filed an application with the New York State Department of Environmental Conservation ("NYSDEC") for an underground storage permit in October 2009, and we have encountered delays in the permitting process. We believe we have provided all of the information the NYSDEC requires to issue the requested permit, and we expect to receive the requested permit early next year. Subject to receiving the requested permit and barring any other unexpected delays, we expect to construct and place into service the NGL storage facility within 120 days after receiving the underground storage permit. As of September 30, 2012, we have incurred approximately $44.9 million of aggregate capital costs for the Watkins Glen NGL storage development project.

Truck Rack Expansion and Upgrade

In November 2012, we completed construction of a new truck loading and unloading facilities at our Bath NGL storage facility. The new truck rack has two bays and arms capable of loading and unloading 70 trucks per day. We are also upgrading the existing truck rack to increase the rack's loading and unloading capabilities from 17 trucks to 30 trucks per day, which we expect to complete in December 2012. Upon completion of the upgrade, our truck racks at the Bath facility are expected to be able to load and unload up to 100 trucks per day. As of September 30, 2012, we have incurred approximately $0.9 million of total capital costs for this project. Our affiliate that utilizes and markets all of the Bath storage capacity, Inergy Services, will pay higher annual reservation fees as a result of the new truck rack.

Commonwealth Pipeline Project

In February 2012, we announced plans to jointly market and develop a new interstate natural gas pipeline project with affiliates of UGI Corporation and WGL Holdings, Inc. The Commonwealth Pipeline project is designed to provide a direct, cost-effective basis for moving Marcellus shale gas to growing natural gas demand markets in southeastern Pennsylvania and the Mid-Atlantic markets. The project sponsors held a non-binding open season for capacity on the Commonwealth Pipeline late in the second quarter of calendar 2012. Based on the results of the open season and subsequent discussions with potential shippers, the project sponsors on September 20, 2012 announced that, among other things, (i) the pipeline is expected to run approximately 120 miles to the southern terminus of our MARC I Pipeline to a point of interconnection with several interstate

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pipelines in Chester County, Pennsylvania; (ii) the 30-inch diameter pipeline will have an initial capacity of 800 MMcf/d of natural gas; (iii) affiliates of UGI Corporation and WGL Holdings have entered into binding precedent agreements to subscribe for firm transportation service on the Commonwealth Pipeline at negotiated rates under 10-year contracts; and (iv) the sponsors expect to place the pipeline into service in 2015.

The project sponsors are continuing to refine costs, route options and other information required to complete a feasibility study, and assess market demand for the proposed transportation capacity. We remain optimistic that the market will support this low-cost transportation option for providing a direct path for moving local Marcellus shale gas to local demand centers, although we can provide no assurance that the project will be placed into service.

Seneca Lake Expansion (Gallery 2)

In fiscal 2012, we performed pre-construction activity and pursued the regulatory approvals required to expand the working gas capacity of our Seneca Lake natural gas storage facility by approximately 0.5 Bcf. We estimate the total capital cost of this expansion to be approximately $3.0 million. We have filed an application with the NYSDEC for the underground storage permit required to debrine and inject natural gas into the cavern. Upon receipt of the underground storage permit, we will request FERC authorization to place the expansion capacity into natural gas storage service. We expect to place this expansion capacity into service in the second half of calendar 2013.

North-South II Expansion and Extension

In September 2011, we held a non-binding open season to gauge shipper interest in our North-South II expansion project, which involved the installation of pipeline, compression and other facilities to enable shippers to move higher volumes of natural gas on a firm basis through our Stagecoach laterals from TGP's 300 Line to Millennium, and all points in between. As part of this project, we would (i) extend our Stagecoach north lateral approximately three miles to interconnect with the East Pipeline, which would enable shippers to transport volumes from TGP's 300 Line (as well as intermediate points, including Millennium) to the point of interconnection between the East Pipeline and Dominion's system in Tompkins County, New York, and (ii) expand the capacity of the Stagecoach laterals, by installing additional compression or looping, to enable shippers to move higher volumes over the existing pipeline route of the North-South Facilities. We believe the market will desire the additional transportation flexibility provided by this project and are continuing both our commercial discussions with potential shippers and our efforts to acquire the land rights necessary to complete the three-mile extension of the Stagecoach north lateral, although we can provide no assurance that the project will be placed into service.

Other Growth Projects

In May 2012, we connected our Seneca Lake natural gas storage facility to Millennium. We installed this interconnection at a total capital cost of approximately $7.4 million. This interconnection provides our storage customers with greater takeaway and delivery options, which we believe will translate into greater revenues from higher storage rates and increased wheeling services.

We have identified existing salt caverns on US Salt's property that we believe can be converted into natural gas and NGL storage capacity. This storage capacity is in addition to the caverns designated for NGL storage by the Watkins Glen NGL storage development project and the expansion of our Seneca Lake natural gas storage facility by approximately 0.5 Bcf. In the normal course of our business, we periodically review cavern information to assess whether caverns are potential candidates for natural gas or NGL storage conversion, evaluate whether market demand would support developing incremental storage services, and discuss storage opportunities with potential customers. We continue to believe the market will require additional natural gas and NGL storage capacity in the Northeast to help satisfy growing demand, and we believe our solution-mined caverns will be able to provide cost-effective solutions.

Our Services

Storage and Transportation

We contract with customers to provide storage and transportation services on a firm (natural gas and NGL) and interruptible (natural gas only) basis. We seek to maximize the portion of physical capacity sold in our storage facilities and on our pipelines under firm contracts. To the extent the physical capacity that is contracted for firm service is not being fully utilized, we attempt to sell the available capacity on an interruptible basis.

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The terms and conditions of the agreements under which we provide interstate storage and transportation services to customers are governed by our FERC tariffs. The general terms and conditions of our tariffs address customary matters such as creditworthiness, extension and termination rights, force majeure, fuel reimbursement and capacity releases. Non-conforming service agreements must be submitted to the FERC for approval.

Firm Storage Services. Firm storage services include storage services pursuant to which customers receive an assured, or “firm,” right to store the commodity in our facilities over a defined period, typically three to five years with respect to our natural gas firm storage contracts. Under our firm storage contracts, we receive fixed monthly capacity reservation fees regardless of whether or not the storage capacity is used. The amount of the monthly reservation fees is typically determined by the number of cycles a customer can fill and empty its contracted storage capacity. Under our firm storage contracts for natural gas storage, we also typically collect a cycling fee based on the volume of natural gas nominated for injection and/or withdrawal and retain a small portion of the gas nominated for injection as compensation for our fuel use. No-notice service, which is commonly referred to as load-following service, is a premium type of firm storage service that entitles natural gas shippers to priority service and provides additional nominating and balancing flexibility.

Transportation Services. We provide interstate and intrastate transportation services. Our customers choose, based upon their particular needs, the applicable mix of services depending upon availability of pipeline capacity, the price of services and the volume and timing of the customer's requirements. Firm transportation customers reserve a specific amount of pipeline capacity at specified receipt and delivery points on our system. Firm customers generally pay fees based on the quantity of capacity reserved regardless of use, plus a commodity and a fuel charge paid on the volume of gas actually transported. Capacity reservation revenues derived from a firm service contract are generally consistent during the contract term. Our firm transportation contracts generally range in term from five to ten years, although we may enter into shorter or longer term contracts. In providing interruptible transportation service, we agree to transport gas for a customer when capacity is available. Interruptible transportation service customers pay a commodity charge only for the volume of gas actually transported, plus a fuel charge. Interruptible transportation agreements have terms ranging from day-to-day to multiple years, with rates that change on a daily, monthly or seasonal basis.

Our interstate transportation services include firm wheeling services and firm and interruptible transportation services provided under our FERC tariffs. We have entered into firm wheeling agreements with five shippers under which we are providing 325 MMcf/d of firm wheeling service to the North-South Facilities shippers at negotiated rates for an initial five-year period. We have entered into firm transportation agreements with four shippers under which we will, upon placement of the MARC I Pipeline into service, provide 450 MMcf/d of firm transportation service to the MARC I shippers at negotiated rates for an initial 10-year period. Our East Pipeline provides intrastate transportation services to NYSEG under a firm transportation service agreement approved by the NYPSC. Under this 10-year contract agreement, we make 30 MMcf/d of transportation capacity available to NYSEG on our East Pipeline for transporting natural gas from Dominion's system to NYSEG's city gates.

Hub Services. With respect to our natural gas storage and transportation operations, hub services include: (i) interruptible storage services, under which customers receive only limited assurances regarding the availability of capacity and deliverability in our storage facilities and pay fees based on their actual utilization of our assets; (ii) firm and interruptible park and loan services, under which customers receive the right to store gas in (park), or borrow gas from (loan), our facilities on a short-term or seasonal basis; (iii) interruptible wheeling services, under which customers pay fees for the limited right to move a volume of natural gas from one interconnection point through storage and redelivering the natural gas to another interconnection point; and (iv) balancing services, under which customers pay us fees to help balance and true up their deliveries of natural gas to, or takeaways of natural gas from, our facilities.

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The table below indicates the types of storage and transportation services that we offer to natural gas customers under our FERC tariffs, as of September 30, 2012:

		Facility  (FERC-Certificated Operator)
Type of Service	Category  of  Service(1)	Stagecoach  (CNYOG)	Thomas Corners  (ASC)	Seneca Lake  (ASC)	Steuben (Steuben Gas)(2)
Firm Storage Service	Firm S/S	Ÿ	Ÿ	Ÿ	Ÿ
Interruptible Storage Service	Hub	Ÿ	Ÿ	Ÿ	Ÿ
No-Notice Storage Service	Firm S/S		Ÿ	Ÿ	Ÿ
Firm Parking Service	Hub		Ÿ	Ÿ	Ÿ
Interruptible Parking Service	Hub		Ÿ	Ÿ	Ÿ
Firm Loan Service	Hub		Ÿ	Ÿ	Ÿ
Interruptible Loan Service	Hub		Ÿ	Ÿ	Ÿ
Firm Wheeling Service	Transport	Ÿ
Interruptible Wheeling Service	Hub	Ÿ	Ÿ	Ÿ	Ÿ
Enhanced Interruptible Wheeling Service	Hub		Ÿ	Ÿ	Ÿ
Firm Transportation Service(3)	Transport	Ÿ
Interruptible Transportation Service	Transport	Ÿ
Interruptible Hourly Balancing Service	Hub		Ÿ	Ÿ	Ÿ

(1) "Firm S/S" refers to firm storage services, "Hub" refers to hub services and "Transport" refers to transportation services

(2) Pro forma for pending merger of Steuben Gas Storage with and into ASC.

(3) Assumes the MARC I Pipeline is placed into service.

Salt

Our salt products are manufactured for food, industrial, pharmaceutical and water conditioning applications. We produce evaporated salt products for customers according to customized specifications, and our product line includes food-grade salt, pharmaceutical-grade salt, bulk salt for chemical feedstock, water softening pellets, pool salt and salt blocks. US Salt does not market and distribute products under its own brand.

When we enter into long-term contracts, we attempt to secure minimum volumetric purchase requirements and other appropriate contractual protections.We have entered into a limited number of long-term contracts under which we agreed to provide a fixed volume of product to the customer at certain times over the life of the contract, subject to standard contractual protections like force majeure rights.

Our Customers

Our natural gas storage and transportation customers consist primarily of natural gas LDCs, electric generation companies, natural gas producers, other natural gas pipelines, and natural gas marketing companies. We provide storage and transportation services in both natural gas supply and demand markets.

Our natural gas customers are largely investment-grade customers. For the fiscal year ended September 30, 2012, Consolidated Edison Inc. ("ConEd") accounted for approximately 14% of our total revenue. With respect to our natural gas customers that are either unrated or non-investment grade, we are authorized by our FERC tariffs and policies to request credit support to secure a portion of our customers' obligations.

Our salt customers are largely creditworthy industrial companies, pharmaceutical companies, food manufacturing companies, and distribution companies, including retail companies such as national grocer chains.

Industry Background

Storage and Transportation

The midstream sector of the natural gas industry provides the link between exploration and production and the delivery of natural gas and its components to end-use markets. The midstream sector consists generally of gathering and processing, transportation and storage activities. Our midstream operations focus on storage and transportation activities for natural gas and NGLs.

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The fundamentals of the natural gas market create a basic demand for storage. Natural gas is produced at a relatively steady rate throughout the year so natural gas supply is relatively constant. However, natural gas consumption is highly seasonal because the market consumes more natural gas in the winter than can be produced. In contrast, more natural gas is produced in the summer than is consumed, which creates this fundamental need for storage. Natural gas storage acts as the balancing mechanism between supply and demand.

Natural gas storage plays a vital role in maintaining the reliability of natural gas supplies needed to meet consumer demands. Storage facilities are used by pipelines to balance operations, by end users (such as power generation companies and local gas distribution companies) to manage volatility and secure natural gas supplies, and by independent natural gas marketing and trading companies in connection with the execution of their trading strategies. Storage allows for the warehousing of natural gas and is used to inject excess production during periods of low demand (typically, warmer summer months) and to withdraw natural gas during periods of high demand (typically, colder winter months).

As is the case with natural gas storage, natural gas transportation pipelines play a vital role in ensuring gas supplies find a market (i.e., moving supply to demand). Transportation pipelines receive natural gas from other mainline transportation pipelines and gathering systems and deliver the natural gas to industrial end-users, utilities and other pipelines.

A recent shift in supply sources, from conventional to unconventional, has affected the supply patterns, the flows and the rates that can be charged on pipeline systems. The impacts will vary among pipelines according to the location and the number of competitors attached to these new supply sources. These changing market dynamics are prompting midstream companies to evaluate the construction of short-haul pipelines as a means of providing demand markets with cost-effective access to newly-developed production regions, as compared to relying on higher-cost, long-haul pipelines that were originally designed to transport natural gas greater distances across the country.

Demand for natural gas storage can be negatively impacted during periods in which there is a narrow seasonal spread between current and future natural gas prices. The natural gas industry is currently experiencing a significant shift in the sources of supply with prolific new shale plays primarily, and this dramatic change could affect our operations.

Natural gas produced at the wellhead normally contains NGLs. Unprocessed natural gas containing NGLs is generally not acceptable for transportation in the U.S. interstate pipeline system or for commercial use. Processing plants extract the NGLs, leaving residual dry gas that meets interstate pipeline and commercial quality specifications. NGL storage facilities are used for the storage of mixed NGLs and NGL products owned by third-parties in storage tanks and underground wells, which allow for the injection and withdrawal of such products at various times of the year to meet demand cycles.

Salt Production

According to the Salt Institute, a North American based non-profit salt industry trade association, more than 290 million metric tons of salt were produced in the world in calendar 2011. Salt is generally categorized into four types based upon the method of production: evaporated salt, solar salt, rock salt and salt in brine. Dry salt is produced through the following methods: solution mining and mechanical evaporation, solar evaporation or deep-shaft mining. US Salt produces salt using solution mining and mechanical evaporation. In solution mining, wells are drilled into salt beds or domes and then water is injected into the formation and circulated to dissolve the salt. After salt is removed from a solution-mined salt deposit, the empty cavern can be used to store other substances, such as natural gas, NGLs or compressed air.

The salt solution, or brine, is next pumped out of the cavern and taken to a processing plant for evaporation. The brine may be treated to remove minerals and then pumped into vacuum pans in which the brine is boiled, and evaporated until a salt slurry is created. The slurry is then dried and separated. Depending on the type of salt product to be produced, iodine and an anti-caking agent may be added to the salt. Most food grade table salt is produced in this manner.

Regulation

Our operations are subject to extensive regulation by federal, state and local authorities. The regulatory burden on our operations increases our cost of doing business and, in turn, affects our profitability. We have experienced increased and more burdensome regulatory oversight over the past few years and, based on our expectation that this trend will continue for the foreseeable future, we anticipate that greater time and resources will be required to obtain the approvals necessary to acquire, develop, and construct midstream infrastructure. We believe the regulatory environment for projects located in the Northeast is particularly challenging, as public opposition to upstream oil and gas activities has increasingly influenced regulatory processes.

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We believe that our operations are in substantial compliance with existing federal, state, and local laws and regulations (including the laws and regulations described below), and that our on-going compliance with applicable law will not have a material adverse effect on our business or results of operations. However, we can provide no assurance that the adoption of new laws and regulations will not add significant costs that could have a material adverse effect on our operations and financial results, or that our results from operations will not be materially and adversely impacted if regulations become more stringent in general. Our inability to obtain or maintain any material permit required to operate or expand our projects could have an adverse impact on our revenues.

Natural Gas Storage and Transportation

Our natural gas storage and transportation operations are subject to extensive federal and state regulation. In particular, our natural gas storage and transportation facilities are subject to regulation by the FERC, and our natural gas pipelines (including storage lateral pipelines) are subject to regulation by the Department of Transportation's ("DOT") Pipeline and Hazardous Materials Safety Administration ("PHMSA").

Under the Natural Gas Act, the FERC has authority to regulate gas transportation services in interstate commerce, which includes natural gas storage services. The FERC exercises jurisdiction over rates charged for services and the terms and conditions of service; the certification and construction of new facilities; the extension or abandonment of services and facilities; the maintenance of accounts and records; the acquisition and disposition of facilities; standards of conduct between affiliated entities; and various other matters. Regulated natural gas companies are prohibited from charging rates determined by the FERC to be unjust, unreasonable, or unduly discriminatory, and both the existing tariff rates and the proposed rates of regulated natural gas companies are subject to challenge.

The rates and terms and conditions of our natural gas storage and transportation services are found in the FERC-approved tariffs of CNYOG, the owner of the Stagecoach facility and laterals, the North-South Facilities and the MARC I Pipeline; Steuben Gas Storage, the owner of the Steuben facility; and ASC, the owner of the Thomas Corners and Seneca Lake facilities. CNYOG and ASC are authorized to charge and collect market-based rates for storage services provided at the Stagecoach, Thomas Corners and Seneca Lake natural gas storage facilities, and CNYOG is authorized to charge and collect negotiated rates for transportation services provided by the North-South Facilities and MARC I Pipeline. Steuben Gas Storage is authorized to charge and collect cost-of-service rates at the Steuben facility. Market-based and negotiated rate authority allows us to negotiate rates with individual customers based on market demand, which we then make public. A loss of market-based or negotiated rate authority or any successful complaint or protest against the rates charged or provided by CNYOG or ASC could have an adverse impact on our revenues.

On August 6, 2010, CNYOG filed an application with the FERC (Docket No. CP10-480) requesting authority to construct, operate and own the MARC I Pipeline. On November 14, 2011, the FERC issued a certificate order granting the requested authorization. On February 13, 2012, the FERC issued an order denying or dismissing all requests for rehearing of the certificate order and a request for stay of that order.

On February 14, 2012, certain of the parties seeking rehearing of the MARC I certificate order filed with the Second Circuit Court of Appeals an appeal and emergency motion for stay of the MARC I certificate. A temporary stay was granted on February 17, 2012, which halted all construction-related activity on the Pipeline until a three-judge panel vacated the temporary stay on February 28, 2012. In March, the Second Circuit granted the request for an expedited hearing briefing schedule for the MARC I certificate appeal. On June 12, 2012, the appellate court held that the FERC properly discharged its responsibilities and summarily dismissed with prejudice petition challenging the MARC I certificate and rehearing orders.

On May 21, 2012, we filed applications with the FERC (Docket Nos. CP12-465 and CP12-466) requesting authority (i) to abandon the FERC tariff held by Steuben Gas Storage and (ii) for ASC to acquire the Steuben facility, via the merger of Steuben Gas Storage into ASC, and to charge marketed-based rates under ASC's tariff for services at the Steuben facility. On October 11, 2012, the FERC issued an order granting the requested authorizations. Effective April 1, 2013, we will have the ability to charge market-based rates for storage service provided by our Thomas Corners, Seneca Lake and Steuben facilities and to provide wheeling services under one tariff (ASC's tariff). Thomas Corners will also effectively be connected to Dominion, and Steuben will effectively be connected to TGP and Millennium, with respect to services offered under ASC's tariff. These actions move us closer toward our goal of developing and operating a fully-integrated natural gas storage and transportation hub in the Northeast.

Our pipelines used to store and transport natural gas are subject to regulation by PHMSA under the Natural Gas Pipeline Safety Act of 1968 ("NGPSA"). The NGPSA regulates safety requirements in the design, installation, testing, construction, operation

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and maintenance of natural gas pipeline facilities. The NGPSA has since been amended by the Pipeline Safety Act of 1992, the Pipeline Safety Improvement Act of 2002, and the Pipeline Inspection, Protection, Enforcement, and Safety Act of 2006. These amendments, along with implementing regulations more recently adopted by PHMSA, have imposed additional safety requirements on pipeline operators such as the development of a written qualification program for individuals performing covered tasks on pipeline facilities and the implementation of pipeline integrity management programs. These integrity management plans require more frequent inspections and other preventative measures to ensure pipeline safety in “high consequence areas,” such as high population areas, areas unusually sensitive to environmental damage, and commercially navigable waterways.

Notwithstanding the investigatory and preventative maintenance costs incurred performing routine pipeline management activities, we may incur significant expenses if anomalous pipeline conditions are discovered or due to the implementation of more stringent pipeline safety standards as a result of new or amended legislation. For example, in January 2012, President Obama signed the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (“Pipeline Safety Act”), which requires increased safety measures for gas and hazardous liquids transportation pipelines. Among other things, the Pipeline Safety Act directs the Secretary of Transportation to promulgate rules or standards relating to expanded integrity management requirements, automatic or remote-controlled valve use, excess flow valve use, and leak detection system installation. The Pipeline Safety Act also directs owners and operators of interstate and intrastate gas transmission pipelines to verify their records confirming the maximum allowable pressure of pipelines in certain class locations and high consequence areas, requires promulgation of regulations for conducting tests to confirm the material strength of pipe operating above 30% of specified minimum yield strength in high consequence areas, and increases the maximum penalty for violation of pipeline safety regulations from $1 million to $2 million. PHMSA is also considering changes to its natural gas transmission pipeline regulations to, among other things, expand the scope of "high consequence areas", strengthen integrity management requirements applicable to existing operators; strengthen or expand non-integrity pipeline management standards relating to such matters as valve spacing, automatic or remotely-controlled valves, corrosion protection, and gathering lines; and add new regulations to govern the safety of underground natural gas storage facilities including underground storage caverns and injection or withdrawal well piping that are not regulated today. We cannot predict the final outcome of these legislative or regulatory efforts or the precise impact that compliance with any resulting new requirements may have on our business.

Our natural gas storage operations are also subject to non-rate regulation by various state agencies. For example, the NYSDEC has jurisdiction over the underground storage of natural gas and well drilling, conversion and plugging in New York. The NYSDEC therefore regulates aspects of our Stagecoach, Thomas Corners, Seneca Lake and Steuben natural gas storage facilities.

IPE, as the owner and operator of our East Pipeline, is subject to lightened regulation under NYPSC regulations and policies. Lightened regulation generally exempts IPE from NYPSC regulation applicable to the provision of retail service. IPE remains subject to limited corporate (e.g., obtaining approval prior to any transfer of its ownership interests or the issuance of debt securities) and operational and safety (e.g., filing of vegetation management plan and annual reports detailing the gas volumes transported over the pipeline) regulation established and maintained by the NYPSC.

On September 15, 2011, we filed an application with the NYPSC (Docket No. 11-G-0510) requesting authority to pledge the equity interests of IPE in collateral support of, and to guarantee, up to $3 billion of Inergy's long-term indebtedness. The application described that, upon completion of our initial public offering, the scope of the requested authorization would be limited to pledges and guarantees supporting up to $1.5 billion of long-term indebtedness of Inergy Midstream and its wholly-owned subsidiaries. On December 15, 2011, the NYPSC issued an order granting the requested authorization.

NGL Storage

Our NGL storage operations are also subject to federal, state and local regulatory oversight. For example, our NGL storage operations are subject to non-rate regulation by state agencies. The NYSDEC has jurisdiction over the underground storage of NGLs and well drilling, conversion and plugging in New York. Thus, the NYSDEC regulates aspects of our Bath facility and our proposed Watkins Glen facility.

In October 2009, we filed an application with the NYSDEC for an underground storage permit for our Watkins Glen NGL storage facility. In November 2010, the NYSDEC issued a Positive Declaration for the project. In August 2011, the NYSDEC determined that the Draft Supplemental Environmental Impact Statement we submitted for the project was complete. A public hearing on the project was held in September 2011, and a second public hearing was held in November 2011. In early 2012, based on concerns expressed by interested stakeholders and conversations with NYSDEC Staff, we informed the NYSDEC that we would reduce our environmental footprint and modified our brine pond design. In September 2012, we submitted to the

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NYSDEC all final drawings and plans for our revised project design. We expect the NYSDEC to issue an underground storage permit to us early next year.

Salt Production

Our salt production and manufacturing business is highly regulated. Under the Food, Drug and Cosmetic Act, the United States Food and Drug Administration regulates food and pharmaceutical standards applicable to salt products for human consumption and drug products. The United States Environmental Protection Agency ("EPA") administers regulations for emissions control under a Title V air permit, operation and control of solution mining operations, and stormwater pollution prevention for petroleum products. The NYSDEC regulates the drilling and plugging of brine production wells, cooling/process water intake, and wastewater and stormwater discharges. The NYSDEC also administers regulations for bulk petroleum and chemical storage.

Environmental, Health and Safety

In addition, our operations are subject to stringent federal, regional, state and local laws and regulations governing the discharge and emission of pollutants into the environment, environmental protection, or occupational health and safety. These laws and regulations may impose significant obligations on our operations, including the need to obtain permits to conduct regulated activities; restrict the types, quantities and concentration of materials that can be released into the environment; apply workplace health and safety standards for the benefit of employees; require remedial activities or corrective actions to mitigate pollution from former or current operations; and impose substantial liabilities on us for pollution resulting from our operations. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil and criminal penalties; the imposition of investigatory, remedial and corrective action obligations or the incurrence of capital expenditures; the occurrence of delays in the development of projects; and the issuance of injunctions restricting or prohibiting some or all of the activities in a particular area.

The following is a summary of the more significant existing environmental laws and regulations, each as amended from time to time, to which our business operations are subject:

• The federal Comprehensive Environmental Response, Compensation and Liability Act of 1980, a remedial statute that imposes strict liability on generators, transporters and arrangers of hazardous substances at sites where hazardous substance releases have occurred or are threatening to occur;

• The federal Resource Conservation and Recovery Act, which governs the treatment, storage and disposal of solid wastes, including hazardous wastes;

• The federal Clean Air Act, which restricts the emission of air pollutants from many sources and imposes various pre-construction, monitoring and reporting requirements;

• The federal Water Pollution Control Act, also known as the federal Clean Water Act, which regulates discharges of pollutants from facilities to state and federal waters;

• The federal Safe Drinking Water Act, which ensures the quality of the nation's public drinking water through adoption of drinking water standards and controlling the injection of substances into below-ground formations that may adversely affect drinking water sources;

• The National Environmental Policy Act, which requires federal agencies to evaluate major agency actions having the potential to significantly impact the environment and which may require the preparation of Environmental Assessments and more detailed Environmental Impact Statements that may be made available for public review and comment;

• The federal Endangered Species Act, which restricts activities that may affect federally identified endangered and threatened species or their habitats through the implementation of operating restrictions or a temporary, seasonal, or permanent ban in affected areas; and

• The federal Occupational Safety and Health Act, which establishes workplace standards for the protection of the health and safety of employees, including the implementation of hazard communications programs designed to inform employees about hazardous substances in the workplace, potential harmful effects of these substances, and appropriate control measures.

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Certain of these environmental laws impose strict, joint and several liability for costs required to clean up and restore properties where pollutants have been released regardless of whom may have caused the harm or whether the activity was performed in compliance with all applicable laws. In the course of our operations, generated materials or wastes may have been spilled or released from properties owned or leased by us or on or under other locations where these materials or wastes have been taken for recycling or disposal. In addition, many of the properties owned or leased by us were previously operated by third parties whose management, disposal or release of materials and wastes was not under our control. Accordingly, we may be liable for the costs of cleaning up or remediating contamination arising out of our operations or as a result of activities by others who previously occupied or operated on properties now owned or leased by us. Private parties, including the owners of properties that we lease and facilities where our materials or wastes are taken for recycling or disposal, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property or natural resource damages. We may not be able to recover some or any of these additional costs from insurance.

We have not received any notices that we have violated these environmental laws and regulations in any material respect and we have not otherwise incurred any material liability or capital expenditures thereunder. Future developments, such as stricter environmental laws or regulations, or more stringent enforcement of existing requirements could affect our operations. For instance, the EPA and other federal and state agencies are considering or have already commenced the study of potential adverse impacts that certain drilling methods (including hydraulic fracturing) may have on water quality and public health, with the U.S. Department of Energy having released a report recommending the implementation of a variety of measures to reduce the environmental impacts from shale-gas production. Similarly, Congress and several states, including New York and Pennsylvania, have proposed or enacted legislation or regulations that are expected to make it more difficult or costly for exploration and production companies to produce natural gas and NGLs. These initiatives, enactments and regulations could have an indirect adverse impact on us by decreasing demand for the storage and transportation services that we offer.

In addition, federal and state occupational safety and health laws require us to organize information about materials, some of which may be hazardous or toxic, that are used, released, or produced in the course of our operations. Certain portions of this information must be provided to employees, state and local governmental authorities and responders, and local citizens in accordance with applicable federal and state Emergency Planning and Community Right-to-Know Act requirements. Our operations are also subject to the safety hazard communication requirements and reporting obligations set forth in federal workplace standards.

Competition

Natural gas storage operators compete for customers based on geographical location, which determines connectivity to pipelines and proximity to supply sources and end-users, as well as operating reliability and flexibility, price, available capacity and service offerings. From an operator's perspective, having a diverse customer group that requires a variety of storage services is important to maximizing asset utilization and capturing incremental revenue opportunities while minimizing costs. An increase in competition in our markets could arise from new ventures or expanded operations from existing competitors.

Our principal competitors in our natural gas storage market include other independent storage providers and major natural gas pipelines. These major pipeline natural gas transmission companies have existing storage facilities connected to their systems that compete with certain of our facilities. The FERC has adopted a policy that favors authorization of new storage projects, and there are numerous natural gas storage options in the New York/Pennsylvania geographic market. Pending and future construction projects, if and when brought on line, may also compete with our natural gas storage operations. These projects may include FERC-certificated storage expansions and greenfield construction projects. We also compete with the numerous alternatives to storage available to customers, including pipeline balancing/no-notice services, seasonal/swing services provided by pipelines and marketers and on-system LNG facilities.

Our primary competitors in the NGL storage business include integrated major oil companies, refiners and processors, and other pipeline and storage companies.

Our salt operations compete for customers primarily based on price and service. Because transportation costs are a material component of the costs our customers pay, most of our customers are geographically located east of the Mississippi River.

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Employees

Our subsidiary, US Salt, has 140 employees, 105 of which are members of the United Steel Workers union. We do not otherwise have employees, and we rely on Inergy under our Omnibus Agreement to provide us the corporate and other employees needed to carry out our operations. We believe that our relationship with our employees (including union labor) is satisfactory.

Available Information

Our website is located at www.inergylp.com. We make available, free of charge, on or through our website our annual reports on Form 10-K, which include our audited financial statements, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as we electronically file such material with the Securities and Exchange Commission ("SEC"). These documents are also available, free of charge, at the SEC's website at www.sec.gov. In addition, copies of these documents, excluding exhibits, may be requested at no cost by contacting Investor Relations, Inergy Midstream, L.P., Two Brush Creek Boulevard, Suite 200, Kansas City, Missouri, 64112, and our corporate telephone number is (816) 842-8181.

We also make available within the “Corporate Governance” section of our website our corporate governance guidelines, the charter of our Audit Committee and our Code of Business Conduct and Ethics. Requests for copies may be directed in writing to: Inergy Midstream, L.P., Two Brush Creek Boulevard, Suite 200, Kansas City, Missouri, 64112, Attention: General Counsel. Interested parties may contact the chairperson of any of our Board committees, our Board's independent directors as a group or our full Board in writing by mail to Inergy Midstream, L.P., Two Brush Creek Boulevard, Suite 200, Kansas City, Missouri, 64112, Attention: General Counsel. All such communications will be delivered to the director or directors to whom they are addressed.

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Item 1A. Risk Factors

Risks Inherent in Our Business

The supply and demand for natural gas could be adversely affected by many factors outside of our control which could negatively affect us.

Our success depends on the supply and demand for natural gas. The degree to which our business is impacted by changes in supply or demand varies. Our business can be negatively impacted by sustained downturns in supply and demand for natural gas, including reductions in our ability to renew contracts on favorable terms and to construct new infrastructure. One of the major factors that will impact natural gas demand will be the potential growth of the demand for natural gas in the power generation market, particularly driven by the speed and level of existing coal-fired power generation that is replaced with natural gas-fired power generation. One of the major factors impacting natural gas supplies has been the significant growth in unconventional sources such as shale plays. In addition, the supply and demand for natural gas for our business will depend on many other factors outside of our control, which include, among others:

• adverse changes in general global economic conditions. The level and speed of the recovery from the recent recession remains uncertain and could impact the supply and demand for natural gas and our future rate of growth in our business;

• adverse changes in domestic regulations that could impact the supply or demand for natural gas;

• technological advancements that may drive further increases in production and reduction in costs of developing natural gas shales;

• competition from imported LNG and Canadian supplies and alternate fuels;

• increased prices of natural gas or NGLs that could negatively impact demand for these products;

• increased costs to explore for, develop, produce, gather, process and transport natural gas or NGLs;

• adoption of various energy efficiency and conservation measures; and

• perceptions of customers on the availability and price volatility of our services, particularly customers' perceptions on the volatility of natural gas prices over the longer-term.

If volatility and seasonality in the natural gas industry decrease, because of increased production capacity or otherwise, the demand for our services and the prices that we will be able to charge for those services may decline. In addition to volatility and seasonality, an extended period of high natural gas prices would increase the cost of acquiring base gas and likely place upward pressure on the costs of associated expansion activities. An extended period of low natural gas prices could adversely impact storage values for some period of time until market conditions adjust. These commodity price impacts could have a negative impact on our business, financial condition, and results of operations.

If we do not complete growth projects or make acquisitions, our future growth may be limited.

Our business strategy depends on our ability to complete growth projects and make acquisitions from Inergy and third parties that result in an increase in cash generated from operations on a per unit basis (i.e., complete accretive transactions). However, Inergy (i) is entitled under the omnibus agreement to review, and has the first option on, any third-party acquisition opportunities presented to us or to Inergy, (ii) is not obligated to make acquisition opportunities available to us, (iii) is not restricted from competing with us, and (iv) may acquire, construct or dispose of natural gas or NGL facilities or other midstream assets in the future without any obligation to offer us the opportunity to purchase or construct those assets. Moreover, we may be unable to complete successful, accretive growth projects or acquisitions for any of the following reasons:

• we fail to identify attractive expansion or development projects or acquisition candidates that satisfy our economic and other criteria, or we are outbid for such opportunities by our competitors;

• we cannot raise financing for such projects or acquisitions on economically acceptable terms;

• we fail to secure adequate customer commitments to use the facilities to be developed, expanded or acquired; or

• we cannot obtain governmental approvals or other rights, licenses or consents needed to complete such projects or acquisitions. 

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Our operations are subject to extensive regulation, and regulatory measures adopted by regulatory authorities could have a material adverse effect on our business, financial condition and results of operations.

Our operations are subject to extensive regulation by federal, state and local regulatory authorities. For example, because we transport natural gas in interstate commerce and we store natural gas that is transported in interstate commerce, our natural gas storage and transportation facilities are subject to comprehensive regulation by the FERC under the Natural Gas Act. Federal regulation under the Natural Gas Act extends to such matters as:

• rates, operating terms and conditions of service;

• the form of tariffs governing service;

• the types of services we may offer to our customers; 

• the certification and construction of new, or the expansion of existing, facilities;

• the acquisition, extension, disposition or abandonment of facilities; 

• contracts for service between storage and transportation providers and their customers; 

• creditworthiness and credit support requirements; 

• the maintenance of accounts and records;

• relationships among affiliated companies involved in certain aspects of the natural gas business;

• the initiation and discontinuation of services; and 

• various other matters.

Natural gas companies may not charge rates that, upon review by FERC, are found to be unjust and unreasonable or unduly discriminatory. Existing interstate transportation and storage rates may be challenged by complaint and are subject to prospective change by FERC. Additionally, rate increases proposed by a regulated pipeline or storage provider may be challenged and such increases may ultimately be rejected by FERC. We currently hold authority from FERC to charge and collect (i) market-based rates for interstate storage services provided at the Stagecoach, Thomas Corners and Seneca Lake facilities and (ii) negotiated rates for interstate transportation services provided by our North-South Facilities and our MARC I Pipeline. FERC's “market-based rate” policy allows regulated entities to charge rates different from, and in some cases, less than, those which would be permitted under traditional cost-of-service regulation. Among the sorts of changes in circumstances that could raise market power concerns would be an expansion of capacity, acquisitions or other changes in market dynamics. There can be no guarantee that we will be allowed to continue to operate under such rate structures for the remainder of those assets' operating lives. Any successful challenge against rates charged for our storage and transportation services, or our loss of market-based rate authority or negotiated rate authority, could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions. Our market-based rate authority for our natural gas storage facilities may be subject to review and possible revocation if FERC determines that we have the ability to exercise market power in our market area. If we were to lose our ability to charge market-based rates, we would be required to file rates based on our cost of providing service, including a reasonable rate of return. Cost-of-service rates may be lower than our current market-based rates.

There can be no assurance that FERC will continue to pursue its approach of pro-competitive policies as it considers matters such as pipeline rates and rules and policies that may affect rights of access to natural gas transportation capacity and transportation and storage facilities. Failure to comply with applicable regulations under the Natural Gas Act, the Natural Gas Policy Act of 1978, the Pipeline Safety Act of 1968 and certain other laws, and with implementing regulations associated with these laws, could result in the imposition of administrative and criminal remedies and civil penalties of up to $1,000,000 per day, per violation.

We may not be able to renew or replace expiring contracts.

Our primary exposure to market risk occurs at the time our existing contracts expire and are subject to renegotiation and renewal. As of September 30, 2012, the weighted average remaining tenor of our existing portfolio of firm storage contracts is approximately 3.4 years. Customer contracts for 5.2 Bcf of natural gas firm storage service will expire in fiscal 2013. The extension or replacement of existing contracts depends on a number of factors beyond our control, including:

• the macroeconomic factors affecting natural gas and NGL storage economics for our current and potential customers;

• the level of existing and new competition to provide services to our markets;

• the balance of supply and demand, on a short-term, seasonal and long-term basis, in our markets;

• the extent to which the customers in our markets are willing to contract on a long-term basis; and

• the effects of federal, state or local regulations on the contracting practices of our customers.

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Any failure to extend or replace a significant portion of our existing contracts, or extending or replacing them at unfavorable or lower rates, could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions.

We depend on third-party pipelines connected to our storage facilities and pipelines, and we could be negatively impacted by circumstances beyond our control that temporarily or permanently interrupt the operation of such third-party pipelines.

We depend on the continued operation of third-party pipelines that provide delivery options to and from our storage facilities, and to which our transportation pipelines are connected. For example, our Stagecoach facility depends on TGP's 300 Line and Millennium, currently the only interstate pipelines to which it is directly interconnected. These pipelines are owned by parties not affiliated with us. Any temporary or permanent interruption at any key pipeline or other interconnect point with our storage facilities that causes a material reduction in the volume of storage or transportation services provided by us could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions.

In addition, the rates charged by the interconnected pipelines for transportation to and from our facilities and pipelines affect the utilization and value of our services. Significant changes in the rates charged by these pipelines or the rates charged by other pipelines with which the interconnected pipelines compete could also have a material adverse effect on our business, financial condition, results of operations and ability to make distributions.

Expanding our business by developing new midstream assets subjects us to risks.

Our growth projects are an integral part of our business strategy. The development and construction of storage facilities, pipelines, and truck/rail terminals involves numerous regulatory, environmental, political and legal uncertainties beyond our control and may require the expenditure of significant amounts of capital. When we undertake these projects, they may not be completed on schedule, at the budgeted cost or at all. Moreover, our revenues may not increase immediately upon the expenditure of funds on a particular project. For instance, if we build a new midstream asset, the construction will occur over an extended period of time, and we will not receive material increases in revenues until the project is placed in service. Moreover, we may construct facilities to capture anticipated future growth in production and/or demand in a region in which such growth does not materialize. As a result, new facilities may not be able to attract enough throughput to achieve our expected investment return, which could adversely affect our business, financial condition, results of operations and ability to make distributions.

Certain of our growth projects must receive regulatory approval from federal and state authorities prior to construction, such as our Watkins Glen NGL storage development project. The approval process for storage and transportation projects located in the Northeast has become increasingly challenging, due in part to state and local concerns related to unregulated exploration and production and gathering activities in new production areas (including the Marcellus shale play). We cannot guarantee such authorization will be granted or, if granted, that such authorization will be free of burdensome or expensive conditions.

Acquisitions or growth projects that we complete may not perform as anticipated and could result in a reduction of our cash available for distribution.

Even if we complete projects or acquisitions that we believe will be accretive, such projects or acquisitions may nevertheless reduce our cash available for distribution due to the following factors:

• mistaken assumptions about storage capacity, deliverability, base gas needs, geological integrity, revenues, synergies, costs (including operating and administrative, capital, debt and equity costs), customer demand, growth potential, assumed liabilities and other factors;

• the failure to receive cash flows from an growth project or newly acquired asset due to delays in the commencement of operations for any reason;

• unforeseen operational issues or the realization of liabilities that were not known to us at the time the acquisition or growth project was completed; 

• the inability to attract new customers or retain acquired customers to the extent assumed in connection with the acquisition or growth project; 

• the failure to successfully integrate growth projects or acquired assets or businesses into our operations and/or the loss of key employees; or 

• the impact of regulatory, environmental, political and legal uncertainties that are beyond our control.

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If we complete future growth projects or acquisitions, our capitalization and results of operations may change significantly, and you will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of these funds and other resources. If any growth projects or acquisitions we ultimately complete are not accretive to our cash available for distribution, our ability to make distributions may be reduced.

If we are unable to obtain needed capital or financing on satisfactory terms to fund expansions of our asset base, our ability to pay cash distributions may be diminished or our financial leverage could increase.

In order to expand our asset base, we will need to make expansion capital expenditures. If we do not make sufficient or effective expansion capital expenditures, we will be unable to expand our business operations and may be unable to raise the level of our cash distributions. To fund our expansion capital expenditures, we will be required to use cash from our operations or incur borrowings or sell additional common units or other limited partner interests. Such uses of cash from operations will reduce cash available for distribution to our common unitholders. Our ability to obtain bank financing or to access the capital markets for future equity or debt offerings may be limited by our financial condition at the time of any such financing or offering and the covenants in our debt agreements, as well as by general economic conditions and contingencies and uncertainties that are beyond our control. Even if we are successful in obtaining the necessary funds, the terms of such financings could limit our ability to pay distributions to our common unitholders. In addition, incurring additional debt may significantly increase our interest expense and financial leverage, and issuing additional limited partner interests may result in significant common unitholder dilution and increase the aggregate amount of cash required to maintain the then-current distribution rate, which could materially decrease our ability to pay distributions at the then-current distribution rate. Moreover, we do not have any commitment with any of our affiliates, including Inergy, to fund our cash flow deficits or provide other direct or indirect financial assistance to us.

Increased competition could have a negative impact on the demand for our services, which could adversely affect our financial results.

We compete primarily with other providers of storage and transportation services that own or operate natural gas and NGL storage facilities and natural gas pipelines. Such competitors include independent storage developers and operators, LDCs, interstate and intrastate natural gas transmission companies with storage facilities connected to their pipelines, and other midstream companies. Some of our competitors have greater financial, managerial and other resources than we do and control substantially more storage and transportation capacity than we do. In addition, our customers may develop their own storage and transportation assets in lieu of using ours. FERC has adopted a policy that favors authorization of new storage projects, and there are numerous natural gas storage options in the Northeast geographic market. Pending and future construction projects, if and when brought on-line, may also compete with our natural gas storage operations. Such projects may include FERC-certificated storage expansions and greenfield construction projects.

We also compete with the numerous alternatives to storage available to customers, including pipeline balancing/no-notice services, seasonal/swing services provided by pipelines and marketers and on-system LNG facilities. Natural gas as a fuel also competes with other forms of energy available to end-users, including electricity, coal and liquid fuels. Increased demand for such forms of energy at the expense of natural gas could lead to a reduction in demand for natural gas storage and transportation services.

If our competitors substantially increase the resources they devote to the development and marketing of competitive services or substantially decrease the prices at which they offer their services, we may be unable to compete effectively. Some of these competitors may expand or construct new storage or transportation assets that would create additional competition for us. The expansion of storage or transportation assets and construction activities of our competitors could result in storage or transportation capacity in excess of actual demand, which could reduce the demand for our services, and potentially reduce the rates that we receive for our services.

All of these competitive pressures could make it more difficult for us to retain our existing customers and/or attract new customers as we seek to expand our business, which could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions. In addition, competition could intensify the negative impact of factors that decrease demand for natural gas and NGL storage and transportation in our markets, such as adverse economic conditions, weather, higher fuel costs and taxes or other governmental or regulatory actions that directly or indirectly increase the cost or limit the use of natural gas.

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We expect to derive a significant portion of our revenues from a limited number of customers, and the loss of one or more of these customers could result in a significant loss of revenues and cash flow.

We expect to derive a significant portion of our revenues and cash flow from a limited number of customers. For the fiscal year ended September 30, 2012, ConEd accounted for approximately 14% of our total revenue. The loss, nonpayment, nonperformance or impaired creditworthiness of one of our large customers could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions.

We are exposed to the credit risk of our customers in the ordinary course of our business.

We extend credit to our customers as a normal part of our business. As a result, we are exposed to the risk of loss resulting from the nonpayment and/or nonperformance of our customers. While we have established credit policies that include assessing the creditworthiness of our customers as permitted by our FERC-approved gas tariffs and requiring appropriate terms or credit support from them based on the results of such assessments, there can be no assurance that we have adequately assessed the creditworthiness of our existing or future customers or that there will not be unanticipated deterioration in their creditworthiness. Resulting nonpayment and/or nonperformance by our customers could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions.

Additionally, in instances where we loan natural gas to third parties, the magnitude of our credit risk is significantly increased, as the failure of the third party to return the loaned volumes would result in losses equal to the full value of the loaned natural gas rather than, in the case of firm storage or hub services contracts, losses equal to fees on volumes nominated for injection or withdrawal.

The fees charged by us to third parties under storage and transportation agreements may not escalate sufficiently to cover increases in costs, and those agreements may be suspended in some circumstances.

Our costs may increase at a rate greater than the rate that the fees we charge to third parties increase pursuant to our contracts with them. In addition, some third parties' obligations under their agreements with us may be permanently or temporarily reduced upon the occurrence of certain events, some of which are beyond our control, including force majeure events wherein the supply of natural gas is curtailed or cut off. Force majeure events include (but are not limited to) revolutions, wars, acts of enemies, embargoes, import or export restrictions, strikes, lockouts, fires, storms, floods, acts of God, explosions, mechanical or physical failures of our equipment or facilities or those of third parties. If the escalation of fees is insufficient to cover increased costs or if any third party suspends or terminates its contracts with us, our business, financial condition, results of operations and ability to make distributions could be materially adversely affected.

Our business involves many hazards and risks, some of which may not be fully covered by insurance.

Our operations are subject to all of the risks and hazards inherent in the natural gas and NGL storage and transportation businesses, including:

• subsidence of the geological structures where we store natural gas and NGLs; 

• risks and hazards inherent in drilling operations associated with the development of new caverns; 

• problems maintaining the wellbores and related equipment and facilities that form a part of the infrastructure that is critical to the operation of our storage facilities; 

• damage to our facilities and properties caused by hurricanes, tornadoes, floods, fires and other natural disasters, acts of terrorism, third parties, equipment or material failures, pipeline or vessel ruptures or corrosion, explosions and other incidents;

• leaks, migrations or losses of natural gas and NGLs; 

• collapse of storage caverns;

• operator error;

• environmental pollution or other environmental issues, including drinking water contamination associated with our raw water or water disposal wells; and 

• other industry hazards that could result in the suspension of operations.

These risks could result in substantial losses due to breaches of contractual commitments, personal injury and/or loss of life, damage to and destruction of property and equipment and pollution or other environmental damage. These risks may also result in curtailment or suspension of our operations. A natural disaster or other hazard affecting the areas in which we operate could have a material adverse effect on our operations. We are not fully insured against all risks inherent in our business. In addition, we are not insured against all environmental accidents that might occur, some of which may result in toxic tort claims.

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If a significant accident or event occurs for which we are not fully insured, it could result in a material adverse effect on our business, financial condition, results of operations and ability to make distributions. Furthermore, we may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies may substantially increase. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. Additionally, we may be unable to recover from prior owners of our assets, pursuant to our indemnification rights, for potential environmental liabilities.

As a result of these risks and hazards, we have been, and will likely be, a defendant in legal proceedings and litigation arising in the ordinary course of business. We maintain insurance policies with insurers in such amounts and with such coverages and deductibles as we believe are reasonable and prudent. However, our insurance may not be adequate to protect us from all material expenses related to potential future claims for personal injury and property damage.

In addition, we share insurance coverage with Inergy, for which we reimburse Inergy pursuant to the terms of the omnibus agreement. To the extent Inergy experiences covered losses under the insurance policies, the limit of our coverage for potential losses may be decreased.

Restrictions in our revolving credit facility could adversely affect our business, financial condition, results of operations and ability to make distributions.

We have a $600 million credit facility (expandable up to $750 million), with a maturity date in December 2016. Our revolving credit facility will be available to fund working capital and our growth projects, make acquisitions and for general partnership purposes.

Our revolving credit facility contains various covenants and restrictive provisions that will limit our ability to, among other things:

• incur additional debt;

• make distributions on or redeem or repurchase units;

• make certain investments and acquisitions; 

• incur or permit certain liens to exist; 

• enter into certain types of transactions with affiliates;

• merge, consolidate or amalgamate with another company; and 

• transfer or otherwise dispose of assets.

Furthermore, the revolving credit facility contains covenants requiring us to maintain certain financial ratios. For example, our revolving credit facility requires maintenance of a consolidated leverage ratio (as defined in our credit agreement) of not more than 5.00 to 1.00 and an interest coverage ratio (as defined in our credit agreement) of not less than 2.50 to 1.00. Borrowings under our revolving credit facility are secured by (i) pledges of the equity interests of, and guarantees by, substantially all of our existing and future subsidiaries, and (ii) liens on substantially all of our real and personal property.

The provisions of our revolving credit facility may affect our ability to obtain future financing and pursue attractive business opportunities and our flexibility in planning for, and reacting to, changes in business conditions. In addition, a failure to comply with the provisions of our revolving credit facility could result in an event of default, which could enable our lenders, subject to the terms and conditions of the revolving credit facility, to declare any outstanding principal of that debt, together with accrued interest, to be immediately due and payable. If the payment of any such debt is accelerated, our assets may be insufficient to repay such debt in full, and the holders of our common units could experience a partial or total loss of their investment.

Debt we incur in the future may limit our flexibility to obtain financing and to pursue other business opportunities.

Our future level of debt could have important consequences to us, including the following:

• our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms; 

• our funds available for operations, future business opportunities and distributions to common unitholders will be reduced by that portion of our cash flow required to make interest payments on our debt; 

• we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and

• our flexibility in responding to changing business and economic conditions may be limited.

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Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service any future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets or seeking additional equity capital. We may not be able to effect any of these actions on satisfactory terms or at all.

An unfavorable resolution of the Anadarko litigation could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions.

In June 2010, our predecessor, Inergy Midstream, LLC, 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 our predecessor 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) we refused to enter into definitive agreements under which Anadarko would acquire a 25% interest in the pipeline and, by doing so, we breached the letter of intent, and (iii) by refusing to enter into definitive agreements, we 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.  We filed our answer to Anadarko's complaint in January 2012, and discovery is continuing. An unfavorable resolution of such litigation could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions. In addition, such litigation could divert the attention of management and resources in general from day-to-day operations. For further information regarding this lawsuit, please see Item 3 (Legal Proceedings) of this Part I.

Our operations are subject to compliance with environmental and operational safety laws and regulations that may expose us to significant costs and liabilities.

Our operations are subject to stringent federal, regional, state and local laws and regulations governing health and safety aspects of our operations, the discharge of materials into the environment or otherwise relating to environmental protection. Such environmental laws and regulations impose numerous obligations that are applicable to our operations, including the acquisition of permits to conduct regulated activities, the incurrence of capital expenditures to comply with applicable legal requirements, the application of specific health and safety criteria addressing worker protections and the imposition of restrictions on the generation, handling, treatment, storage, disposal and transportation of materials and wastes. Failure to comply with such environmental laws and regulations can result in the assessment of substantial administrative, civil and criminal penalties, the imposition of remedial liabilities and the issuance of injunctions restricting or prohibiting some or all of our activities. Certain environmental laws impose strict, joint and several liability for costs required to clean up and restore sites where materials or wastes have been disposed or otherwise released. In the course of our operations, generated materials or wastes may have been spilled or released from properties owned or leased by us or on or under other locations where these materials or wastes have been taken for recycling or disposal.

It is also possible that adoption of stricter environmental laws and regulations or more stringent interpretation of existing environmental laws and regulations in the future could result in additional costs or liabilities to us as well as the industry in general or otherwise adversely affect demand for our services and salt products. It is also possible that adoption of stricter environmental laws and regulations or more stringent interpretation of existing environmental laws and regulations in the future could result in additional costs or liabilities to us or our customers and also adversely affect demand for the natural gas, NGLs or salt products.

Climate change legislation or regulations restricting emissions of greenhouse gases could result in increased operating and capital costs and reduced demand for our services.

In December 2009, the EPA determined that emissions of carbon dioxide, methane and other greenhouse gases (GHGs) present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth's atmosphere and other climatic changes. Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of GHGs under existing provisions of the federal Clean Air Act. The EPA has adopted two sets of rules regulating GHG emissions under the Clean Air Act, one of which requires a reduction in emissions of GHGs from motor vehicles and the other of which regulates emissions of GHGs from certain large stationary sources, effective January 2, 2011, which could require greenhouse emission controls for those sources. The EPA has also adopted rules requiring the reporting of GHG emissions from specified large GHG emission sources on an annual basis, beginning in 2011 for

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emissions occurring after January 1, 2010, as well as certain onshore oil and natural gas production, processing, transmission, storage and distribution facilities on an annual basis, beginning in 2012 for emissions occurring in 2011.

In addition, the U.S. Congress has from time to time considered adopting legislation to reduce emissions of GHGs, and almost one-half of the states have already taken legal measures to reduce emissions of GHGs primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall GHG emission reduction goal.

The adoption of legislation or regulatory programs to reduce emissions of GHGs could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas that is produced, which may decrease demand for our storage services. Consequently, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on our business, financial condition and results of operations.

Increases in interest rates could adversely impact demand for our storage capacity, our ability to issue equity or incur debt for acquisitions or other purposes, and our ability to make cash distributions at our intended levels.

There is a financing cost for our customers to store natural gas or NGLs in our storage facilities. That financing cost is impacted by the cost of capital or interest rate incurred by the customer in addition to the commodity cost of the natural gas or NGLs in inventory. Absent other factors, a higher financing cost adversely impacts the economics of storing natural gas or NGLs for future sale. As a result, a significant increase in interest rates could adversely affect the demand for our storage capacity independent of other market factors.

In addition, interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. As with other yield-oriented securities, our common unit price is impacted by the level of our cash distributions and our implied distribution yield. The distribution yield is often used by investors to compare and rank yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our common units, and a rising interest rate environment could have an adverse impact on our common unit price, our ability to issue equity or incur debt for acquisitions or other purposes, and our ability to make cash distributions at our intended levels.

If we are unable to diversify our assets and geographic locations, our ability to make distributions to our common unitholders could be adversely affected.

We rely solely on revenues generated from storage and transportation assets that we own, which are located exclusively in the Northeast region of the United States.  Due to our lack of diversification in asset location and the storage-heavy nature of our existing asset base, an adverse development in these businesses or areas, including adverse developments due to catastrophic events, weather and decreases in demand for natural gas, could have a significantly greater impact on our results of operations and cash available for distribution to our common unitholders than if we maintained more diverse assets and locations.

Our growth strategy includes acquiring entities with lines of business that are distinct and separate from our existing operations, which could subject us to additional business and operating risks.

Consistent with our announced growth strategy and pending acquisition of Rangeland Energy, we may acquire assets that have operations in new and distinct lines of business from our existing operations. Integration of new business segments is a complex, costly and time-consuming process and may involve assets in which we have limited operating experience. Failure to timely and successfully integrate acquired entities' new lines of business with our existing operations may have a material adverse effect on our business, financial condition or results of operations. The difficulties of integrating new business segments with existing operations include, among other things:

• operating distinct business segments that require different operating strategies and different managerial expertise;

• the necessity of coordinating organizations, systems and facilities in different locations;

• integrating personnel with diverse business backgrounds and organizational cultures; and

• consolidating corporate and administrative functions.

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In addition, the diversion of our attention and any delays or difficulties encountered in connection with the integration of the new business segments, such as unanticipated liabilities or costs, could harm our existing business, results of operations, financial condition or prospects. Furthermore, new lines of business will subject us to additional business and operating risks, which could have a material adverse effect on our financial condition or results of operations.

We may be unable to successfully integrate our acquisitions.

One of our primary business strategies is to grow through acquisitions. There is no assurance that we will successfully integrate acquisitions into our operations, or that we will achieve the desired profitability from our acquisitions. Failure to successfully integrate these substantial acquisitions could adversely affect our operations. The difficulties of combining the acquired operations include, among other things: (i) operating a significantly larger organization; (ii) coordinating geographically disparate organizations, systems and facilities; (iii) integrating personnel from diverse business backgrounds and organizational cultures; (iv) consolidating corporate, technological and administrative functions; (v) integrating internal controls, compliance under the Sarbanes-Oxley Act of 2002 and other corporate governance matters; (vi) the diversion of management's attention from other business concerns; (vii) customer or key employee loss from the acquired businesses; and (viii) potential environmental or regulatory liabilities and title problems. In addition, we may not realize all of the anticipated benefits from our acquisitions, such as cost-savings and revenue enhancements, for various reasons, including difficulties integrating operations and personnel, higher costs, unknown liabilities and fluctuations in markets.

If we fail to maintain an effective system of internal controls, we may not be able to report our financial results accurately or prevent fraud, which would likely have a negative impact on the market price of our common units.

We are subject to the public reporting requirements of the Securities Exchange Act of 1934, as amended (the Exchange Act). Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and to operate successfully as a publicly traded partnership. Our efforts to maintain our internal controls may not be successful, and we may be unable to maintain effective controls over our financial processes and reporting in the future or to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002, which we refer to as Section 404. For example, Section 404 requires us, among other things, to annually review and report on, and our independent registered public accounting firm to attest to, the effectiveness of our internal controls over financial reporting. Any failure to develop, implement or maintain effective internal controls or to improve our internal controls could harm our operating results or cause us to fail to meet our reporting obligations. Given the difficulties inherent in the design and operation of internal controls over financial reporting, we can provide no assurance as to our, or our independent registered public accounting firm's, conclusions about the effectiveness of our internal controls, and we may incur significant costs in our efforts to comply with Section 404. Ineffective internal controls will subject us to regulatory scrutiny and a loss of confidence in our reported financial information, which could have an adverse effect on our business and would likely have a negative effect on the trading price of our common units.

A change of control could result in us facing substantial repayment obligations under our credit facility.

Our credit agreement contains provisions relating to change of control of our general partner and our partnership. If these provisions are triggered, our outstanding bank indebtedness may become due. In such an event, there is no assurance that we would be able to pay the indebtedness, in which case the lenders under our credit facility would have the right to foreclose on our assets, which would have a material adverse effect on us. There is no restriction on the ability of our general partners to enter into a transaction which would trigger the change of control provisions.

Risks Inherent in an Investment in Us

We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including reimbursements to our general partner and its affiliates, to enable us to pay quarterly distributions to our common unitholders.

We may not have sufficient cash each quarter to continue payments consistent with the full amount of our initial quarterly distribution of $0.37 per unit, or $1.48 per unit per year. The amount of cash we can distribute on our common units principally depends upon the amount of cash we generate from our operations and payments of fees and expenses. Before we pay any distributions on our common units, we will establish reserves and pay fees and expenses, including reimbursements to our general partner and its affiliates, including Inergy, for all expenses they incur and payments they make on our behalf. These amounts will include reimbursements for administrative costs, such as compensation expense for those persons who provide services necessary to run our business, and insurance expenses. These costs will reduce the amount of cash available to pay distributions to our common unitholders.

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The amount of cash we can distribute on our common units will fluctuate from quarter to quarter based on, among other things:

• the rates we charge for storage and transportation services and the amount of services our customers purchase from us, which will be affected by, among other things, the overall balance between the supply of and demand for natural gas, governmental regulation of our rates and services, and our ability to obtain permits for growth projects;

• force majeure events that damage our or third-party pipelines, facilities, related equipment and surrounding properties;

• prevailing economic and market conditions;

• governmental regulation, including changes in governmental regulation in our industry; and

• changes in tax laws.

In addition, the actual amount of cash we will have available for distribution will depend on other factors, some of which are beyond our control, including: the level and timing of capital expenditures we make; the cost of acquisitions; our debt service requirements and other liabilities; fluctuations in our working capital needs; our ability to borrow funds and access capital markets; restrictions contained in our debt agreements; and the amount of cash reserves established by our general partner.

Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow and make acquisitions.

We expect that we will distribute all of our available cash to our common unitholders and will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. As a result, to the extent we are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow.

In addition, because we distribute all of our available cash, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are be no limitations in our partnership agreement, or in our revolving credit facility, on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, may impact the available cash that we have to distribute to our common unitholders.

We may issue additional units without common unitholder approval, which would dilute existing common unitholder ownership interests.

Our partnership agreement does not limit the number of additional limited partner interests we may issue at any time without the approval of our common unitholders. The issuance of additional common units or other equity interests of equal or senior rank will have the following effects:

• our existing common unitholders' proportionate ownership interest in us will decrease; 

• the amount of cash available for distribution on each common unit may decrease; 

• the ratio of taxable income to distributions may increase; 

• the relative voting strength of each previously outstanding common unit may be diminished; and 

• the market price of the common units may decline.

Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors, which could reduce the price at which our common units will trade.

Unlike the holders of common stock in a corporation, our common unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management's decisions regarding our business. Our common unitholders will have no right on an annual or ongoing basis to elect our general partner or its board of directors. The board of directors of our general partner, including the independent directors, is chosen entirely by Inergy, as a result of it owning our general partner, and not by our common unitholders. Unlike publicly traded corporations, we will not conduct annual meetings of our common unitholders to elect directors or conduct other matters routinely conducted at annual meetings of stockholders of corporations. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

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Common unitholders may have liability to repay distributions and in certain circumstances may be personally liable for the obligations of the partnership.

Under certain circumstances, common unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act (the "Delaware Act"), we may not make a distribution to our common unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. A purchaser of units who becomes a limited partner is liable for the obligations of the transferring limited partner to make contributions to the partnership that are known to the purchaser of units at the time it became a limited partner and for unknown obligations if the liabilities could be determined from the partnership agreement. A purchaser of common units who becomes a limited partner is liable for the obligations of the transferring limited partner to make contributions to the partnership that are known to the purchaser of the common units at the time it became a limited partner and for unknown obligations if the liabilities could be determined from the partnership agreement. Liabilities to partners on account of their partnership interests and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.

It may be determined that the right, or the exercise of the right by the limited partners as a group, to (i) remove or replace our general partner, (ii) approve some amendments to our partnership agreement or (iii) take other action under our partnership agreement constitutes “participation in the control” of our business. A limited partner that participates in the control of our business within the meaning of the Delaware Act may be held personally liable for our obligations under the laws of Delaware to the same extent as our general partner. This liability would extend to persons who transact business with us under the reasonable belief that the limited partner is a general partner. Neither our partnership agreement nor the Delaware Act specifically provides for legal recourse against our general partner if a limited partner were to lose limited liability through any fault of our general partner.

The amount of cash we have available for distribution to common unitholders depends primarily on our cash flow and not solely on profitability, which may prevent us from making cash distributions during periods when we record net income.

The amount of cash we have available for distribution depends primarily upon our cash flow, including cash flow from reserves and working capital or other borrowings, and not solely on profitability, which will be affected by non-cash items. As a result, we may pay cash distributions during periods when we record net losses for financial accounting purposes and may not pay cash distributions during periods when we record net income.

Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.

Our partnership agreement restricts unitholders' voting rights by providing that any units held by a person or group that owns 20% or more of any class of units then outstanding, other than our general partner and its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot vote on any matter.

Reimbursements due to our general partner and its affiliates for services provided to us or on our behalf will reduce cash available for distribution to our common unitholders. The amount and timing of such reimbursements will be determined by our general partner.

Prior to making any distribution on our common units, we will reimburse our general partner and its affiliates, including Inergy, for all administrative costs and other expenses they incur and payments they make on our behalf pursuant to the omnibus agreement. Under the omnibus agreement, we will reimburse our general partner and its affiliates for all expenses incurred on our behalf, including administrative costs, such as compensation expense for those persons who provide services necessary to run our business, and insurance expenses. As of September 30, 2012, we reimbursed our general partner and its affiliates approximately $15.3 million in fiscal year 2012 (including $9.0 million in reimbursements of direct personnel related expenses). Neither our partnership agreement nor the omnibus agreement limits the amount of expenses for which our general partner and its affiliates may be reimbursed. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us. The reimbursement of expenses and payment of fees, if any, to our general partner and its affiliates will reduce the amount of available cash to pay cash distributions to our common unitholders.

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The credit and risk profile of our general partner and its owner, Inergy, could adversely affect our credit ratings and risk profile, which could increase our borrowing costs or hinder our ability to raise capital.

The credit and business risk profiles of our general partner and Inergy may be factors considered in credit evaluations of us. This is because our general partner, which is owned by Inergy, controls our business activities, including our cash distribution policy and growth strategy. Any adverse change in Inergy's financial condition, including the degree of its financial leverage and its dependence on cash flow from us to service its debt, may adversely affect our credit ratings and risk profile.

If we were to seek a credit rating in the future, our credit rating may be adversely affected by the leverage of our general partner or Inergy, as credit rating agencies such as Standard & Poor's Ratings Services and Moody's Investors Service may consider the leverage and credit profile of Inergy and its affiliates because of their ownership interest in and control of us. Any adverse effect on our credit rating would increase our cost of borrowing or hinder our ability to raise financing in the capital markets, which would impair our ability to grow our business and make distributions to common unitholders.

Our general partner has a limited call right that may require unitholders to sell their common units at an undesirable time or price.

If at any time our general partner and its affiliates own more than 85% of the outstanding common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price equal to the greater of (i) the average of the daily closing prices per limited partner interest of the class purchased for the 20 consecutive trading days immediately prior to the date three days before the date our general partner first mails notice of its election to purchase those limited partner interests, and (ii) the highest price paid by our general partner or any of its affiliates for any limited partner interests of the class purchased during the 90-day period preceding the date that the notice is mailed. As a result, unitholders may be required to sell their common units at an undesirable time or price and may not receive any return or a negative return on their investment. Unitholders may also incur a tax liability upon a sale of their common units. Our general partner is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon exercise of the limited call right. There is no restriction in our partnership agreement that prevents our general partner from issuing additional common units and exercising its call right. If our general partner exercised its limited call right, the effect would be to take us private and, if the units were subsequently deregistered, we would no longer be subject to the reporting requirements of the Exchange Act. As of September 30, 2012 Inergy owns, directly or indirectly, an aggregate of 75% of our common units.

Risks Inherent in Our Structure and Relationship with Inergy

Inergy controls our general partner, which has sole responsibility for conducting our business and managing our operations. Our general partner and its affiliates, including Inergy, have conflicts of interest with us and limited duties, and they may favor their own interests to the detriment of us and our common unitholders.

Inergy owns and controls our general partner and appoints all of the directors of our general partner. Although our general partner has a duty to manage our partnership in a manner it believes is in our best interests, the executive officers and directors of our general partner have a fiduciary duty to manage our general partner in a manner beneficial to Inergy. Therefore, conflicts of interest may arise between our general partner and its affiliates, including Inergy, on the one hand, and us and our common unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of its affiliates over the interests of our common unitholders.

Inergy and other affiliates of our general partner may compete with us.

Our partnership agreement provides that our general partner will be restricted from engaging in any business activities other than acting as our general partner and those activities incidental to its ownership of interests in us. Affiliates of our general partner, including Inergy, are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us. Inergy currently holds interests in, and may make investments in and purchases of, entities that acquire, own and operate natural gas and NGL storage and transportation businesses. In addition, Inergy is entitled under the omnibus agreement to review and has the first option on any third-party acquisition opportunities presented to us or to Inergy and is under no obligation to make acquisition opportunities available to us. These investments and acquisitions may include entities or assets that we would have been interested in acquiring. Therefore, Inergy may compete with us for investment opportunities, and Inergy may own an interest in entities that compete with us.

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Pursuant to the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to our general partner or any of its affiliates, including its executive officers and directors and Inergy. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. This may create actual and potential conflicts of interest between us and affiliates of our general partner and result in less than favorable treatment of us and our common unitholders.

Our general partner intends to limit its liability regarding our contractual and other obligations.

Our general partner intends to limit its liability under our contractual and other obligations so that the counterparties to such arrangements have recourse only against our assets and not against our general partner or its assets. Our general partner may therefore cause us to incur indebtedness or other obligations that are nonrecourse to our general partner. Our partnership agreement provides that any action taken by our general partner to limit its liability is not a breach of our general partner's duties, even if we could have obtained more favorable terms without the limitation on liability. In addition, we are obligated to reimburse or indemnify our general partner to the extent that it incurs obligations on our behalf. Any such reimbursement or indemnification payments would reduce the amount of cash otherwise available for distribution to our common unitholders.

Our partnership agreement restricts the remedies available to our common unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

Our partnership agreement contains provisions that restrict the remedies available to our common unitholders for actions taken by our general partner that might otherwise constitute breaches of duty under state law with respect to fiduciary duties. For example, our partnership agreement provides that:

• whenever our general partner, the board of directors of our general partner or any committee thereof (including the conflicts committee) makes a determination or takes, or declines to take, any other action in their respective capacities, our general partner, the board of directors of our general partner or any committee thereof (including the conflicts committee), as applicable, is required to make such determination, or take or decline to take such other action, in good faith, and is not subject to any higher standard imposed by our partnership agreement, Delaware law or any other law, rule or regulation, or at equity; 

• a determination, other action or failure to act by our general partner, the board of directors of our general partner or any committee thereof (including the conflicts committee) is deemed to be in good faith unless our general partner, the board of directors of our general partner or any committee thereof believed such determination, other action or failure to act was not in the best interests of the partnership; 

• our general partner does not have any liability to us or our common unitholders for decisions made in its capacity as a general partner so long as it acted in good faith; and 

• our general partner and its officers and directors are not be liable for monetary damages to us or our limited partners for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or those other persons acted in bad faith or, in the case of a criminal matter, acted with knowledge that the conduct was unlawful. 

Whenever a conflict arises between our general partner or its affiliates, on the one hand, and us and our limited partners, on the other hand, the resolution or course of action in respect of such conflict of interest shall be permitted and deemed approved by all our limited partners and shall not constitute a breach of our partnership agreement, of any agreement contemplated thereby or of any duty, if the resolution or course of action in respect of such conflict of interest is (i) approved by the conflicts committee of the board of directors of our general partner, although our general partner is not obligated to seek such approval; or (ii) approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner or its affiliates.

In connection with a situation involving a transaction with an affiliate or a conflict of interest, any determination by our general partner must be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by our common unitholders or the conflicts committee then it will be presumed that, in making its decision, taking any action or failing to act, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.

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Unlike many other master limited partnerships, which require at least two independent members of the conflicts committee, our partnership agreement provides that a conflicts committee may be comprised of one or more directors. If we establish a conflicts committee with only one director, your interests may not be as well served as if we had a conflicts committee comprised of at least two independent directors. A single member conflicts committee would not have the benefit of discussion with and input from other independent directors.

Our partnership agreement limits our general partner's duties to holders of our common units.

Our partnership agreement contains provisions that modify and reduce the standards to which our general partner would otherwise be held by state law with respect to fiduciary duties. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner, or otherwise free of contractual or fiduciary duties to us and our common unitholders. This entitles our general partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited partners. Examples of decisions that our general partner may make in its individual capacity include:

• how to allocate business opportunities among us and its affiliates; 

• whether to exercise its limited call right; 

• how to exercise its voting rights with respect to any units it owns; 

• whether to exercise its registration rights; 

• whether to exercise its registration rights;

• whether or not to consent to any merger or consolidation of us or amendment to the partnership agreement.

By purchasing a common unit, a common unitholder is treated as having consented to the provisions in the partnership agreement, including the provisions discussed above. 

Inergy may elect to cause us to issue common units to it in connection with a resetting of the quarterly distribution related to its IDRs, without the approval of the conflicts committee of the board of directors of our general partner or the holders of our common units. This election could result in lower distributions to our common unitholders.

Inergy has the right to reset, at a higher level, the quarterly distribution based on our cash distributions at the time of the exercise of the reset election. Following a reset election, the quarterly distribution will be reset to an amount equal to the cash distribution amount per unit for the quarter immediately preceding the reset election (which amount we refer to as the reset quarterly distribution).

If Inergy elects to reset the quarterly distribution, it will be entitled to receive a number of newly issued common units. The number of common units to be issued to Inergy will equal the number of common units that would have entitled the holder to the quarterly cash distribution in the prior quarter equal to the distribution to Inergy on the IDRs in such prior quarter. It is possible that Inergy could exercise this reset election at a time when it is experiencing, or expects to experience, declines in the cash distributions it receives related to its IDRs and may, therefore, desire to be issued common units rather than retain the right to receive incentive distributions based on the quarterly distribution. As a result, a reset election may cause our common unitholders to experience a reduction in the amount of cash distributions that our common unitholders would have otherwise received had we not issued new common units to Inergy in connection with resetting the quarterly distribution.

Even if holders of our common units are dissatisfied, they cannot currently remove our general partner without its consent.

If our common unitholders are dissatisfied with the performance of our general partner, they have limited ability to remove our general partner. Common unitholders are unable to remove our general partner without its consent because Inergy owns a sufficient number of common units to be able to prevent its removal. The vote of the holders of at least two-thirds of all our outstanding common units is required to remove our general partner. Inergy currently owns, directly or indirectly, an aggregate of 75% of our common units.

Our general partner interest and our IDRs may be transferred without common unitholder consent.

Our partnership agreement provides that, at any time, our general partner may transfer all or any of its general partner interest or common units to another person without the consent of our common unitholders, and our common unitholders will have no right to elect our general partner or its directors on an annual or other continuing basis. In addition, Inergy and Inergy Holdings GP, LLC ("Holdings GP"), the indirect owner of Inergy's general partner, have entered into an agreement under which Holdings GP will be required to purchase the entity that controls our general partner in the event that (i) a change of control of Inergy

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occurs at a time when Inergy is entitled to receive less than 50% of all cash distributed with respect to our limited partner interests and IDRs or (ii) through dilution or a distribution to the Inergy common unitholders of Inergy's interests in us, Inergy is entitled to receive less than 25% of all cash distributed with respect to our limited partner interests and IDRs. If the sole member of our general partner transfers its membership interest in our general partner to a third party or Holdings GP acquires the entity that controls our general partner, the third party or Holdings GP, as applicable, would then be in a position to replace the board of directors and executive officers of our general partner with its designees and thereby exert significant control over the decisions taken by the board of directors and executive officers of our general partner. This effectively permits a “change of control” without the vote or consent of the common unitholders. Our partnership agreement also provides that the holder of the IDRs may transfer those interests to a third party at any time without the consent of our common unitholders. Inergy indirectly owns all of our IDRs. If Inergy transfers its IDRs to a third party, Inergy may not have the same incentive to grow our partnership and increase quarterly distributions to common unitholders over time as it would if it had retained ownership of the IDRs.

Tax Risks to Common Unitholders

The tax treatment of publicly traded partnerships is subject to potential legislative, judicial or administrative changes. If we were treated as a corporation for federal income tax purposes, or if we were to become subject to a material amount of state or local taxation, then our cash available for distribution to our unitholders would be substantially reduced.

The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes. A publicly traded partnership such as us may be treated as a corporation for federal income tax purposes unless it satisfies requirements regarding the sources of its income. Based on our current operations we believe that we are treated as a partnership rather than a corporation; however, a change in our business could cause us to be treated as a corporation for federal income tax purposes.

In addition, current law may change so as to cause us to be treated as a corporation for federal income tax purposes. For example, members of Congress have recently considered substantive changes to the existing federal income tax laws that would affect the tax treatment of certain publicly traded partnerships. In addition, because of widespread state budget deficits, several states are evaluating ways to subject partnerships to entity level taxation through the imposition of state income, franchise or other forms of taxation. If any state were to impose a tax upon us as an entity, the cash available to pay distributions would be reduced. We are unable to predict whether any of these changes, or other proposals, will ultimately be enacted.

Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity level taxation for federal, state or local income tax purposes, then the quarterly distribution amount and the target distribution amount will be adjusted to reflect the impact of that law on us.

If we were treated as a corporation for federal income tax purposes, we would be obligated to pay federal income tax on our taxable income at the corporate tax rate, currently a maximum rate of 35%, as well as any applicable state income tax. Distributions to our unitholders generally would be taxed to them in the same manner as distributions from a corporation, and none of our income, gain, loss, deduction or credit would flow through to our unitholders. Because a tax would be imposed upon us as a corporation, our cash available for distribution would be substantially reduced. Therefore, our treatment as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our common units.

If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contest will reduce our cash available for distribution to you.

We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. In addition, the costs of any contest with the IRS will be borne indirectly by you and our general partner because the costs will reduce our cash available for distribution.

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You may be required to pay taxes on your share of our income even if you do not receive cash distributions from us.

Because you will be treated as a partner in us for federal income tax purposes, we will allocate a share of our taxable income to you which could be different in amount than the cash we distribute to you, and you may be required to pay any federal income taxes and, in some cases, state and local income taxes on your share of our taxable income even if you do not receive any cash distributions from us. You may not receive cash distributions from us equal to your share of our taxable income or even equal to the actual tax liability that results from that income.

Tax gain or loss on the disposition of our common units could be more or less than expected.

If you sell your common units, you will recognize a gain or loss equal to the difference between your amount realized and your tax basis in those common units. Because distributions in excess of your allocable share of our total net taxable income result in a reduction in your tax basis in your common units, the amount, if any, of such prior excess distributions with respect to the units you sell will, in effect, become taxable income to you if you sell such units at a price greater than your tax basis in those common units, even if the price you receive is less than your original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture of depreciation deductions. In addition, because the amount realized includes a unitholder's share of our nonrecourse liabilities, if you sell your units, you may incur a tax liability in excess of the amount of cash you receive from the sale.

Tax-exempt entities, regulated investment companies and non-U.S. persons face unique tax issues from owning common units that may result in adverse tax consequences to them.

Investment in common units by tax-exempt entities, including employee benefit plans and individual retirement accounts (known as IRAs), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes imposed at the highest effective applicable tax rate, and non-U.S. persons will be required to file U. S. federal income tax returns and pay tax on their share of our taxable income. If you are a tax-exempt entity or a non-U.S. person, you should consult your tax advisor before investing in our common units.

We treat each purchaser of our common units as having the same tax benefits without regard to the specific common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.

To maintain the uniformity of the economic and tax characteristics of our common units, we have adopted certain depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. These positions may result in an understatement of deductions and an overstatement of income to our unitholders. For example, we do not amortize certain goodwill assets, the value of which has been attributed to certain of our outstanding units. A subsequent holder of those units may be entitled to an amortization deduction attributable to that goodwill under Internal Revenue Code Section 743(b). But, because we cannot identify these units once they are traded by the initial holder, we do not allocate any subsequent holder of a unit any such amortization deduction. This approach may understate deductions available to those unitholders who own those units and may result in those unitholders reporting that they have a higher tax basis in their units than would be the case if the IRS strictly applied Treasury Regulations relating to these depreciation or amortization adjustments. This, in turn, may result in those unitholders reporting less gain or more loss on a sale of their units than would be the case if the IRS strictly applied those Treasury Regulations.

The IRS may challenge the manner in which we calculate our unitholder's basis adjustment under Section 743(b). If so, because the specific unitholders to which this issue relates cannot be identified, the IRS may assert adjustments to all unitholders selling units within the period under audit. A successful IRS challenge to this position or other positions we may take could adversely affect the amount of taxable income or loss allocated to our unitholders. It also could affect the gain from a unitholder's sale of common units or result in audit adjustments to our unitholders' tax returns without the benefit of additional deductions. Consequently, a successful IRS challenge could have a negative impact on the value of the common units.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred.

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The use of this proration method may not be permitted under existing Treasury Regulations. Recently, the U.S. Treasury Department issued proposed Treasury Regulations that provide a safe harbor pursuant to which publicly traded partnerships may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge our proration method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units. If so, that unitholder would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.

If you loan your units to a “short seller” to cover a short sale of units, you may be considered as having disposed of the loaned units, and you may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and you may recognize gain or loss from such disposition. During the period of the loan, any of our income, gain, loss or deduction with respect to those units may not be reportable by you and any cash distributions you receive as to those units could be fully taxable as ordinary income. To assure your status as a partner and avoid the risk of gain recognition from a loan to a short seller you are urged to modify any applicable brokerage account agreements to prohibit your broker from borrowing your units.

The sale or exchange of 50% or more of our capital and profits interests within a twelve-month period will result in the termination of our partnership for federal income tax purposes.

We will be considered to have constructively terminated as a partnership for federal income tax purposes if there is a sale or exchange within a twelve-month period of 50% or more of the total interests in our capital and profits. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest will be counted only once. Our termination would, among other things, result in the closing of our taxable year for all unitholders which could result in us filing two tax returns (and unitholders receiving two Schedule K-1s) for one calendar year. Our termination could also result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a calendar year, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in its taxable income for the year of termination. Our termination would not affect our classification as a partnership for federal income tax purposes, but instead, we would be treated as a new partnership for federal income tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred. Pursuant to an IRS relief procedure a publicly traded partnership that has technically terminated may request special relief which, if granted by the IRS, among other things, would permit the partnership to provide only a single Schedule K-1 to unitholders for the tax years in which the termination occurs.

Our unitholders will likely be subject to state and local taxes and return filing requirements in states where they do not live as a result of investing in our common units.

In addition to federal income taxes, our unitholders will likely be subject to other taxes, including state and local taxes, unincorporated business taxes, estate, inheritance or intangible taxes and foreign taxes that are imposed by the various jurisdictions in which we do business or own property and in which they do not reside. We own property and conduct business in various parts of the United States. Unitholders may be required to file state and local income tax returns in many or all of the jurisdictions in which we do business or own property. Further, unitholders may be subject to penalties for failure to comply with those requirements. It is our unitholders' responsibility to file all required U. S. federal, state, local and foreign tax returns.

Item 1B. Unresolved Staff Comments.

None.

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Item 2. Properties.

We own the midstream and salt assets described in Item 1, including four natural gas storage facilities (our Stagecoach, Thomas Corners, Steuben and Seneca Lake natural gas storage facilities), two interstate natural gas pipeline facilities (our North-South Facilities and MARC I Pipeline), an intrastate pipeline (the East Pipeline), the Bath NGL storage facility, and US Salt's plant and production facilities. We own these assets in fee title, except that a portion of our North-South Facilities and our Stagecoach and Thomas Corners facilities are subject to lease-leaseback arrangements with local taxing authorities under payment-in-lieu-of-taxes programs.

We believe we have satisfactory title or valid rights to use all of our material properties. Although some of these properties are subject to liabilities and leases, liens for taxes not yet due and payable, encumbrances securing payment obligations under non-competition agreements entered in connection with acquisitions and immaterial encumbrances, easements and restrictions, we do not believe that any of these burdens will materially interfere with our continued use of these properties in our business, taken as a whole. In addition, we believe we have, or are in the process of obtaining, all required material approvals, authorizations, orders, licenses, permits, franchises and consents of, and have obtained or made all required material registrations, qualifications and filings with, the various state and local governmental and regulatory authorities that relate to ownership of our properties or the operation of our business.

Our obligations under our credit facility are secured by liens and mortgages on our fee-owned real and personal property, except that (i) our real property located in New York is not subject to mortgage under our credit facility and (ii) our bank lenders do not have a lien on any of real or personal property comprising the East Pipeline.

Item 3. Legal Proceedings.

In June 2010, our predecessor and CNYOG entered into a letter of intent with 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 our predecessor 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) our predecessor refused to enter into definitive agreements under which Anadarko would acquire a 25% interest in the pipeline and, by doing so, we breached the letter of intent, and (iii) by refusing to enter into definitive agreements, our predecessor 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. 

We filed preliminary objections to the complaint and sought a judgment in our favor and an order dismissing Anadarko's complaint. Following a hearing on our motion to dismiss the Anadarko complaint on December 2, 2011, our motion was denied. We filed our answer to Anadarko's complaint in January 2012 and discovery is continuing. We believe that Anadarko's claims are without merit and intend to vigorously defend themselves in the lawsuit.

We are not a party to any other legal proceeding other than legal proceedings arising in the ordinary course of business. We are also, from time to time, a party to administrative and regulatory proceedings that have arisen in the ordinary course of business. Our regulatory proceedings are described in Item 1 (“Regulation”) of this Report.

Item 4. Mine Safety Disclosures

Not applicable.

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PART II

Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities.

On December 16, 2011, our common units representing limited partner interests began trading on The New York Stock Exchange ("NYSE") under the symbol “NRGM” following our initial public offering. The following table sets forth the range of high and low bid prices of the common units, as reported by the NYSE, as well as the amount of cash distributions declared per common unit for the periods indicated.

Quarters Ended:	Low		High		Cash Distribution Per Unit
Fiscal 2012:
September 30, 2012	$	21.05	$	23.60	$	0.385
June 30, 2012	19.07		21.75		0.380
March 31, 2012	18.69		22.15		0.370
December 31, 2011(1)	17.65		18.95		0.040

(1) Includes the period beginning December 21, 2011 (the closing date of our IPO through December 31, 2011). Accordingly, the $0.04 cash distribution per unit corresponds to a pro-rated quarterly distribution per unit of $0.37.

As of November 7, 2012, we had issued and outstanding 75,151,930 common units, which were held by 31 unitholders of record.

Cash Distribution Policy

We make quarterly distributions to our partners within approximately 45 days after the end of each fiscal quarter in an aggregate amount equal to our available cash for such quarter. Available cash generally means, with respect to each fiscal quarter, all cash on hand at the end of the quarter less the amount of cash that our general partner determines in its reasonable discretion is necessary or appropriate to:

• provide for the proper conduct of our business;

• comply with applicable law, any of our debt instruments, or other agreements; or

• provide funds for distributions to unitholders for any one or more of the next four quarters;

plus all cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter. Working capital borrowings are generally borrowings that are made under our revolving credit facility and in all cases are used solely for working capital purposes or to pay distributions to partners.

On November 14, 2012, we paid a distribution of $0.385 per common unit ($1.54 per common unit on an annualized basis) to all unitholders of record on November 7, 2012.

Incentive Distribution Rights

IDRs represent the right to receive 50% of quarterly distributions of available cash after the initial quarterly distribution has been achieved. We issued IDRs to Inergy Midstream Holdings, L.P., a wholly-owned subsidiary of Inergy, as part of our initial public offering, and Inergy Midstream Holdings, L.P. continues to hold 100% of our IDRs.

Recent Sales of Unregistered Securities

On May 14, 2012, we issued 473,707 common units to Inergy for partial consideration for the purchase of US Salt. The common units were issued in a private issuance exempt from registration under Section 4(2) of the Securities Act and Rule 506 of Regulation D. See Note 10 to our Consolidated Financial Statements for additional information regarding the acquisition of US Salt.

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Equity Compensation Plan Information

The following table sets forth in tabular format, a summary of our equity compensation plan information as of September 30, 2012:

Plan category	Number of securities to be issued upon exercise of outstanding options, warrants and rights	Weighted- average exercise price of outstanding options, warrants and rights		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
	(a)	(b)		(c)
Equity compensation plans approved by security holders(1)	—	$	—	7,049,277
Equity compensation plans not approved by security holders	—	—		—
Total	—	$	—	7,049,277

(1) Equity Compensation plans approved by the security holders prior to our IPO.

Item 6. Selected Financial Data.

The following tables set forth selected consolidated financial data and other operating data of Inergy Midstream, L.P. The selected historical consolidated financial data of Inergy Midstream, L.P. as of and for the years ended September 30, 2012, 2011, 2010, 2009, and 2008, are derived from the audited consolidated financial statements of Inergy Midstream, L.P (formerly Inergy Midstream, LLC), and are retrospectively adjusted to include the historical balances of US Salt as described in note 10 to the Consolidated Financial Statements in Item 15.

“EBITDA” shown in the table below is defined as income before income taxes, plus net interest expense and depreciation and amortization expense. Adjusted EBITDA represents EBITDA excluding the gain or loss on the disposal of assets, long-term incentive and equity compensation expenses and transaction costs. Transaction costs are third party professional fees and other costs that are incurred in conjunction with closing a transaction. EBITDA and Adjusted EBITDA should not be considered an alternative to net income, income before income taxes, cash flows from operating activities, or any other measure of financial performance calculated in accordance with generally accepted accounting principles as those items are used to measure operating performance, liquidity or ability to service debt obligations. We believe that EBITDA provides additional information for evaluating our ability to make the quarterly distribution and is presented solely as a supplemental measure. We believe that Adjusted EBITDA provides additional information for evaluating our financial performance without regard to our financing methods, capital structure and historical cost basis. EBITDA and Adjusted EBITDA, as we define them, may not be comparable to EBITDA and Adjusted EBITDA or similarly titled measures used by other corporations or partnerships.

The data in the following tables should be read together with and is qualified in its entirety by reference to, the historical consolidated financial statements and the accompanying notes included in this report. The tables should be read together with “Management's Discussion and Analysis of Financial Condition and Results of Operations” under Item 7.

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	Inergy Midstream L.P. (formerly Inergy Midstream, LLC) Year Ended September 30, (in millions, except unit and per unit data)
	2012			2011		2010			2009			2008
Statement of Operations Data:
Revenues	$	189.8		$	163.2	$	146.9		$	136.5		$	87.5
Costs and expenses:
Service/product related costs	41.4			46.4		42.0			48.9			15.4
Operating and administrative	30.4			19.4		19.2			14.1			11.8
Depreciation and amortization	50.5			43.9		42.4			35.4			24.7
(Gain) loss on disposal of assets	—			—		0.9			—			(1.9		)
	122.3			109.7		104.5			98.4			50.0
Operating income	67.5			53.5		42.4			38.1			37.5
Interest expense, net	(1.8		)	—		—			—			—
Other income	—			—		0.8			—			0.8
Net income	65.7			53.5		43.2			38.1			38.3
Net income attributable to non-controlling partners	—			—		(0.8		)	(1.4		)	(1.4		)
Net income attributable to partners	$	65.7		$	53.5	$	42.4		$	36.7		$	36.9
Net income per limited partner unit:
Basic	$	0.58
Diluted	$	0.58
Weighted-average limited partners’ units outstanding (in thousands):
Basic	74,768
Diluted	74,768
Cash distributions paid per unit(a)	$	0.79

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	2012			2011			2010			2009			2008
Balance Sheet Data (end of period):
Total assets	$	1,027.9		$	813.7		$	667.5		$	663.0		$	605.3
Total debt, including current portion	416.5			—			—			8.3			10.9
Partners’ capital	555.3			660.8			547.8			511.5			504.8
Other Financial Data:
EBITDA (unaudited)	$	118.0		$	97.4		$	85.6		$	73.5		$	63.0
Adjusted EBITDA (unaudited)	125.2			99.6			90.2			74.3			61.6
Net cash provided by operating activities	132.7			96.3			94.3			71.9			60.6
Net cash used in investing activities	(328.3		)	(165.2		)	(54.7		)	(52.8		)	(106.6		)
Net cash provided by (used in) financing activities	195.6			68.9			(43.2		)	(18.4		)	48.9
Maintenance capital expenditures(b) (unaudited)	4.5			5.0			1.6			0.9			0.2
Other Operating Data (unaudited):
Natural gas storage capacity (Bcf)	41.0			41.0			39.5			32.5			32.5
% of total revenue (excluding US Salt revenue) generated from firm contracts	89		%	94		%	98		%	96		%	98		%
Reconciliation of Net Income to EBITDA and Adjusted EBITDA:
Net income	$	65.7		$	53.5		$	43.2		$	38.1		$	38.3
Depreciation and amortization	50.5			43.9			42.4			35.4			24.7
Interest expense, net	1.8			—			—			—			—
EBITDA	$	118.0		$	97.4		$	85.6		$	73.5		$	63.0
Long-term incentive and equity compensation expense	6.5			1.8			3.5			0.8			0.5
(Gain) loss on disposal of assets	—			—			0.9			—			(1.9		)
Transaction costs(c)	0.7			0.4			0.2			—			—
Adjusted EBITDA	$	125.2		$	99.6		$	90.2		$	74.3		$	61.6
Reconciliation of Net Cash Provided by Operating Activities to EBITDA and Adjusted EBITDA:
Net cash provided by operating activities	$	132.7		$	96.3		$	94.3		$	71.9		$	60.6
Net changes in working capital balances	(9.2		)	1.1			(7.8		)	1.6			0.5
Amortization of deferred financing costs	(0.8		)	—			—			—			—
Interest expense, net	1.8			—			—			—			—
Long-term incentive and equity compensation expense	(6.5		)	—			—			—			—
Gain (loss) on disposal of assets	—			—			(0.9		)	—			1.9
EBITDA	$	118.0		$	97.4		$	85.6		$	73.5		$	63.0
Long-term incentive and equity compensation expense	6.5			1.8			3.5			0.8			0.5
(Gain) loss on disposal of assets	—			—			0.9			—			(1.9		)
Transaction costs(c)	0.7			0.4			0.2			—			—
Adjusted EBITDA	$	125.2		$	99.6		$	90.2		$	74.3		$	61.6

(a) The Company completed its IPO on December 21, 2011. The cash distributions paid per unit includes a $0.04 cash distribution per limited partner unit, which corresponds to its initial quarterly cash distribution of $0.37 per quarter ($1.48 annually) and represents the prorated distribution for the period of time from December 21, 2011 through December 31, 2011, the end of the first fiscal quarter. The Company also paid a cash distribution of $0.37 and $0.38 during the third and fourth fiscal quarters, respectively.

(b) Maintenance capital expenditures are defined as those capital expenditures that do not increase operating capacity or revenues from existing levels.

(c) Transaction costs are third party professional fees and other costs that are incurred in conjunction with closing a transaction.

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Forward-Looking Statements

This report, including information included or incorporated by reference in this report, 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, but not limited to, (i) we expect to place the MARC I Pipeline into service on December 1, 2012; (ii) we expect to sell the 100,000 Dth/d of turned-back MARC I Pipeline capacity at or near rates payable by the existing MARC I shippers; (iii) we expect to receive in early calendar 2013 the approvals required to construct and operate our Watkins Glen NGL storage development project; (iv) we expect to complete and place the Seneca Lake expansion capacity into service in calendar 2013; (v) we believe Anadarko's claims relating to the MARC I Pipeline are without merit; and (vi) we anticipate completing our acquisition of Rangeland Energy in calendar 2012; 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, natural gas and NGLs;

• weather conditions;

• industry factors that influence the demand for natural gas storage and transportation capacity in the Northeast;

• costs or difficulties related to the integration of our existing businesses and acquisitions may be greater than expected;

• economic conditions;

• the availability of natural gas and NGLs, and the price of natural gas and NGLs, to consumers compared to the price of alternative and competing fuels;

• environmental claims;

• interest rates; and

• the price and availability of debt and equity financing.

We have described under “Risk Factors” additional factors that could cause actual results to be materially different from those described in the forward-looking statements. Other factors that we have not identified in this report could also have this effect. You are cautioned not to put undue reliance on any forward-looking statement, which speaks only as of the date it was made.

Overview

We are a predominantly fee-based, growth-oriented limited partnership that develops, acquires, owns and operates midstream energy assets. We own and operate natural gas and NGL storage and transportation facilities and a salt production business located in the Northeast region of the United States. We own and operate four natural gas storage facilities that have an aggregate working gas storage capacity of 41.0 Bcf; natural gas pipeline facilities with 905 MMcf/d of transportation capacity; a 1.5 million barrel NGL storage facility; and US Salt, a leading solution mining and salt production company.

Our primary business objective is to increase the cash distributions that we pay to our unitholders by growing our business through the development, acquisition and operation of additional midstream assets near production and demand centers. An integral part of our growth strategy is the continued development of our platform of interconnected natural gas assets in the Northeast that can be operated as an integrated storage and transportation hub. For example, because we believe storage and transportation customers value operating flexibility, we expect to increase the interconnectivity between our natural gas assets and third-party pipelines, thereby resulting in increased demand for our services. We also expect our growth strategy to reflect our desire to diversify our operations, in terms of both our geographic footprint and the type of midstream services we provide to customers.

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Organic growth projects, including both expansions and greenfield development projects, have recently provided cost-effective options for us to grow our midstream infrastructure base. In general, purchasers of midstream 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 business quickly and successfully. We therefore expect to grow our business in the near term through both organic growth projects and acquisitions.

Our operations include (i) the storage and transportation of natural gas and NGLs, which are reported in our storage and transportation reporting segment, and (ii) US Salt's production and wholesale distribution of evaporated salt products, which are reported in our salt reporting segment. The cash flows from our storage and transportation operations are predominantly fee-based under one to ten year contracts with creditworthy counterparties and, therefore, are generally economically stable and not significantly affected in the short term by changing commodity prices, seasonality or weather fluctuations. The 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.

The majority of our operating cash flows are generated by our natural gas storage operations. 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. This demand growth is primarily driven by the natural gas-fired electric generation sector and conversion from petroleum-based fuels. Due to the high percentage of our cash flows generated by our natural gas storage operations, we have attempted to diversify our asset base recently by developing natural gas transportation assets and NGL storage assets. Our pending acquisition of Rangeland Energy also illustrates how we expect to diversify our asset base through acquisitions.

Our ability to market available transportation capacity is impacted by supply and demand for natural gas, competition from other pipelines, natural gas price volatility, the price differential between physical locations on our pipeline systems (basis spreads), economic conditions, and other factors. Our transportation facilities have benefited from, and we expect our pipelines to continue to benefit from, the development of the Marcellus shale as a significant supply basin. As LDCs and other customers increasingly utilize short-haul transportation options to satisfy their transportation needs, we believe the location of our transportation assets relative to the Marcellus shale will enable us to realize additional benefits.

Our long-term profitability will be influenced primarily by (i) successfully executing our existing development projects and continuing to develop new organic growth projects in our markets; (ii) pursuing strategic acquisitions from third parties, including Inergy, to grow our business; (iii) contracting and re-contracting storage and transportation capacity with our customers; and (iv) managing increasingly difficult regulatory processes, particularly in permitting and approval proceedings at the federal and state levels.

We remain encouraged by our inventory of growth projects, such as the Watkins Glen NGL storage development project and the Commonwealth Pipeline project. These projects illustrate our diversification objectives, our desire to deploy capital prudently, our strong belief in the markets in which we operate, and our goal of integrating our assets when possible. Importantly, we also believe these projects demonstrate our commitment to our customers and their existing and forecast needs. In addition, many of our growth projects provide a basis for incremental growth, such as our ability to potentially expand the MARC I Pipeline through the installation of additional compression.

Although it has become more difficult to obtain the authorizations required to develop or expand natural gas and NGL storage and transportation assets in the Northeast, we remain confident that the incremental time and money required to pursue and complete market-driven facilities in the Northeast will deliver meaningful value to our unitholders. The regulatory environment, combined with the location of our assets relative to both high-demand markets and the Marcellus shale play, effectively provides a significant barrier to entry that other market participants may find difficult to overcome.

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How We Evaluate Our Operations

We evaluate our business performance on the basis of the following key measures:

• revenues derived from firm storage contracts and the percentage of physical capacity and / or deliverability sold; 

• revenues derived from transportation contracts and the percentage of physical capacity sold; 

• operating and administrative expenses; and 

• EBITDA and Adjusted EBITDA.

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.

Firm Storage Contracts

A substantial majority of our revenues is derived from storage services we provide under firm contracts. We seek to maximize the portion of our physical capacity sold under firm contracts. With respect to our natural gas storage operations, to the extent that physical capacity that is contracted for firm service is not being fully utilized, we attempt to contract available capacity for interruptible service. The table below sets forth the percentage of operationally available physical capacity or deliverability sold under firm storage contracts, as of September 30, 2012: 

Storage Facility (Commodity)	Percentage  Contractually  Committed	Weighted-Average  Maturity  (Year)
Stagecoach (Natural Gas)	100%	2016
Thomas Corners (Natural Gas)	100%	2015
Seneca Lake (Natural Gas)	100%	2016
Steuben (Natural Gas)	100%	2017
Bath (NGL)(1)	100%	2016

(1) We have contracted 100% of our Bath storage facility to an affiliate, Inergy Services.

Transportation Contracts

The North-South Facilities and East Pipeline, together with the MARC I Pipeline when placed into service, are expected to provide material earnings to our operations. We will seek to maximize the portion of physical capacity sold on the pipelines under firm contracts. To the extent the physical capacity that is contracted for firm service is not being fully utilized, we plan to contract available capacity on an interruptible basis. Our existing transportation assets and our transportation projects under development are 89% contracted and committed.

Operating and Administrative Expenses

Operating and administrative expenses consist primarily of wages, repair and maintenance costs, and professional fees. These expenses typically do not vary significantly based upon the amount of natural gas or NGLs that we store or transport. We obtain in-kind fuel reimbursements from natural gas shippers in accordance with our FERC gas tariffs and individual contract terms. The timing of our expenditures may fluctuate with planned maintenance activities that take place during off-peak periods, and changes in regulation also impact our expenditures. In addition, fluctuations in project development costs are impacted by the level of development activity during a period. Our operating and administrative expenses have also increased following our initial public offering due to an increase in legal and accounting costs and related public company regulatory and compliance expenses.

EBITDA and Adjusted EBITDA

We define EBITDA as income before income taxes, plus net interest expense and depreciation and amortization expense. We define Adjusted EBITDA as EBITDA excluding the gain or loss on the disposal of assets, long-term incentive and equity compensation expense, and transaction costs. Transaction costs are third-party professional fees and other costs that are incurred in conjunction with closing a transaction.

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Adjusted EBITDA is a non-GAAP supplemental financial measure that management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies, may use to assess:

• our operating performance as compared to other publicly traded partnerships in the midstream energy industry, without regard to historical cost basis or financing methods;

• the ability of our assets to generate sufficient cash flow to make distributions to our common unitholders; 

• our ability to incur and service debt and fund capital expenditures; and

• the viability of acquisitions and other capital expenditure projects and the returns on investment in various opportunities.

EBITDA and Adjusted EBITDA should not be considered an alternative to net income, income before income taxes, cash flows from operating activities, or any other measure of financial performance calculated in accordance with GAAP, as those items are used to measure operating performance, liquidity and our ability to service debt obligations. We believe that EBITDA provides additional information for evaluating our ability to make distributions to our common unitholders and is presented solely as a supplemental measure. We believe that Adjusted EBITDA provides additional information for evaluating our financial performance without regard to our financing methods, capital structure and historical cost basis. You should not consider Adjusted EBITDA in isolation or as a substitute for analysis of our results as reported under GAAP. EBITDA and Adjusted EBITDA, as we define them, may not be comparable to EBITDA and Adjusted EBITDA or similarly titled measures used by other corporations or partnerships in our industry, thereby diminishing such measures' utility.

Recent Developments

On November 16, 2012, we entered into Amendment No. 1 (the “Amendment”) with JPMorgan Chase Bank, N.A., as administrative agent, and the other lenders party thereto, which amends our existing credit facility, dated as of December 21, 2011 (the “Credit Facility”).  The Amendment, among other things, (i) amends the definition of Consolidated EBITDA to include projected Consolidated EBITDA attributable to fixed fee contracts from our pending acquisition of Rangeland Energy; (ii) increases the Maximum Total Leverage Ratio to 5.50 to 1.0 for any two consecutive fiscal quarters ending on or immediately after the date of the consummation of a Permitted Acquisition in excess of $50 million; and (iii) adds a Senior Secured Leverage Ratio of 3.75 to 1.00 on and after the cumulative issuance of $200 million or more of Permitted Junior Debt.  

On November 3, 2012, we entered into an agreement with Rangeland Equity Holdings, LLC to acquire 100% of the membership interests of Rangeland Energy for cash consideration of $425 million, subject to certain performance goals and working capital adjustments.  Rangeland Energy owns and operates the COLT Hub, which is an integrated crude oil rail and storage terminal located in the heart of the Bakken and Three Forks shale oil-producing plays.  The Colt Hub primarily consists of 720,000 barrels of crude oil storage, two 8,700-foot rail loops, an eight-bay truck unloading rack, and 21-mile bi-directional crude oil pipeline that connects the terminal to crude oil gathering systems and crude oil interstate pipelines.  The COLT Hub is capable of moving more than 120,000 barrels of crude oil per day by rail.  We expect to complete the Rangeland Energy acquisition in calendar 2012.   

We anticipate financing approximately $453 million of Rangeland Energy transaction costs and post-closing capital expenditures through a combination of debt and equity offerings.  In particular, we (i) entered into an agreement to sell $225 million through a private placement of common units to qualified institutional investors conditioned upon and closing contemporaneously with the closing of the Rangeland acquisition and (ii) we expect to fund our remaining financing requirements through the sale of long-term senior notes or, if applicable, borrowings on an unsecured $225 million credit facility that we have arranged to backstop our financing requirements.  We expect to complete these financing transactions prior to or contemporaneously with the closing of the Rangeland Energy acquisition.

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Results of Operations

Fiscal Year Ended September 30, 2012 Compared to Fiscal Year Ended September 30, 2011

The following table summarizes the consolidated statement of operations for the fiscal years ended September 30, 2012 and 2011, respectively (in millions):

	Year Ended September 30,				Change
	2012		2011		In Dollars			Percentage
Revenue	$	189.8	$	163.2	$	26.6		16.3	%
Service/product related costs	41.4		46.4		(5.0		)	(10.8	)
Operating and administrative expenses	30.4		19.4		11.0			56.7
Depreciation and amortization	50.5		43.9		6.6			15.0
Operating income	67.5		53.5		14.0			26.2
Interest expense, net	1.8		—		1.8			*
Net income	$	65.7	$	53.5	$	12.2		22.8	%

* Not meaningful

Revenue. Revenues for the year ended September 30, 2012 were $189.8 million, an increase of $26.6 million, or 16.3%, from $163.2 million during fiscal 2011.

Revenues from firm storage were $94.5 million for the year ended September 30, 2012, an increase of $4.1 million, or 4.5%, from $90.4 million during fiscal 2011. Natural gas firm storage revenues increased $0.5 million compared to the prior year period. The acquisition of our Seneca Lake storage facility in July 2011 along with a higher percentage of contracted capacity at the facility during the period contributed to a $3.2 million increase in natural gas firm storage revenues. A reduction in contract rates at our various facilities resulted in a $2.7 million decrease in natural gas firm storage revenues. NGL firm storage revenues also increased $3.5 million due to the contractual /customer mix at our Bath facility.

Revenues from transportation were $28.4 million for the year ended September 30, 2012, an increase of $14.4 million, or 102.9%, from $14.0 million during fiscal 2011. Transportation revenues increased $15.2 million due to the placement into service of our North-South Facilities and $3.6 million due to the acquisition of the East Pipeline. Offsetting these increases is a $4.4 million reduction due to revenues derived from marketing capacity we held on TGP's 300 line, which was historically marketed to Stagecoach storage customers and was not renewed during the current fiscal year.

Revenues from hub services were $14.9 million for the year ended September 30, 2012, an increase of $8.4 million, or 129.2%, from $6.5 million during fiscal 2011. This increase resulted primarily from additional demand for interruptible wheeling service as a result of customer demand to move gas to and from our interconnecting pipes primarily due to increasing natural gas development in Pennsylvania. Additionally, hub services revenue increased $1.1 million due to insurance reimbursements related to the Stagecoach central compressor loss.

Revenues from salt were $52.0 million for the year ended September 30, 2012, a decrease of $0.3 million, or 0.6%, from $52.3 million during fiscal 2011.

Service/Product Related Costs. Service/product related costs, including storage, transportation and salt costs for the year ended September 30, 2012, were $41.4 million, a decrease of $5.0 million, or 10.8%, from $46.4 million during fiscal 2011.

Storage related costs were $5.9 million for the year ended September 30, 2012, a decrease of $3.1 million, or 34.4%, from $9.0 million during fiscal 2011. Storage related costs decreased primarily due to a $3.4 million insurance reimbursement related to the Stagecoach central compressor loss, and an additional decrease of $3.7 million related to the costs incurred in the prior period associated with the Stagecoach central compressor loss, and to a lesser extent a $0.9 million decrease during the period due to a reduction of butane product sales from fiscal 2011. These decreases were partially offset by a $3.9 million increase in storage related costs incurred as a result of placing our North-South Facilities into service in December 2011, and $0.6 million due to lower fuel collections as a result of lower average natural gas prices during the current year.

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Transportation related costs were $5.2 million for the year ended September 30, 2012, a decrease of $1.6 million, or 23.5%, from $6.8 million during fiscal 2011. Transportation related costs are primarily comprised of fixed costs for leasing transportation capacity on a non-affiliated interconnecting pipe. This decrease was due to the non-renewal of certain TGP capacity held by us.

Salt related costs were $30.3 million for the year ended September 30, 2012, a decrease of $0.3 million, or 1.0%, from $30.6 million during fiscal 2011.

Our storage related costs consist primarily of direct costs to run the storage facilities, including electricity, contractor and fuel costs. These costs are offset by any fuel-in-kind collections made during the period. Our salt related costs directly relate to the cost of salt sold. Our transportation related costs consist primarily of our costs to procure firm transportation capacity on certain pipelines.

Operating and Administrative Expenses. Operating and administrative expenses were $30.4 million for the year ended September 30, 2012, compared to $19.4 million during fiscal 2011, an increase of $11.0 million, or 56.7%. Operating expenses increased $2.2 million due to the acquisition of our Seneca Lake facility in July 2011, $4.7 million due to an increase in unit based compensation expenses, $1.8 million due to an increase in property taxes and personnel costs at our various facilities, $0.5 million due to placing our North-South Facilities into service in December 2011, $0.7 million due to an increase in acquisition related expenses associated with US Salt, and $0.8 million due to costs related to being a public company.

Depreciation and Amortization. Depreciation and amortization increased to $50.5 million for the year ended September 30, 2012, from $43.9 million during fiscal 2011. This $6.6 million, or 15.0%, increase resulted primarily from the Seneca Lake acquisition in July 2011 and current year depreciation on the North-South Facilities which were placed into full service in December 2011.

Interest Expense. Interest expense was $1.8 million for the year ended September 30, 2012 related to interest incurred on outstanding borrowings on our revolving Credit Facility. There was no interest expense in the prior period due to no outstanding debt, as Inergy funded our operations, prior to our December 2011 IPO.

Net Income. Net income for the year ended September 30, 2012, was $65.7 million compared to net income of $53.5 million during fiscal 2011. The $12.2 million, or 22.8%, increase in net income was primarily attributable to higher revenue and lower service/product related costs during the year ended September 30, 2012, partially offset by increased operating and administrative costs, depreciation and amortization, and interest expenses as discussed above.

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

	Year Ended September 30,
	2012		2011
EBITDA:
Net income	$	65.7	$	53.5
Depreciation and amortization	50.5		43.9
Interest expense, net	1.8		—
EBITDA	$	118.0	$	97.4
Long-term incentive and equity compensation expense	6.5		1.8
Transaction costs (a)	0.7		0.4
Adjusted EBITDA	$	125.2	$	99.6

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	Year Ended September 30,
	2012			2011
EBITDA:
Net cash provided by operating activities	$	132.7		$	96.3
Net changes in working capital balances	(9.2		)	1.1
Amortization of deferred financing costs	(0.8		)	—
Interest expense, net	1.8			—
Long-term incentive and equity compensation expense	(6.5		)	—
EBITDA	$	118.0		$	97.4
Long-term incentive and equity compensation expense	6.5			1.8
Transaction costs (a)	0.7			0.4
Adjusted EBITDA	$	125.2		$	99.6

(a) Transaction costs are third party professional fees and other costs that are incurred in conjunction with closing a transaction.

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

Fiscal Year Ended September 30, 2011 Compared to Fiscal Year Ended September 30, 2010

The following table summarizes the consolidated statement of operations for the fiscal years ended September 30, 2011 and 2010, respectively (in millions):

	Year Ended September 30,					Change
	2011		2010			In Dollars			Percentage
Revenue	$	163.2	$	146.9		$	16.3		11.1	%
Service/product related costs	46.4		42.0			4.4			10.5
Operating and administrative expenses	19.4		19.2			0.2			1.0
Depreciation and amortization	43.9		42.4			1.5			3.5
Loss on disposal of assets	—		0.9			(0.9		)	*
Operating income	53.5		42.4			11.1			26.2
Other income	—		0.8			(0.8		)	*
Net income	53.5		43.2			10.3			23.8	%
Net income attributable to non-controlling partners	—		(0.8		)	0.8			*
Net income attributable to partners	$	53.5	$	42.4		$	11.1		26.2	%

* not meaningful

Revenue. Revenues in fiscal 2011 were $163.2 million, an increase of $16.3 million, or 11.1%, from $146.9 million in fiscal 2010.

Revenues from firm storage were $90.4 million in fiscal 2011, an increase of $9.4 million, or 11.6%, from $81.0 million in fiscal 2010. Natural gas firm storage revenues increased $9.0 million primarily due to the commencement of Thomas Corners storage contracts in April 2010. NGL revenues increased $0.4 million primarily related to an overall increase in the contractual storage fee rates charged to new customers at our Bath storage facility.

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Revenues from transportation were $14.0 million in fiscal 2011, an increase of $1.9 million, or 15.7%, from $12.1 million in fiscal 2010. This increase resulted primarily from an increase in rates charged for transportation.

Revenues from hub services were $6.5 million in fiscal 2011, an increase of $4.9 million, or 306.3%, from $1.6 million in fiscal 2010. This increase resulted primarily from additional demand for interruptible wheeling service as a result of customer demand to move gas to and from our interconnecting pipes primarily due to increasing natural gas development in Pennsylvania.

Revenues from salt were $52.3 million for the year ended September 30, 2011, an increase of $0.1 million, or 0.2%, from $52.2 million during fiscal 2010.

Service/Product Related Costs. Service/product related costs in fiscal 2011 were $46.4 million, an increase of $4.4 million, or 10.5%, from $42.0 million in fiscal 2010.

Storage related costs were $9.0 million in fiscal 2011, an increase of $3.8 million, or 73.1%, from $5.2 million in fiscal 2010. Natural gas storage cost increased $2.5 million and NGL storage cost increased $1.3 million. The increase in natural gas storage cost was primarily due to an increase in compression costs in fiscal 2011 due to the rental of certain temporary compressors at our Stagecoach facility as a result of an operational loss of certain compression functionality during fiscal 2011. NGL storage cost increased due to a decrease of fuel-in-kind collections as a result of a change in the contractual arrangement at our Bath storage facility, which provided for higher storage rates but lower fuel-in-kind collections.

Transportation related costs were $6.8 million in fiscal 2011 and 2010. Transportation related costs are primarily comprised of fixed costs for leasing transportation capacity on a non-affiliated interconnecting pipe.

Salt related costs were $30.6 million for the year ended September 30, 2011, an increase of $0.6 million, or 2.0%, from $30.0 million during fiscal 2010.

Our storage related costs consist primarily of direct costs to run the storage facilities, including electricity, contractor and fuel costs. These costs are offset by any fuel-in-kind collections made during the period. Our salt related costs directly relate to the cost of salt sold. Our transportation related costs consist primarily of our costs to procure firm transportation capacity on certain pipelines.

Operating and Administrative Expenses. Operating and administrative expenses were $19.4 million in fiscal 2011 compared to $19.2 million in fiscal 2010, an increase of $0.2 million, or 1.0%.

Depreciation and Amortization. Depreciation and amortization increased to $43.9 million in fiscal 2011 from $42.4 million in fiscal 2010. This $1.5 million, or 3.5%, increase resulted primarily from placing Thomas Corners into service in November 2009 and the Seneca Lake acquisition in July 2011.

Loss on Disposal of Assets. Loss on disposal of assets was $0.9 million in fiscal 2010. The loss recognized during the 2010 period resulted from the abandonment of a development project. There was no such loss during fiscal 2011.

Net Income Attributable to Non-Controlling Partners. We acquired an approximate 55% in the operations of Steuben Gas Company when we acquired 100% of the membership interest in ASC in October 2007. In January 2010, we acquired an additional 25% interest in Steuben Gas Company, and in each of April 2010 and July 2010, we acquired an additional 10% interest in Steuben Gas Company. These acquisitions gave us 100% ownership of Steuben Gas Company.

Net Income Attributable to Partners. Net income for fiscal 2011 was $53.5 million compared to net income of $42.4 million in fiscal 2010. The $11.1 million, or 26.2%, increase in net income was primarily attributable to higher revenue partially offset by generally higher costs as discussed above.

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EBITDA and Adjusted EBITDA. The following table summarizes EBITDA and Adjusted EBITDA for the years ended September 30, 2011 and 2010, respectively (in millions):

	Year Ended September 30,
	2011		2010
EBITDA:
Net income	$	53.5	43.2
Depreciation and amortization	43.9		42.4
EBITDA	$	97.4	$	85.6
Long-term incentive and equity compensation expense	1.8		3.5
Loss on disposal of assets	—		0.9
Transaction costs (a)	0.4		0.2
Adjusted EBITDA	$	99.6	$	90.2

	Year Ended September 30,
	2011		2010
EBITDA:
Net cash provided by operating activities	$	96.3	$	94.3
Net changes in working capital balances	1.1		(7.8		)
Loss on disposal of assets	—		(0.9		)
EBITDA	$	97.4	$	85.6
Long-term incentive and equity compensation expense	1.8		3.5
Loss on disposal of assets	—		0.9
Transaction costs (a)	0.4		0.2
Adjusted EBITDA	$	99.6	$	90.2

(a) Transaction costs are third party professional fees and other costs that are incurred in conjunction with closing a transaction.

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

Liquidity and Sources of Capital

We are a partnership holding company that derives all of our operating cash flow from our operating subsidiaries.  Our principal sources of liquidity include cash generated by operating activities, credit facilities (including our $600 million Credit Facility), debt issuances, and sales of our common units.   Our operating subsidiaries use cash from their respective operations to fund their operating activities and maintenance capital expenditures.  We use cash generated by our operating subsidiaries and, if applicable, borrowings under our Credit Facility to service our outstanding indebtedness, fund growth capital expenditures, and make distributions to unitholders.  We do not guarantee indebtedness of, or have similar commitments to, our affiliates, including Inergy.

Cash Flows and Contractual Obligations

Fiscal Year Ended September 30, 2012 Compared to Fiscal Year Ended September 30, 2011

Net operating cash inflows were $132.7 million and $96.3 million for the fiscal years ended September 30, 2012 and 2011, respectively. The $36.4 million increase in operating cash flows was primarily attributable to the placement into service of our North-South Facilities and the acquisition of our Seneca Lake storage facility.

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Net investing cash outflows were $328.3 million and $165.2 million for the fiscal years ended September 30, 2012 and 2011, respectively. Net cash outflows were primarily impacted by the $182.5 million acquisition of US Salt in May 2012. As the accounting treatment of this transaction was similar to a pooling of interests since the two entities are under common control, the book value of the acquired net assets of $107.7 million is shown on the consolidated statements of cash flows in investing activities. The purchase price in excess of the acquired net book value of $74.8 million is shown in financing activities. In addition, we increased our capital expenditures by $122.2 million in the year ended September 30, 2012 compared to the same period in the prior year primarily as a result of the MARC I Pipeline. Partially offsetting these increases was a $66.8 million decrease in cash outlays related to the acquisition of Seneca Lake in fiscal 2011.

Net financing cash inflows were $195.6 million and $68.9 million for the fiscal years ended September 30, 2012 and 2011, respectively. The increase in cash inflows was primarily attributable to an increase in net borrowings on our Credit Facility to fund our capital expenditures, and borrowings to fund the acquisition of US Salt, and further due to net proceeds from the issuance of common units. Offsetting these increases in cash inflows were distributions and a $74.8 million cash outlay related to the US Salt acquisition as discussed above. Inergy historically funded our working capital and growth capital expansion initiatives and we historically paid Inergy all cash generated from operations. Subsequent to our IPO, Inergy no longer provides us credit support.

Fiscal Year Ended September 30, 2011 Compared to Fiscal Year Ended September 30, 2010

Net operating cash inflows were $96.3 million and $94.3 million for the fiscal years ended September 30, 2011 and 2010, respectively. The $2.0 million increase in operating cash flows was primarily related to the commencement of Thomas Corners' storage contracts in April 2010.

Net investing cash outflows were $165.2 million and $54.7 million for the fiscal years ended September 30, 2011 and 2010, respectively. The increase in net cash outflows was primarily attributable to a $66.8 million increase in cash outlays related to the acquisition of Seneca Lake and a $43.7 million increase in purchases of property, plant and equipment.

Net financing cash inflows (outflows) were $68.9 million and $(43.2) million for the fiscal years ended September 30, 2011 and 2010, respectively. The net change was primarily attributable to a $48.5 million increase in the equity contributions from Inergy and a net borrowing from Inergy in 2011 of $9.5 million compared to a net payment to Inergy of $28.4 million in 2010. As described above, Inergy historically funded our working capital and growth capital expansion initiatives. We historically paid Inergy all cash generated from operations. In fiscal 2010, we also made payments of $18.3 million related to the acquisition of the minority interest in Steuben Gas Company and $8.3 million in principal payments on long-term debt. No such payments were made in fiscal 2011.

At September 30, 2012 and 2011, we had goodwill of $96.5 million, representing 9% and 12% of total assets in each year, respectively. This goodwill is attributable to our acquisitions.

At September 30, 2012, we were in compliance with all debt covenants to our credit facility.

The following table summarizes our contractual obligations as of September 30, 2012 (in millions):

	Total		Less than 1 year		1-3 years		4-5 years		After 5 years
Aggregate amount of principal and interest to be paid on the outstanding long-term debt(a)	$	451.9	$	9.9	$	16.6	$	425.4	$	—
Future minimum lease payments under noncancelable operating leases	1.0		0.5		0.5		—		—
Standby letters of credit	2.0		1.6		0.4		—		—
Purchase commitments of identified growth projects(b)	22.2		22.2		—		—		—
Total contractual obligations	$	477.1	$	34.2	$	17.5	$	425.4	$	—

(a) Our long-term debt is variable interest rate debt at prime rate or LIBOR plus an applicable spread. These rates plus their applicable spreads were between 1.97% and 4.00% at September 30, 2012. These rates have been applied for each period presented in the table.

(b) Identified growth projects primarily related to the Watkins Glen NGL development project and the MARC I Pipeline.

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We believe that anticipated cash from operations and borrowing capacity under our Credit Facility will be sufficient to meet our liquidity needs for the foreseeable future. If our plans or assumptions change or are inaccurate, or we make acquisitions, we may need to raise additional capital. While global financial markets and economic conditions have been disrupted and volatile in the past, the conditions have improved more recently. However, we give no assurance that we can raise additional capital to meet these needs. As of September 30, 2012, we have firm purchase commitments totaling approximately $22.2 million related to certain of these projects. Additional commitments or expenditures, if any, we may make toward any one or more of these projects are at the discretion of the Company. Any discontinuation of the construction of these projects will likely result in less future cash flow and earnings than we have indicated previously.

Description of Credit Facility

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

On April 16, 2012, we exercised a portion of the accordion feature under the Credit Facility and increased the loan commitments thereunder by $100 million and, as a result, the accordion feature available to us is now $150 million. The aggregate amount of revolving loan commitments under the Credit Facility is now $600 million and can be increased by up to $150 million, subject to the lenders' agreement and the satisfaction of certain conditions.

Our outstanding balance on the Credit Facility at September 30, 2012 amounted to $416.5 million. Outstanding standby letters of credit under the Credit Facility amounted to $2.0 million at September 30, 2012.  As a result, we have approximately $181.5 million of remaining capacity at September 30, 2012, subject to compliance with any applicable covenants under such facility.

The Credit Facility requires us to maintain a consolidated leverage ratio (as defined in our credit agreement) of not more than 5.00 to 1.00 and an interest coverage ratio (as defined in our credit agreement) of not less than 2.50 to 1.00. At September 30, 2012, our consolidated leverage ratio was 2.89 to 1.0 and our interest coverage ratio was not meaningful due to our negligible amount of interest expense.

Recent Accounting Pronouncements

In June 2011 the FASB issued Accounting Standards Update No. 2011-05, “Presentation of Comprehensive Income” (“ASU 2011-05”). Under ASU 2011-05, an entity has the option to present the total of comprehensive income, the components of net income, and the components of other comprehensive income either in a single continuous statement of comprehensive income or in two separate but consecutive statements. Under both options, an entity will be required to present each component of net income along with total net income, each component of other comprehensive income along with a total for other comprehensive income, and a total amount for comprehensive income. Furthermore, regardless of the presentation methodology elected, the entity will be required to present on the face of the financial statements reclassification adjustments for items that are reclassified from other comprehensive income to net income. In December 2011, the FASB issued Accounting Standards Update No. 2011-12, "Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05" ("ASU 2011-12") which deferred this requirement in order to allow the FASB more time to determine whether reclassification adjustments should be required to be presented on the face of the financial statements. The amendments contained in ASUs 2011-05 and 2011-12 do not change the items that must be reported in other comprehensive income or when an item of other comprehensive income must be reclassified to net income. The amendments also do not affect how earnings per share is calculated or presented. We adopted ASUs 2011-05 and 2011-12 in the fourth quarter of the year ended September 30, 2012. We elected to present the total of comprehensive income in two separate but consecutive statements.

Critical Accounting Policies

Revenue Recognition. Revenue for natural gas and NGL firm storage is recognized ratably over the contract period regardless of the volume of natural gas or NGL stored by our customers, revenue from natural gas firm storage is also affected to a lesser extent by volumes of storage gas received and or delivered by the Company's customers. Revenue for transportation services is recognized ratably over the contract period. Transportation revenue is derived from the sale of capacity that we have secured on certain third party pipelines, revenues for transportation on natural gas pipelines acquired in the Seneca Lake acquisition in July 2011, and transportation revenue from placing the North-South Facilities into service in the 2012 fiscal year. Revenue from transportation services is also affected to a lesser extent by volumes of gas transported during the period. Revenue from hub services is recognized

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ratably over the contract period. The contract period for hub services is typically less than one year. Revenues from salt are recognized when product is shipped to the customer or when certain contractual performance requirements have otherwise been met.

Impairment of Goodwill and Long-Lived Assets. Goodwill is subject to at least an annual assessment for impairment by applying a fair-value-based test. Additionally, an acquired intangible asset should be separately recognized if the benefit of the intangible asset is obtained through contractual or other legal rights, or if the intangible asset can be sold, transferred, licensed, rented or exchanged, regardless of the acquirer's intent to do so.

We completed the valuation of each of our reporting units and determined no impairment existed as of September 30, 2012. The valuation of our reporting units requires us to make certain assumptions as it relates to future operating performance. When considering operating performance, various factors are considered such as current and changing economic conditions and the commodity price environment, among others. If the growth assumptions embodied in the current year impairment testing prove inaccurate, we could incur an impairment charge. A 10% decrease in the estimated future cash flows and a 1% increase in the discount rate used in our impairment analysis would not have indicated a potential impairment of any of our intangible assets. To date, we have not recognized any impairment on assets we have acquired.

Accruals and Contingent Liabilities. Accruals are made when our assessment indicates that it is probable that a liability has occurred and the amount of liability can be reasonably estimated. Such accruals may include estimates and are based on all known facts at the time and our assessment of the ultimate outcome. Among the many uncertainties that impact our estimates are the necessary regulatory requirements for operating gas storage facilities, costs of medical care associated with worker's compensation and employee health insurance claims, and the possibility of legal claims. Our estimates for contingent liability accruals are increased or decreased as additional information is obtained or resolution is achieved. Presently, there are no material accruals in these areas. Although the resolution of these uncertainties has not historically had a material impact on our results of operations or financial condition, we cannot provide assurance that actual amounts will not vary significantly from estimated amounts.

Seasonality

Because a high percentage of our baseline cash flow is derived from fixed reservation fees under multi-year contracts, our revenues are not generally seasonal in nature, nor are they typically affected by weather and price volatility during the term of the multi-year contracts. Weather impacts natural gas demand for power generation and heating purposes and propane demand for heating purposes, which in turn influences the value of storage across our natural gas and NGL facilities. Peak demand for natural gas typically occurs during the winter months, caused by the heating load, although certain markets such as the Florida market peak in the summer months due to cooling demands. Peak demand for propane typically occurs during the winter months, caused by residential heating load.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk.

Interest Rate Risk

Our operating and acquisition activities were historically funded by Inergy. Interest was not historically charged on the funding of our activities except during periods of construction.

We have a $600 million revolving credit facility subject to the risk of loss associated with movements in interest rates. At September 30, 2012, we had floating rate obligations totaling $416.5 million under the Credit Facility. We may hedge portions of our borrowings under the Credit Facility from time to time. Floating rate obligations expose us to the risk of increased interest expense in the event of increases in short-term interest rates. We had no hedging instruments in place at September 30, 2012.

If the floating rate were to fluctuate by 100 basis points from September 2012 levels, our interest expenditures would change by a total of approximately $4.2 million per year.

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Commodity Price, Market and Credit Risk

We do not take title to the natural gas or NGLs that we store or transport for our customers and, accordingly, are not exposed to commodity price fluctuations on natural gas or NGLs stored in our facilities or transported through our pipelines by our customers. Except for the base gas we purchase and use in our natural gas storage facilities, which we consider to be a long-term asset, and volume and pricing variations related to small volumes of fuel-in-kind natural gas that we are entitled to retain from our customers as compensation for our fuel costs, our current business model is designed to minimize our exposure to fluctuations in commodity prices. As a result, absent other market factors that could adversely impact our operations, changes in the price of natural gas or NGLs should not materially impact our operations.

Item 8. Financial Statements and Supplementary Data.

Reference is made to the financial statements and report of independent registered public accounting firm included later in this report under Item 15.

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.

None.

Item 9A. Controls and Procedures.

The SEC, as required by Section 404 of the Sarbanes-Oxley Act, adopted rules requiring companies to file reports with the SEC to include a management report on such company's internal control over financial reporting in its annual report.

In addition, our independent registered public accounting firm must attest to our internal control over financial reporting. The Form 10-K for the year ended September 30, 2012 will not include a report of management's assessment regarding internal control over financial reporting or an attestation report of our independent registered public accounting firm due to a transition period established by SEC rules applicable to new public companies. Management will be required to provide an assessment of the effectiveness of our internal control over financial reporting as of September 30, 2013.

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 September 30, 2012, at the reasonable assurance level. There have been no changes in our internal control over financial reporting (as defined in Rule 13(a)-15(f) or Rule 15d-15(f) of the Exchange Act) during the period ended September 30, 2012, that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

Item 9B. Other Information.

None.

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PART III

Item 10. Directors, Executive Officers and Corporate Governance.

Our General Partner Manages Inergy Midstream, L.P.

NRGM GP, LLC, our general partner, manages our operations and activities on our behalf through its directors and officers. Our general partner is not elected by our common unitholders and will not be subject to re-election in the future. Directors of our general partner oversee our operations. The directors of our general partner are appointed by Inergy Midstream Holdings, L.P., which is the sole member of our general partner and is controlled Inergy. Similarly, our unitholders are limited partners and do not or participate, directly or indirectly, in our management or operations. The board of directors of our general partner, which we refer to as “our board of directors” or “our board,” is presently composed of four directors.

The officers of our general partner, which we refer to as “our officers,” are employed by the general partner of Inergy and manage the day-to-day affairs of our business. Certain of our officers devote the majority of their time to our business, while other officers have responsibilities for both us and Inergy and devote less than a majority of their time to our business. We also utilize certain employees of the general partner of Inergy to operate our business and provide us with administrative services.

Neither our general partner nor Inergy receive any management fee or other compensation in connection with our general partner's management of our business. However, prior to making any distribution on our common units, we are obligated to reimburse our general partner and its affiliates, including Inergy, for all expenses they incur and payments they make on our behalf. We have entered into an omnibus agreement with Inergy and its general partner, pursuant to which we agreed upon certain aspects of our relationship with them, including the provision by Inergy to us of certain administrative services and employees and our agreement to reimburse Inergy for the cost of such services and employees.

Directors and Executive Officers

The following table sets forth certain information with respect to our executive officers and directors. Executive officers and directors serve until their successors are duly appointed or elected or until the earlier of their death, resignation, removal or disqualification. There are no family relationships among any of the individuals listed below.

Executive Officers and Directors	Age	Position with our General Partner
John J. Sherman	57	Chief Executive Officer, President and Director
Phillip L. Elbert	54	Executive Vice President - Strategy and Director
R. Brooks Sherman, Jr.	47	Executive Vice President
Michael J. Campbell	43	Senior Vice President - Chief Financial Officer
Laura L. Ozenberger	54	Senior Vice President - General Counsel and Secretary
William C. Gautreaux	49	President - Inergy Services
Michael D. Lenox	36	Vice President - Chief Accounting Officer
Warren H. Gfeller	60	Director
Arthur B. Krause	71	Director
Randy E. Moeder	52	Director

John J. Sherman. Mr. Sherman has served as our President, Chief Executive Officer and a director since our initial public offering in December 2011. Mr. Sherman has served as Chief Executive Officer and director of Inergy since March 2001 and of Inergy's predecessor from 1997 until July 2001. Prior to joining Inergy's predecessor, he was a vice president with Dynegy Inc. from 1996 through 1997. He was responsible for all downstream propane marketing operations, which at the time were the country's largest. From 1991 through 1996, Mr. Sherman was the president of LPG Services Group, Inc., a company he co-founded and grew to become one of the nation's largest wholesale marketers of propane before Dynegy acquired LPG Services in 1996. From 1984 through 1991, Mr. Sherman was a vice president and member of the management committee of Ferrellgas. He also served as President, Chief Executive Officer and director of Inergy Holdings GP, LLC and is currently a director of Great Plains Energy Inc.We believe the breadth of Mr. Sherman's experience in the energy industry, through his current position as the President and CEO and his past employment described above, as well as his current board of director positions, has given him valuable knowledge about our business and our industry that makes him an asset to the board of directors of our general partner.

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Phillip L. Elbert. Mr. Elbert has served as our Executive Vice President - Strategy and the Executive Vice President - Strategy of Inergy since September 2012. Mr. Elbert served as President and Chief Operating Officer-Propane Operations of Inergy since September 2007 until August 2012 and Executive Vice President-Propane Operations and director of Inergy since March 2001. He joined Inergy's predecessor as Executive Vice President-Operations in connection with its acquisition of the Hoosier Propane Group in January 2001. Mr. Elbert joined the Hoosier Propane Group in 1992 and was responsible for overall operations, including Hoosier's retail, wholesale and transportation divisions. From 1987 through 1992, he was employed by Ferrellgas, serving in a number of management positions relating to retail, transportation and supply. Prior to joining Ferrellgas, he was employed by Buckeye Gas Products, a large propane marketer from 1981 to 1987. He also served as the President and Chief Operating Officer-Propane Operations of Inergy Holdings GP, LLC.

R. Brooks Sherman, Jr. Mr. Brooks Sherman, Jr. (no relation to Mr. John Sherman) has served as our Executive Vice President since September 2012. He served as our Executive Vice President - Chief Financial Officer since our initial public offering in December 2011. Mr. Sherman has served as President of Inergy since September 2012, Executive Vice President since September 2007, Senior Vice President since September 2002 and Chief Financial Officer since March 2001. Mr. Sherman previously served as Vice President from March 2001 until September 2002. He joined Inergy's predecessor in December 2000 as Vice President and Chief Financial Officer. From 1999 until joining Inergy's predecessor, he served as Chief Financial Officer of MCM Capital Group. From 1996 through 1999, Mr. Sherman was employed by National Propane Partners, a publicly traded master limited partnership, first as its controller and chief accounting officer and subsequently as its chief financial officer. From 1995 to 1996, Mr. Sherman served as chief financial officer for Berthel Fisher & Co. Leasing Inc. and prior to 1995, Mr. Sherman was in public accounting with Ernst & Young and KPMG Peat Marwick. He also served as Executive Vice President and Chief Financial Officer of Inergy Holdings GP, LLC.

Michael J. Campbell. Mr. Campbell has served as our Senior Vice President - Chief Financial Officer and the Senior Vice President - Chief Financial Officer of Inergy since September 2012. He joined Inergy in 2002 and served as its Vice President and Treasurer since May 2005. He previously served as Director of Financial Analysis in the Corporate Development department at Aquila, Inc., and as Manager Crude and Structured Products Trading Support at Koch Industries.

Laura L. Ozenberger. Ms. Ozenberger has served as our Senior Vice President - General Counsel and Secretary since our initial public offering in December 2011. Ms. Ozenberger has served as Senior Vice President-General Counsel and Secretary of Inergy since September 2007 and Vice President-General Counsel and Secretary of Inergy since February 2003. From 1990 to 2003, Ms. Ozenberger worked for Sprint Corporation. While at Sprint, Ms. Ozenberger served in a number of management roles in the Legal and Finance departments. Prior to 1990, Ms. Ozenberger was in a private legal practice. She also served as Senior Vice President - General Counsel and Secretary of Inergy Holdings GP, LLC.

William C. Gautreaux. Mr. Gautreaux has served as our President - Inergy Services since September 2012 and served as President - Inergy Services for Inergy since November 2011. Mr. Gautreaux has been with Inergy since it inception in 1997 and manages Inergy's coast-to-coast NGL supply and logistics business. Prior to joining Inergy, Mr. Gautreaux was employed by Ferrellgas and later co-founded and managed supply and risk management for LPG Services Group, Inc., which was acquired by Dynegy in 1996.

Michael D. Lenox. Mr. Lenox has served as our Vice President and Chief Accounting Officer and the Vice President and Chief Accounting Officer of Inergy since September 2012. Mr. Lenox joined Inergy in September 2007 as its Director of Financial Reporting and has served as its Vice President and Corporate Controller since November 2011. Prior to joining Inergy, Mr. Lenox was in public accounting with Ernst & Young.

Warren H. Gfeller. Mr. Gfeller has been a member of our general partner's board of directors since our initial public offering in December 2011. Mr. Gfeller has been a member of the board of directors of Inergy's board of directors since March 2001. He was a member of Inergy's predecessor's board of directors from January 2001 until July 2001. He has engaged in private investments since 1991. From 1984 to 1991, Mr. Gfeller served as president and chief executive officer of Ferrellgas, Inc., a retail and wholesale marketer of propane and other natural gas liquids. Mr. Gfeller began his career with Ferrellgas in 1983 as an executive vice president and financial officer. Prior to joining Ferrellgas, Mr. Gfeller was the Chief Financial Officer of Energy Sources, Inc. and a CPA at Arthur Young & Co. He also served as a director of Inergy Holdings GP, LLC, Zapata Corporation and Duckwall-Alco Stores, Inc. Mr. Gfeller worked for many years in the energy industry. This experience has given him a unique perspective on our operations, and, coupled with his extensive financial and accounting training and practice, has made him a valuable member of the board of directors of our general partner.

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Arthur B. Krause. Mr. Krause has been a member of our general partner's board of directors since our initial public offering in December 2011. Mr. Krause has served as a member of the board of directors of Inergy's general partner since May 2003. Mr. Krause retired from Sprint Corporation in 2002, where he served as Executive Vice President and Chief Financial Officer from 1988 to 2002. He was President of United Telephone-Eastern Group from 1986 to 1988. From 1980 to 1986, he was Senior Vice President of United Telephone System. He currently serves as a director of Westar Energy and served as a director of Inergy Holdings GP, LLC from April 2005 until November 2010. Mr. Krause's prior leadership experience and his extensive financial and accounting training and practice have made him a valuable member of the board of directors of our general partner.

Randy E. Moeder. Mr. Moeder has been a member of our general partner's board of directors since March 2012. Mr. Moeder currently is the Chief Executive Officer and President of Moeder Oil & Gas, LLC. Mr. Moeder previously served as the Chief Executive Officer and President of Hiland Partners, LP and Hiland Partners, GP. He also held various positions with Continental Resources, Inc. and its affiliates from 1990 to 2004. Mr. Moeder brings a wealth of oil and gas industry experience to our board. His experience with the midstream sector as well as publicly traded master limited partnership give him valuable insight into the successful execution of our long-term growth objectives and makes him a valuable member of our board.

Independent Directors

Messrs. Gfeller, Krause and Moeder qualify as “independent” pursuant to independence standards established by the NYSE as set forth in Section 303A.02 of the NYSE's Listed Company Manual. To be considered an independent director under the NYSE listing standards, the board of directors must affirmatively determine that a director has no material relationship with us. In making this determination, the board of directors adheres to all of the specific tests for independence included in the NYSE's listing standards and considers all other facts and circumstances it deems necessary or advisable.

Non-Management Executive Sessions and Unitholder Communications

Our non-management directors will meet in regularly scheduled sessions. Our non-management directors have appointed Warren H. Gfeller as the lead director to preside at such meetings. We have established a procedure by which unitholders or interested parties may communicate directly with the board of directors, any committee of the board, any of the independent directors or any one director serving on the board of directors by sending written correspondence addressed to the desired person, committee or group to the attention of Laura Ozenberger at Inergy Midstream, L.P., Two Brush Creek Blvd., Suite 200, Kansas City, MO 64112. Communications are distributed to the board of directors, or to any individual director or directors as appropriate, depending on the facts and circumstances outlined in the communication.

Risk Oversight

We face a number of risks, including environmental and regulatory risks, and others, such as the impact of competition and weather conditions. Management is responsible for the day-to-day management of risks our partnership faces, while the board of directors, as a whole and through its committees, has responsibility for the oversight of risk management. In fulfilling its risk oversight role, the board of directors must determine whether risk management processes designed and implemented by our management are adequate and functioning as designed. Senior management regularly delivers presentations to the board of directors on strategic matters, operations, risk management and other matters, and is available to address any questions or concerns raised by the board. Board meetings regularly include discussions with senior management regarding strategies, key challenges and risks and opportunities for our partnership.

Our board committees assist the board in fulfilling its oversight responsibilities in certain areas of risk. The audit committee assists with risk management oversight in the areas of financial reporting, internal controls and compliance with legal and regulatory requirements and our risk management policy relating to our hedging program. The compensation committee assists the board of directors with risk management relating to our compensation policies and programs.

Board Committees

Audit Committee

The members of the audit committee are Arthur B. Krause, Warren H. Gfeller and Randy E. Moeder. Our board has determined that each of the members of our audit committee meets the independence standards established by the NYSE and that Mr. Gfeller is an audit committee financial expert based upon the experience stated in his biography. The audit committee's primary responsibilities are to monitor: (a) the integrity of our financial reporting process and internal control system; (b) the independence and performance of the independent registered public accounting firm; and (c) the disclosure controls and

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procedures established by management. The charter of our compensation committee may be found on our website at www.inergylp.com under the Investor Relations tab - Inergy Midstream.

Conflicts Committee

The board of directors of our general partner has the ability to establish a conflicts committee under our partnership agreement. The conflicts committee will consist of one or more members and will review specific matters that the board believes may involve conflicts of interest (including certain transactions with Inergy). The members of the conflicts committee may not be officers or employees of our general partner or directors, officers or employees of its affiliates, including Inergy, and must meet the independence and experience standards established by the NYSE and Securities Exchange Act of 1934, as amended, or the Exchange Act, to serve on an audit committee of a board of directors, along with other requirements. Any matters approved by the conflicts committee will be conclusively deemed approved by all of our partners and not a breach by our general partner of any duties it may owe us or our common unitholders.

Compensation Committee

Although we are not required by NYSE listing standards to have a compensation committee, two members of our board serve as members of our compensation committee, which oversees our long term incentive plan. The members of the compensation committee are Warren H. Gfeller and Arthur B. Krause. The charter of our compensation committee may be found on our website at www.inergylp.com under the Investor Relations tab - Inergy Midstream.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Exchange Act requires our directors and executive officers, and persons who own more than 10% of any class of equity securities of our company registered under Section 12 of the Exchange Act, file with the SEC initial reports of ownership and report of changes in ownership in such securities and other equity securities of our company. SEC regulations require directors, executive officers and greater than 10% unitholders furnish our company with copies of all Section 16(a) reports they file. To our knowledge, based solely on review of the reports furnished to us and written representations that no other reports were required, during the fiscal year ended September 30, 2012, all Section 16(a) filing requirements applicable to our directors, executive officers and greater than 10% unitholders, were met.

Code of Ethics

We have adopted a code of ethics that applies to our principal executive officer, principal financial officer, principal accounting officer or controller or persons performing similar functions, as well as to all of our other employees. Additionally, the board of directors has adopted corporate governance guidelines for the directors and the board. The code of ethics and corporate governance guidelines may be found on our website at www.inergylp.com under the Investor Relations tab - Inergy Midstream.

Item 11. Executive Compensation.

Compensation Discussion and Analysis

All of our executive officers and other personnel necessary for the management of our business are employed and compensated by the general partner of Inergy, subject to our reimbursement for services provided to us.

Responsibility and authority for cash compensation-related decisions for our executive officers resides with the compensation committee of Inergy's general partner. Our executive officers manage our business as part of the service provided by Inergy under the omnibus agreement, and the cash compensation for all of our executive officers is partially and indirectly paid by us through reimbursement to Inergy. The compensation committee of the board of directors of our general partner is responsible for the administration of our long-term incentive plan and for compensation of our general partner's non-employee directors.

Certain of our officers devote the majority of their time to our business, while other officers have responsibilities for both us and Inergy and devote less than a majority of their time to our business. Because the officers of our general partner are employees of the general partner of Inergy, cash compensation is paid by Inergy, and we reimburse Inergy in exchange for the employees' services provided to us. The officers of our general partner, as well as the employees of Inergy who provide services to us, may participate in employee benefit plans and arrangements sponsored by Inergy, including plans that may be established in the future.

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Compensation Philosophy and Objectives

We do not directly employ any of the persons responsible for managing our business. Our general partner manages our operations and activities, and its board of directors and executive officers will make decisions on our behalf and we have no control over such costs and cannot establish or direct the compensation policies or practices Inergy. All of our executive officers also serve as executive officers of Inergy or one of its subsidiaries. We are responsible for the reimbursement that we pay to Inergy pursuant to the omnibus agreement. However, from time to time the shared executives may receive awards of equity in us pursuant to our long-term incentive plan and we will bear the costs of the awards granted under our long-term incentive plan.

A full discussion of the compensation programs for Inergy's executive officers and the policies and philosophy of the compensation committee of the board of directors of Inergy GP, LLC is set forth in Inergy's annual report on Form 10-K under the heading “Executive Compensation.”

Inergy Midstream Long Term Incentive Plan

Our general partner sponsors the Inergy Midstream, L.P. Long Term Incentive Plan for its directors, consultants and employees and the employees and consultants of its affiliates who perform services for it. The plan is administered by the compensation committee of our general partner's board of directors.

Restricted Units

The Inergy Midstream, L.P. Long Term Incentive Plan currently permits, and our general partner has made, grants of restricted units. Restricted units are subject to a restricted period the terms of which are set forth in a restricted unit award agreement. In general, restricted units vest over a five-year period. The individual award agreement also sets forth the conditions under which the restricted units may become vested or forfeited, which may include, without limitation, the accelerated vesting upon the achievement of specified performance goals, or the forfeiture for failing to achieve specified performance goals and such other terms and conditions as the committee may establish. Unless otherwise specifically provided for in an award agreement, distributions are paid to the holder of the restricted units without restriction. Restricted units are designed to furnish additional compensation to employees and directors and to align their economic interests with those of common unitholders.

On May 2, 2012, the compensation committee awarded Mr. R. Brooks Sherman, Jr., Mr. Campbell, Ms. Ozenberger and Mr. Gautreaux 50,000, 20,000, 40,000 and 30,000 Inergy Midstream, L.P. restricted units, respectively. The awards were made shortly following our initial public offering to better align the economic interests of these key employees with our common unitholders and to provide incentive for these key individuals to remain employed with Inergy. These awards vest 25%, 25% and 50% on the third, fourth and fifth anniversaries, respectively, from the date of grant. You can also find additional details regarding these awards in Inergy's annual report on Form 10-K under the heading “Executive Compensation.”

Termination and Amendment

Our board of directors in its discretion may terminate the Inergy Midstream, L.P. Long Term Incentive Plan at any time with respect to any common units for which a grant has not yet been made. Our board of directors also has the right to alter or amend Inergy Midstream, L.P. Long Term Incentive Plan from time to time, including increasing the number of common units with respect to which awards may be granted subject to unitholder approval as required by the exchange upon which the common units are listed at that time. However, no change in any outstanding grant may be made that would materially impair the rights of the participant without the consent of the participant.

Compensation Committee Report

We have reviewed and discussed the foregoing Compensation Discussion and Analysis with management. Based on our review and discussion with management, we have recommended that the Compensation Discussion and Analysis be included in this Annual Report on Form 10-K for the year ended September 30, 2012.

Warren H. Gfeller

Arthur B. Krause

Members of the Compensation Committee

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Director Compensation Table for the Fiscal Year Ended September 30, 2012

The following table sets forth the cash and non-cash compensation for the year ended September 30, 2012, by each person who served as a non-employee director of our general partner.

Name	Fees Earned or Paid in Cash ($)	Unit Awards ($)(1)	Total ($)
Warren H. Gfeller	42,833	49,997	92,830
Arthur B. Krause	49,833	49,997	99,830
Randy E. Moeder	40,333	49,980	90,313

(1) On December 21, 2011, Messrs. Gfeller and Krause were each awarded 2,941 restricted units. On March 1, 2012, Mr. Moeder was awarded 2,341 restricted units. As of September 30, 2012, other than these restricted unit awards, these directors had no other equity awards outstanding.

Compensation of Directors

The officers or employees of our general partner or of the general partner of Inergy who also serve as our directors do not receive additional compensation for serving as directors. Our board determines compensation of our directors. Each non-employee director receives cash compensation of $40,000 per year for attending our regular board and distribution meetings. Each non-employee director receives $1,000 for each special meeting of the board of directors attended and $1,000 per compensation, audit or conflicts committee meeting attended. The chairman of the audit committee receives an annual fee of $10,000 per year and the chairman of the compensation committee receives an annual fee of $2,000 per year. Furthermore, each non-employee director receives an annual grant of restricted units under the long-term incentive plan equal to $50,000 in value. These units vest ratably over three years beginning one year from the grant date. In the event that a director's membership on our board is terminated for any reason, the director, for no consideration, forfeits to us all unvested restricted units. Restricted units may not be sold or otherwise transferred. In addition, non-employee directors will be reimbursed for out-of-pocket expenses in connection with attending meetings of the board of directors or its committees.

Compensation Committee Interlocks and Insider Participation

Warren H. Gfeller and Arthur B. Krause serve as the members of the compensation committee, and neither of them was an officer or employee of our company or any of its subsidiaries during fiscal 2012.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters.

The following table sets forth certain information as of November 6, 2012, regarding the beneficial ownership of our common units by:

• each person who then beneficially owned more than 5% of such units then outstanding;

• each of the named executive officers of our general partner;

• each of the directors of our general partner; and

• all of the directors and executive officers of our general partner as a group.

All information with respect to beneficial ownership has been furnished by the respective directors, executive officers or 5% or more unitholders, as the case may be.

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Name of Beneficial Owner(1)	Common and Class B Units Beneficially Owned	Percentage of Common and Class B Units Beneficially Owned
Inergy, L.P.	56,398,707	75.05	%
John J. Sherman	100,000	*
R. Brooks Sherman, Jr.	55,000	*
Michael J. Campbell	21,000	*
William R. Moler	2,600	*
Laura L. Ozenberger	45,000	*
William C. Gautreaux	140,000	*
Warren H. Gfeller	11,941	*
Arthur B. Krause	7,941	*
Randy E. Moeder	17,341	*
All directors and executive officers as a group (11 persons)	422,323	*

* Less than 1%

(1) Unless otherwise indicated, the address of each person listed above is: Two Brush Creek Boulevard, Suite 200, Kansas City, Missouri 64112. All persons listed have sole voting power and investment power with respect to their units unless otherwise indicated.

We refer you to Item 5 of this report for certain information regarding securities authorized for issuance under equity compensation plans.

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

For a discussion of director independence, see Item 10 "Directors, Executive Officers and Corporate Governance."

Inergy owns 56,398,707 common units, which equals an approximate 75.0% limited partner interest in us. Our general partner (NRGM GP, LLC) owns a non-economic general partner interest in us. The sole member of our general partner, Inergy Midstream Holdings, L.P., owns all of our IDRs.

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Distributions and Payments to Our General Partner and Its Affiliates

The table below summarizes the distributions and payments made or to be made by us to our general partner and its affiliates in connection with our ongoing operations.  These distributions and payments were determined by and among affiliated entities.

Distributions of available cash to our general partner and its affiliates	We will generally make cash distributions 100% to our common unitholders, including affiliates of our general partner as the holders of an aggregate of 56,398,707 common units (which includes an aggregate 383,223 restricted units granted to our independent directors and employees). Our general partner will not receive cash distributions on its non-economic general partner interest. If distributions exceed the initial quarterly distribution of $0.37 per unit, Inergy will be entitled to 50% of our cash distributions above the initial quarterly distribution level in respect of its IDRs. In fiscal 2012, we made approximately $44.4 million of distributions to our general partner and its affiliates as holders of our common units. In fiscal 2012, we paid approximately $0.7 million to our general partner in respect of the IDRs.
Payments to our general partner and its affiliates	Neither our general partner nor Inergy will receive any management fee or other compensation for the management of our business. However, prior to making any distribution on our common units, we will reimburse our general partner and its affiliates, including Inergy, for all direct and indirect expenses incurred on our behalf, which were approximately $15.3 million in fiscal 2012 (including $9.0 million in reimbursements of direct personnel related expenses). Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us.
Withdrawal or removal of our general partner	If our general partner withdraws or is removed, its general partner interest will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests.

Omnibus Agreement

We have entered into an omnibus agreement with our general partner, Inergy and its general partner that governs certain aspects of our relationship with them, including:

• the provision by Inergy to us of certain administrative services and our agreement to reimburse Inergy for such services;

• the provision by Inergy of such employees as may be necessary to operate and manage our business, and our agreement to reimburse Inergy for the expenses associated with such employees;

• certain indemnification obligations;

• our use of the name “Inergy” and related marks; and

• Inergy's right to review and first option with respect to business opportunities.

Inergy's indemnification obligations to us includes certain liabilities relating to:

• for three years after our initial public offering ("IPO"), certain environmental liabilities attributable to the ownership and operation of our assets prior to our IPO, including (i) any violation or correction of a violation of environmental laws associated with our assets, where a correction of violation would include assessment, investigation, monitoring, remediation, or other similar action and (ii) any event, omission or condition associated with the ownership or operation of our assets (including the presence or release of hazardous materials), including (a) the cost and expense of any assessment, investigation, monitoring, remediation or other similar action, (b) the cost and expense of the preparation and implementation of any closure activity or remedial or corrective action required under environmental laws, and (c) the cost and expense of any environmental or toxic tort litigation;

• environmental liabilities attributable with our prior ownership and operation of Tres Palacios Gas Storage LLC;

• the ownership and operation of our assets prior to the IPO;

provided, that (i) the aggregate amount payable to us pursuant to the first bullet point above will not exceed $15 million and (ii) amounts are only payable to us pursuant to the first and second bullet points above after liabilities relating to the first and second bullet points have exceeded $100,000 and then only for such amounts in excess of $100,000;

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• until the first day after the applicable statute of limitations, any of our federal, state and local income tax liabilities attributable to the ownership and operation of our assets prior to our IPO;

• for three years after the closing of our IPO, the failure to have all necessary consents and governmental permits where such failure renders us unable to use and operate our assets in substantially the same manner in which they were used and operated immediately prior to our IPO; and

• for three years after the closing of our IPO, our failure to have valid and indefeasible easement rights, rights-of-way, leasehold and/or fee ownership interest in and to the lands on which our assets are located and such failure prevents us from using or operating our assets in substantially the same manner as they were used or operated immediately prior to our IPO.

Inergy will not be required to indemnify us for any claims, losses or expenses or income taxes referred to above to the extent such were either (i) reserved for in our financial statements as of the closing of this offering or (ii) we recover any such amounts under available insurance coverage, from contractual rights or other recoveries against any third party.

Our indemnification obligations to Inergy, its general partner and their affiliates (other than our general partner, us and our subsidiaries) includes certain liabilities relating to:

• certain environmental liabilities attributable to the ownership and operation of our assets, but only to the extent the violations, events, omissions or conditions giving rise to such covered environmental liabilities occur after the closing of our IPO; provided , that (i) our aggregate liability for such covered environmental liabilities will not exceed $15 million and (ii) amounts are only payable by us pursuant to this bullet point after liabilities relating to such covered environmental losses have exceeded $100,000 and then only for such amounts in excess of $100,000; and

• losses suffered or incurred by Inergy by reason of or arising out of events and conditions associated with the operation of our assets that occur on or after our IPO (other than covered environmental losses, which are covered by the preceding bullet).

With respect to the provision by Inergy of certain administrative services and such management and operating services as may be necessary to manage and operate our business, the omnibus agreement addresses certain aspects of our relationship with Inergy, including:

��

• the provision by Inergy to us of certain specified administrative services necessary to run our business, including the provision of such employees as may be necessary to operate and manage our business, and our agreement to reimburse Inergy for all reasonable costs and expenses incurred in connection with such services;

• our agreement to reimburse Inergy for all expenses it incurs as a result of us becoming a publicly traded partnership; and

• our agreement to reimburse Inergy for all expenses that it incurs or payments it makes on our behalf with respect to insurance coverage for our business.

Neither our partnership agreement nor the omnibus agreement will limit the amount of expenses for which our general partner and its affiliates may be reimbursed. However, we expect these services to be provided at cost.

Under the omnibus agreement, Inergy has granted and conveyed to us a nontransferable, nonexclusive, royalty free right and license to use the name “Inergy” and any associated or related marks. Our license to use the name “Inergy” will terminate upon the termination of the omnibus agreement. Under the omnibus agreement, Inergy will have the right to review and has the first option on any business opportunities that are presented to us or to Inergy. Although it is under no obligation to make business opportunities available to us, Inergy has a significant economic stake in us and a strong incentive to support our growth.

Except for the indemnification provisions, the omnibus agreement may be terminated by Inergy with 180 days' prior written notice if (i) NRGM GP, LLC is removed as our general partner under circumstances where “cause” does not exist and the common units held by Inergy and its affiliates were not voted in favor of such removal; (ii) a change of control of Inergy occurs; or (iii) a change of control of us occurs. Except for the indemnification provisions, we may terminate the omnibus agreement with 180 days' prior written notice if a change of control of Inergy occurs, a change of control of us occurs or Holdings GP acquires MGP GP, LLC as discussed below in “NRGM GP, LLC Change of Control Event.”

Tax Sharing Agreement

We have entered into a tax sharing agreement with Inergy pursuant to which we will reimburse Inergy for our share of state and local income and other taxes borne by Inergy as a result of our income being included in a combined or consolidated tax return filed by Inergy with respect to taxable periods including or beginning on the closing date of our IPO. The amount of any such

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reimbursement will be limited to the tax that we (and our subsidiaries) would have paid had we not been included in a combined group with Inergy. Inergy may use its tax attributes to cause its combined or consolidated group, of which we may be a member for this purpose, to owe no tax. However, we would nevertheless reimburse Inergy for the tax we would have owed had the attributes not been available or used for our benefit, even though Inergy had no cash expense for that period.

NRGM GP, LLC Change of Control Event

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

The agreement will automatically terminate if prior to a purchase event in clauses (i) or (ii) above, (a) a change of control of Inergy occurs prior to the time that it is entitled to receive less than 50% of all cash distributed with respect to our limited partner interests and IDRs or (b) a change of control of us occurs prior to the time that Inergy is entitled to receive less than 25% of all cash distributed with respect to our limited partner interests and IDRs.

Contribution Agreement

On December 21, 2011, in connection with the closing of our IPO, pursuant to the Contribution, Conveyance and Assumption Agreement by and among us, Inergy, the general partner of Inergy, Inergy Propane, LLC, MGP GP, LLC, MGP and our general partner (the “Contribution Agreement”), Inergy conveyed its initial limited partner interest in our partnership to us, as a recapitalization of Inergy's interest in us, in exchange for:

• 55,925,000 common units representing a 75.2% limited partner interest in us;

• the right to receive a distribution from us of $80 million as reimbursement of pre-formation capital expenditures with respect to our assets;

• the issuance to MGP of all of our incentive distribution rights;

• our assumption of the promissory note; and

• the right to receive a distribution in the amount of $38,199,000 for the aggregate amount of cash contributed by the underwriters to us with respect to the 2,400,000 common units purchased by and issued to the underwriters in connection with their exercise in full of the over-allotment option.

Pursuant to the Contribution Agreement, our general partner conveyed to us its initial general partner interest in us, as a recapitalization of its interest in our partnership, in exchange for a non-economic general partner interest in us.

As a contribution in capital to us, Inergy also contributed to us all intercompany indebtedness that we owed to Inergy Propane, LLC as of December 21, 2011, and such intercompany debt was canceled.

Other Transactions with Related Persons

We provide firm storage services utilizing 100% of the operationally available storage capacity at our Bath storage facility to an affiliate, Inergy Services, under a five-year contract entered into in March 2011. As of September 30, 2012 the annual storage fee is approximately $13.1 million. The terms and conditions of the storage contract are consistent with the terms and conditions of the storage leases that Inergy Services has entered into with third parties. We received total revenues from Inergy Services under this contract of $11.8 million for the fiscal year ended September 30, 2012.

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In addition, we will provide firm storage services utilizing 100% of the operationally available storage capacity at our proposed Watkins Glen NGL storage facility to Inergy Services under a five-year contract. As part of this development project, Inergy Services marketed this future storage capacity and entered into a five-year contract on our behalf with an unaffiliated third party under which the anchor customer obtained the right to store two million barrels of propane and butane at the proposed facility. All revenue generated by Inergy Services from subleasing storage capacity to third parties at the Watkins Glen NGL storage facility will be paid to us during the term of the affiliate contract. The other terms and conditions of the storage contract are consistent with the terms and conditions of the storage contracts that Inergy Services enters into with third parties, including the anchor customer. We estimate the value of this contract over the five-year term to be approximately $36.8 million.

As of September 30, 2011, we had approximately $129.8 million of indebtedness outstanding to another affiliate, Inergy Propane, LLC ("Inergy Propane"), which was subject to interest during the period of construction of our expansion projects. For the fiscal year ended September 30, 2011, the largest aggregate amount of principal outstanding and the amount of principal paid on indebtedness outstanding to Inergy Propane were $129.8 million and $77.1 million, respectively. For the fiscal year ended September 30, 2011, we paid approximately $6.2 million of interest expense on the intercompany indebtedness. Our outstanding intercompany indebtedness was subject to an interest rate of approximately 6.5% at September 30, 2011. This intercompany indebtedness was incurred to support our capital expansion and working capital needs. Upon completion of our IPO, this intercompany indebtedness was extinguished and treated as a capital contribution and part of Inergy's investment in us.

Immediately prior to the closing of our IPO, Inergy issued a $255 million unsecured promissory note to JPMorgan Chase Bank, N.A., which we assumed immediately thereafter pursuant to an assignment and assumption agreement. We assumed the promissory note as partial consideration to Inergy in connection with the recapitalization of its interest in us. Upon completion of our IPO, we repaid the promissory note in full with the net proceeds from our IPO and borrowings of approximately $2.7 million under our revolving credit facility. 

We transferred US Salt to Inergy on November 25, 2011 in connection with our initial public offering. On May 14, 2012, we re-acquired US Salt from Inergy for a total purchase price of $192.5 million, including $182.5 million in cash and 473,707 common units.

Review, Approval or Ratification of Transactions with Related Persons

Although we do not have any formal policy for the review of related party transactions, the Audit Committee would review and approve all transactions or series of related financial transactions, arrangements or relationships between our partnership and any related party, including those that involve an amount that exceeds $120,000. 

In addition, pursuant to our Code of Business Conduct and Ethics, our directors and officers are expected to bring to the attention of our Compliance Officer any conflict or potential conflict of interest.  If a conflict or potential conflict of interest arises between our partnership and our general partner, the resolution of any such conflict or potential conflict should be addressed by the board in accordance with the provisions of our partnership agreement. At the discretion of the board in light of the circumstances, the resolution may be determined by the board in its entirety or by a “conflicts committee” meeting the definitional requirements for such a committee under the Partnership Agreement.

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Item 14. Principal Accountant Fees and Services.

The following table presents fees billed for professional audit services rendered by Ernst & Young LLP for the audit of our annual financial statements and for other services for the years ended September 30, 2012 and 2011 (in millions):

	Year Ended September  30,
	2012		2011
Audit fees(1)	$	1.3	$	0.7

(1) Audit fees consist of assurance and related services that are reasonably related to the performance of the audit or review of our financial statements. This category includes fees related to the review of our quarterly and other SEC filings and services related to internal control assessments.

The audit committee of our general partner reviewed and approved all audit and non-audit services provided to us by Ernst & Young during fiscal 2012. For information regarding the audit committee’s pre-approval policies and procedures related to the engagement by us of an independent accountant, see our audit committee charter on our website at www.inergylp.com.

61

PART IV

Item 15. Exhibits and Financial Statement Schedules.

(a) Exhibits, Financial Statements and Financial Statement Schedules:

1. Financial Statements:

See Index Page for Financial Statements located on page 64.

2. Financial Statement Schedule:

Schedule II: Valuation and Qualifying Accounts located on page 91.

Other financial statement schedules have been omitted because they are either not required, are immaterial or are not applicable or because equivalent information has been included in the financial statements, the notes thereto or elsewhere herein.

3. Exhibits:

Exhibit Number	Description
2.1	Membership Interest Purchase Agreement dated May 14, 2012, by and among Inergy, L.P. and Inergy Midstream, L.P. (incorporated by reference to Exhibit 10.1 to Inergy Midstream, L.P.'s Form 8-K filed on May 14, 2012)
2.2	Securities Purchase Agreement dated as of November 3, 2012, by and between Rangeland Equity Holdings, LLC and Inergy Midstream, L.P. (incorporated by reference to Exhibit 2.1 to Inergy Midstream, L.P.'s Form 8-K filed on November 5, 2012)
3.1	Certificate of Limited Partnership of Inergy Midstream, L.P. (incorporated by reference to Exhibit 3.4 to Inergy Midstream, L.P.'s Form S-1/A filed on November 21, 2011)
3.2	First Amended and Restated Agreement of Limited Partnership of Inergy Midstream, L.P., dated December 21, 2011 (incorporated herein by reference to Exhibit 4.2 to Inergy Midstream, L.P.'s Form S-8 filed on December 21, 2011)
3.3	Certificate of Formation of NRGM GP, LLC (incorporated by reference to Exhibit 3.7 to Inergy Midstream, L.P.'s Form S-1/A filed on November 21, 2011)
3.4	Amended and Restated Limited Liability Company Agreement of NRGM GP, LLC, dated December 21, 2011 (incorporated by reference to Exhibit 3.2 to Inergy Midstream, L.P.'s Form 8-K filed on December 21, 2011)
10.1	Contribution, Conveyance and Assumption Agreement, dated December 21, 2011, by and among Inergy GP, LLC, Inergy, L.P., Inergy Propane, LLC, MGP GP, LLC, Inergy Midstream Holdings, L.P., NRGM GP, LLC, and Inergy Midstream, L.P. (incorporated by reference to Exhibit 10.1 to Inergy Midstream, L.P.'s Form 8-K filed on December 21, 2011)
10.2	Omnibus Agreement, dated December 21, 2011, by and among Inergy GP, LLC, Inergy, L.P., NRGM GP, LLC and Inergy Midstream, L.P. (incorporated by reference to Exhibit 10.2 to Inergy Midstream, L.P.'s Form 8-K filed on December 21, 2011)
10.3*	Inergy Midstream, L.P. Long-Term Incentive Plan, adopted as of December 21, 2011 (incorporated herein by reference to Exhibit 4.3 to Inergy Midstream, L.P.'s Form S-8 filed on December 21, 2011)
10.4*	Form of Inergy Midstream, L.P. Long-Term Incentive Plan Restricted Unit Award Agreement (incorporated herein by reference to Exhibit 4.4 to Inergy Midstream, L.P.'s Form S-8 filed on December 21, 2011)
10.5*	Inergy Midstream, L.P. Employee Unit Purchase Plan, adopted as of December 21, 2011 (incorporated herein by reference to Exhibit 4.5 to Inergy Midstream, L.P.'s Form S-8 filed on December 21, 2011)
10.6	Tax Sharing Agreement, dated December 21, 2011, by and among Inergy, L.P. and Inergy Midstream, L.P. (incorporated by reference to Exhibit 10.6 to Inergy Midstream, L.P.'s Form 8-K filed on December 21, 2011)

62

Exhibit Number	Description
10.7	Credit Agreement, dated December 21, 2011, among Inergy Midstream, L.P., as borrower, the lenders party thereto, and JPMorgan Chase Bank, N.A., as administrative agent (incorporated by reference to Exhibit 10.7 to Inergy Midstream, L.P.'s Form 8-K filed on December 21, 2011)
**21.1	List of subsidiaries of Inergy Midstream, L.P.
**23.1	Consent of Ernst & Young LLP
**31.1	Certification of the Chief Executive Officer pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended
**31.2	Certification of Chief Financial Officer pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended
**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
**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
***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

*	Management contracts or compensatory plans or arrangements
**	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.

63

Inergy Midstream, L.P.

(Formerly Inergy Midstream, LLC)

Consolidated Financial Statements

September 30, 2012 and 2011 and each of the

Three Years in the Period Ended

September 30, 2012

Contents

Report of Independent Registered Public Accounting Firm	65
Audited Consolidated Financial Statements:
Consolidated Balance Sheets	66
Consolidated Statements of Operations	67
Consolidated Statements of Comprehensive Income	68
Consolidated Statements of Partners’ Capital	69
Consolidated Statements of Cash Flows	70
Notes to Consolidated Financial Statements	72

64

Report of Independent Registered Public Accounting Firm

The Board of Directors of NRGM GP, LLC and Unitholders of Inergy Midstream, L.P

We have audited the accompanying consolidated balance sheets of Inergy Midstream, L.P. (formerly Inergy Midstream, LLC) (the Company) as of September 30, 2012 and 2011, and the related consolidated statements of operations, comprehensive income, partners' capital and cash flows for each of the three years in the period ended September 30, 2012. Our audits also included the financial statement schedule listed in the Index and Item 15(a). These financial statements and schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Inergy Midstream, L.P. (formerly Inergy Midstream, LLC) at September 30, 2012 and 2011, and the consolidated results of their operations and their cash flows for each of the three years in the period ended September 30, 2012, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

As discussed in Note 10 to the consolidated financial statements, the accompanying consolidated financial statements have been retrospectively adjusted to include the historical values and results of US Salt, LLC.

/s/ Ernst & Young LLP

Kansas City, Missouri

November 20, 2012

65

INERGY MIDSTREAM, L.P. (FORMERLY INERGY MIDSTREAM, LLC) CONSOLIDATED BALANCE SHEETS (in millions, except unit information)
	September 30,
	2012		2011
Assets
Current assets:
Cash and cash equivalents	$	—	$	—
Accounts receivable	19.3		16.1
Inventories	5.6		5.1
Prepaid expenses and other current assets	5.4		4.7
Total current assets	30.3		25.9
Property, plant and equipment (Note 3):	1,068.7		816.9
Less: accumulated depreciation	200.8		152.9
Property, plant and equipment, net	867.9		664.0
Intangible assets (Note 3):
Customer accounts	38.3		39.5
Other intangible assets	5.2		7.5
	43.5		47.0
Less: accumulated amortization	14.2		19.7
Intangible assets, net	29.3		27.3
Goodwill	96.5		96.5
Other assets	3.9		—
Total assets	$	1,027.9	$	813.7
Liabilities and partners’ capital
Current liabilities:
Accounts payable	$	3.9	$	9.5
Accrued expenses	48.5		12.5
Bank Overdraft	2.6		0.2
Payable to Inergy Propane, LLC and Inergy, L.P. (Note 2)	0.3		129.8
Current portion of long-term debt (Note 5)	1.5		—
Total current liabilities	56.8		152.0
Long-term debt, less current portion (Note 5)	415.0		—
Other long-term liabilities	0.8		0.9
Partners’ capital (Note 6):
Limited partner unitholders (75,181,930 common units issued and outstanding at September 30, 2012)	555.3		660.8
Total partners’ capital	555.3		660.8
Total liabilities and partners’ capital	$	1,027.9	$	813.7

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

66

INERGY MIDSTREAM, L.P. (FORMERLY INERGY MIDSTREAM, LLC) CONSOLIDATED STATEMENTS OF OPERATIONS (in millions, except unit and per unit data)
	Year Ended September 30,
	2012		2011		2010
			(a)		(a)
Revenue:
Firm storage	$	82.7	$	86.4	$	80.5
Transportation	28.4		14.0		12.1
Hub services	14.9		6.5		1.6
Related party firm storage (Note 9)	11.8		4.0		0.5
Salt	52.0		52.3		52.2
	189.8		163.2		146.9
Costs and expenses:
Storage related	5.9		9.0		5.2
Transportation related	5.2		6.8		6.8
Salt related	30.3		30.6		30.0
Operating and administrative	30.4		19.4		19.2
Depreciation and amortization	50.5		43.9		42.4
Loss on disposal of assets	—		—		0.9
	122.3		109.7		104.5
Operating income	67.5		53.5		42.4
Other income	—		—		0.8
Interest expense, net	1.8		—		—
Net income	65.7		53.5		43.2
Net income attributable to non-controlling partners	—		—		(0.8		)
Net income attributable to partners	$	65.7	$	53.5	$	42.4
Less: net income prior to initial public offering of Inergy Midstream, L.P.	12.9
Less: net income earned by US Salt, LLC prior to acquisition (Note 10)	7.8
Net income available to partners	$	45.0
Partners' interest information:
Non-managing general partner interest in net income	$	1.9
Total limited partners’ interest in net income	$	43.1
Net income per limited partner unit:
Basic	$	0.58
Diluted	$	0.58
Weighted-average limited partners’ units outstanding (in thousands):
Basic	74,768
Diluted	74,768

(a)Retrospectively adjusted as described in Note 1.

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

67

INERGY MIDSTREAM, L.P. (FORMERLY INERGY MIDSTREAM, LLC) CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (in millions)
	Year Ended September 30,
	2012		2011		2010
Net income	$	65.7	$	53.5	$	43.2
Change in unrealized fair value on cash flow hedges (Note 2)	0.1		0.1		0.1
Comprehensive income	$	65.8	$	53.6	$	43.3

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

68

INERGY MIDSTREAM, L.P. (FORMERLY INERGY MIDSTREAM, LLC) CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL (in millions)
	Partners' Capital			Non-Controlling Partners			Total Partners’ Capital
Balance at September 30, 2009 (a)	$	506.7		$	4.7		$	511.4
Purchase of minority interest	(13.8		)	(4.5		)	(18.3		)
Contribution by Inergy, L.P.	18.3			—			18.3
Distributions	—			(0.6		)	(0.6		)
Net distribution by US Salt, LLC to Inergy, L.P.	(5.9		)	—			(5.9		)
Disposal of entity	—			(0.4		)	(0.4		)
Change in unrealized fair value on cash flow hedges	0.1			—			0.1
Net income	42.4			0.8			43.2
Balance at September 30, 2010 (a)	547.8			—			547.8
Contribution by Inergy, L.P.	66.8			—			66.8
Net distribution by US Salt, LLC to Inergy, L.P.	(7.4		)	—			(7.4		)
Change in unrealized fair value on cash flow hedges	0.1			—			0.1
Net income	53.5			—			53.5
Balance at September 30, 2011 (a)	660.8			—			660.8
Net proceeds from the issuance of common units	292.4			—			292.4
Extinguishment of indebtedness owed to Inergy, L.P.	152.8			—			152.8
Distributions to Inergy, L.P.	(163.3		)	—			(163.3		)
Distributions to shareholders	(14.6		)	—			(14.6		)
Assumption of promissory note of Inergy, L.P.	(255.0		)	—			(255.0		)
Unit-based compensation charges	6.5			—			6.5
Cash paid for US Salt, LLC acquisition (Note 10)	(182.5		)	—			(182.5		)
Net distribution by US Salt, LLC to Inergy, L.P. prior to acquisition      (Note 10)	(7.9		)	—			(7.9		)
Change in unrealized fair value on cash flow hedges	0.1			—			0.1
Other	0.3			—			0.3
Net income	65.7			—			65.7
Balance at September 30, 2012	$	555.3		$	—		$	555.3

(a) Retrospectively adjusted as described in Note 1.

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

69

INERGY MIDSTREAM, L.P. (FORMERLY INERGY MIDSTREAM, LLC) CONSOLIDATED STATEMENTS OF CASH FLOWS (in millions)
	Year Ended September 30,
	2012			2011			2010
				(a)			(a)
Operating activities
Net income	$	65.7		$	53.5		$	43.2
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation	48.0			41.0			38.7
Amortization	2.5			2.9			3.7
Amortization of deferred financing costs	0.8			—			—
Loss on disposal of assets	—			—			0.9
Unit-based compensation charges	6.5			—			—
Changes in operating assets and liabilities, net of effects from acquisitions:
Accounts receivable	(3.2		)	(2.3		)	(1.5		)
Inventories	(0.4		)	(1.0		)	(0.9		)
Prepaid expenses and other current assets	(0.8		)	1.1			6.1
Other assets	(3.9		)	—			0.7
Accounts payable and accrued expenses	0.7			(0.2		)	(5.4		)
Bank overdraft	2.4			(0.7		)	0.9
Payable to Inergy Propane, LLC and Inergy, L.P.	14.4			2.0			7.9
Net cash provided by operating activities	132.7			96.3			94.3
Investing activities
Acquisitions, net of cash acquired	—			(66.8		)	—
Purchase of US Salt, LLC (Note 10)	(107.7		)	—			—
Purchases of property, plant and equipment	(220.6		)	(98.4		)	(54.7		)
Net cash used in investing activities	(328.3		)	(165.2		)	(54.7		)
(a) Retrospectively adjusted as described in Note 1.
The accompanying notes are an integral part of these consolidated financial statements.

70

INERGY MIDSTREAM, L.P. (FORMERLY INERGY MIDSTREAM, LLC) CONSOLIDATED STATEMENTS OF CASH FLOWS (continued) (in millions)
	Year Ended September 30,
	2012			2011			2010
				(a)			(a)
Financing activities
Proceeds from the issuance of long-term debt	$	509.9		$	—		$	—
Principal payments on long-term debt	(93.4		)	—			(8.3		)
Equity contributions from parent	—			66.8			18.3
Acquisition of minority interest	—			—			(18.3		)
Distribution to Inergy, L.P.	(163.3		)	(7.4		)	(5.9		)
Distributions paid to non-controlling partners	—			—			(0.6		)
Distributions to shareholders	(14.6		)	—			—
Principal payment on promissory note	(255.0		)	—			—
Borrowings from related party	38.8			86.6			62.4
Payments to related party	(39.1		)	(77.1		)	(90.8		)
Net proceeds from issuance of common units	292.4			—			—
Payment for US Salt, LLC in excess of the acquired book value (Note 10)	(74.8		)	—			—
Other	(0.1		)	—			—
Payments for deferred financing costs	(5.2		)	—			—
Net cash provided by (used in) financing activities	195.6			68.9			(43.2		)
Net decrease in cash	—			—			(3.6		)
Cash at beginning of period	—			—			3.6
Cash at end of period	$	—		$	—		$	—
Supplemental disclosure of cash flow information
Cash paid during the period for interest	$	0.5		$	—		$	—
Supplemental schedule of noncash investing and financing activities
Net change to property, plant and equipment through accounts payable and accrued expenses	$	29.6		$	13.5		$	(5.4	)
Net change to property, plant and equipment through non-cash capitalized interest	$	1.7		$	8.7		$	6.4
Extinguishment of indebtedness owed to Inergy, L.P.	$	152.8		$	—		$	—
Assumption of promissory note of Inergy, L.P. (Note 6)	$	255.0		$	—		$	—
Acquisitions, net of cash acquired:
Current assets	$	—		$	0.5		$	—
Property, plant and equipment	—			66.3			—
Total acquisitions, net of cash acquired	$	—		$	66.8		$	—

(a) Retrospectively adjusted as described in Note 1.

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

71

INERGY MIDSTREAM, L.P.

(FORMERLY INERGY MIDSTREAM, LLC)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1 - Organization and Basis of Presentation

Organization

Inergy Midstream, LLC was formed in September 2004 by Inergy, L.P. (“Inergy”) to acquire, develop, own and operate midstream energy assets. In connection with its initial public offering (“IPO”) of common units representing limited partnership interests, (i) Inergy Midstream, LLC converted into a Delaware limited partnership and changed its name to Inergy Midstream, L.P. (the “Company”) on November 14, 2011, and (ii) the Company transferred to Inergy 100% of its membership interest in two wholly owned subsidiaries (US Salt, LLC and Tres Palacios Gas Storage LLC) on November 25, 2011. The Company's common units began trading on the New York Stock Exchange (“NYSE”) on December 16, 2011 under the symbol “NRGM,” and the IPO closed on December 21, 2011.

The Company issued 18,400,000 common units in the IPO, including 2,400,000 common units issued under the underwriters' overallotment rights. No public market for the common units existed prior to the IPO. Upon completion of the offering, the public owned common units representing an approximate 24.8% limited partnership interest in the Company and Inergy owned common units representing an approximate 75.2% limited partnership interest in the Company. Inergy indirectly owns the Company's general partnership interest, which entitles the general partner to management but no economic rights in the Company.

Inergy owns all of the Company's Incentive Distribution Rights (“IDRs”) which entitle it to receive 50% of all distributions by the Company in excess of the initial quarterly distribution of $0.37 per unit. IDRs, which represent a limited partnership ownership interest in the Company, are considered to be participating securities because they have the right to participate in earnings with common equity holders. Under the Company's partnership agreement, IDRs participate in net income only to the extent of the amount of cash distributions actually declared, thereby excluding the IDRs from participating in undistributed earnings or losses. Accordingly, the undistributed net income is allocated to the other ownership interests on a pro-rata basis. Distributions declared in the quarters ended June 30, 2012 and September 30, 2012, were $0.01 and $0.015 greater, respectively, than the initial annualized distribution and therefore IDRs in the amount of $0.7 million and $1.2 million were earned in the quarters ended June 30, 2012 and September 30, 2012, respectively.

On May 14, 2012, the Company acquired 100% of the membership interests in US Salt, LLC (“US Salt”) from Inergy. Following the US Salt acquisition, Inergy owned an approximate 75.0% ownership interest in the Company. See Note 10 for a discussion of the US Salt acquisition.

NRGM GP, LLC Change of Control Event

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

Nature of Operations

The Company's financial statements reflect two operating and reporting segments: storage and transportation operations and salt operations. The Company's storage and transportation operations are engaged primarily in the storage and transportation of natural gas and natural gas liquids (“NGLs”). Its operations are currently concentrated in the Northeast region of the United States. The Company's salt operations, which are located in New York, include the production and sale of salt products. US Salt is one of five major solution mined salt manufacturers in the United States, producing evaporated salt products for food, industrial, pharmaceutical and water conditioning uses.

72

INERGY MIDSTREAM, L.P.

(FORMERLY INERGY MIDSTREAM, LLC)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The Company owns and operates the following storage facilities:

• Stagecoach, a 26.3 billion cf 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;

• Thomas Corners, a 7.0 billion cf multi-cycle depleted reservoir natural gas storage facility located in Steuben County, New York;

• Steuben, a 6.2 billion cf single-turn depleted reservoir natural gas storage facility located in Steuben County, New York;

• Seneca Lake, a 1.5 billion cf multi-cycle salt dome reservoir natural gas storage facility located in Schuyler County, New York; and

• Bath, a 1.5 million barrel NGL storage facility located near Bath, New York.

The Company also owns and operates natural gas transportation assets in the Northeast, including:

• the compression and appurtenant facilities installed to expand transportation capacity on the Stagecoach north and south laterals (the “North-South Facilities”), which provide 325 MMcf/d of interstate transportation service to shippers;

• the MARC I Pipeline, a 39-mile, 30-inch interstate natural gas pipeline that will upon completion extend from the Company's Stagecoach south lateral interconnect with Tennessee Gas Pipeline's 300 Line and Transco's Leidy Line, which will initially provide 450 MMcf/d of firm transportation service to shippers; and

• Inergy Pipeline East, a 37.5-mile, 12-inch diameter intrastate natural gas pipeline in New York.

In addition, the Company owns 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.

Basis of Presentation

On May 14, 2012, the Company acquired 100% of the membership interests in US Salt from Inergy (“US Salt Acquisition”). The US Salt Acquisition is reflected in the Company's consolidated financial statements based on the historical values, and periods prior to the acquisition have been retrospectively adjusted to include the historical balances of US Salt. This accounting treatment is similar to the pooling of interests and is required as the transaction is amongst entities under common control.

The accompanying consolidated financial statements include the accounts of Inergy Midstream, L.P. (formerly Inergy Midstream, LLC) and its wholly owned subsidiaries, Arlington Storage Company, LLC (“Arlington”), Central New York Oil And Gas Company, L.L.C. (“CNYOG”), Finger Lakes LPG Storage, LLC (“Finger Lakes”), Inergy Gas Marketing, LLC, Inergy Pipeline East, LLC, US Salt and Inergy Storage, Inc.  All significant intercompany transactions, including distribution income, and balances have been eliminated in consolidation.

Prior to the completion of the IPO on December 21, 2011 the Company was a wholly owned subsidiary of Inergy.  The consolidated financial statements that are presented for the periods prior to the IPO have been prepared to represent the net assets and related historical results of the Company as if it were a stand-alone entity with the exception that the operations of Tres Palacios Gas Storage LLC (which was assigned to Inergy on November 25, 2011) has been excluded from the historical results.  The general ledger of each entity owned by the Company (excluding Tres Palacios Gas Storage LLC) forms the primary basis for the accompanying financial statements.  Costs incurred by Inergy which benefit both the Company and Inergy's wholly owned subsidiaries, have been allocated in a manner described in “Allocation of Expenses” below.

73

INERGY MIDSTREAM, L.P.

(FORMERLY INERGY MIDSTREAM, LLC)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Principles of Consolidation

The accompanying consolidated financial statements include the accounts of the Company and its subsidiaries. All significant intercompany balances and transactions have been eliminated in consolidation.

Note 2 - Summary of Significant Accounting Policies

Revenue Recognition

Revenue for natural gas and NGL firm storage is recognized ratably over the contract period regardless of the volume of natural gas or NGL stored by the Company's customers, revenue from natural gas firm storage is also affected to a lesser extent by volumes of storage gas received and or delivered by the Company's customers. Revenue for transportation services is recognized ratably over the contract period. Transportation revenue is derived from the sale of capacity that the Company has secured on certain third party pipelines, revenues for transportation on natural gas pipelines acquired in the Seneca Lake acquisition in July 2011, and transportation revenue from placing the North-South Facilities into service in the 2012 fiscal year. Revenue from transportation services is also affected to a lesser extent by volumes of gas transported during the period. Revenue from hub services is recognized ratably over the contract period. The contract period for hub services is typically less than one year. Revenues from salt are recognized when product is shipped to the customer or when certain contractual performance requirements have otherwise been met.

Expense Classification

Storage related costs consist of the direct costs to operate the storage and transportation facilities including power, contractor and fuel costs. These costs support the revenue generated from firm storage, hub services and transportation services due to the intertwined nature of our assets. The Company's transportation related costs consist primarily of costs to procure firm transportation capacity on certain pipelines. With the acquisition of Seneca Lake and two related pipelines on July 13, 2011, transportation related costs also consist of direct costs to operate Seneca Lake's pipeline lateral and the East pipeline. In limited instances, the Company may sell inventory obtained from fuel-in-kind collections. The cost basis of this inventory will be recorded in storage related costs. Operating and administrative expenses consist of all expenses incurred by the Company other than those described above in storage and transportation related costs and depreciation and amortization. Certain operating and administrative expenses and depreciation and amortization are incurred in providing storage services, but are not included in storage and transportation related costs. These amounts were $44.3 million, $35.6 million and $33.9 million during the years ended September 30, 2012, 2011 and 2010, respectively.

Credit Risk and Concentrations

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.

One customer, ConEdison, accounted for approximately 14%, 16% and 18% of the Company's total revenue for the fiscal years ended September 30, 2012, 2011 and 2010, respectively.  No other customer accounted for 10% or more of the Company's total revenue in those years. All ConEdison revenues are captured in the storage and transportation segment.

ConEdison accounted for 11% and 13% of the Company's consolidated accounts receivable at September 30, 2012 and 2011, respectively.

74

INERGY MIDSTREAM, L.P.

(FORMERLY INERGY MIDSTREAM, LLC)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Use of Estimates

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

Inventories

Inventories for storage and transportation operations, consisting primarily of natural gas, are stated at the lower of cost or market and are computed predominantly using the average cost method. Inventories for salt operations are stated at the lower of cost or market, cost being principally determined on the first-in, first-out method. All costs associated with the production of finished goods at the salt production facility are captured as inventory costs.

Property, Plant and Equipment

Property, plant and equipment are stated at historical cost less accumulated depreciation. The Company capitalizes all construction related direct labor and material costs as well as the cost of funds used during construction. Amounts capitalized for cost of funds used during construction amounted to $5.3 million, $8.7 million and $6.4 million for the years ended September 30, 2012, 2011 and 2010, respectively. Depreciation is computed by the straight-line method over the estimated useful lives of the assets, as follows:

	Years
Land, improvements and buildings	15-25
Office furniture and equipment	3-7
Vehicles	3-5
Base gas	10
Plant equipment	3-20

Salt deposits are depleted on a unit of production method. Maintenance and repairs are charged to expense as incurred.

The Company reviews its long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If such events or changes in circumstances are present, a loss is recognized if the carrying value of the asset is in excess of the sum of the undiscounted cash flows expected to result from the use of the asset and its eventual disposition. An impairment loss is measured as the amount by which the carrying amount of the asset exceeds the fair value of the asset. The Company has not identified any indicators that suggest the carrying amount of an asset may not be recoverable for the period ended September 30, 2012.

Identifiable Intangible Assets

Intangible assets acquired in the acquisition of a business are required to be separately recognized if the benefit of the intangible asset is obtained through contractual or other legal rights, or if the intangible asset can be sold, transferred, licensed, rented or exchanged, regardless of the acquirer's intent to do so. Deferred financing costs represent financing costs incurred in obtaining financing and are being amortized over the term of the related debt.

The Company has recorded certain identifiable intangible assets, which are amortized on a straight-line basis over their estimated economic lives, as follows:

	Weighted-Average Life (years)
Customer accounts	19.5
Deferred financing costs	5.0

75

INERGY MIDSTREAM, L.P.

(FORMERLY INERGY MIDSTREAM, LLC)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Estimated amortization, including amortization of deferred financing costs reported as interest expense, for the next five years ending September 30, is as follows (in millions):

Year Ending September 30,
2013	$	3.1
2014	3.1
2015	3.1
2016	3.1
2017	2.1

Goodwill

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

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

The Company completed its annual impairment test for each of its reporting units and determined that no impairment existed as of September 30, 2012.

Income Taxes

The Company and its majority unitholder, Inergy, are generally not subject to federal or state income tax. Therefore, the earnings of the Company are included in the federal and state income tax returns of its common unitholders and, as a result of Inergy's majority ownership interest in the Company, the individual partners of Inergy. 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 Company's partnership agreement.

Cash and Cash Equivalents

The Company defines cash equivalents as all highly liquid investments with maturities of three months or less when purchased.

Income Per Unit

The Company calculates basic net income per limited partner unit by utilizing the two class method. Net income available to partners and the weighted-average number of units outstanding are presented only for the period subsequent to the IPO on December 21, 2011. Earnings (net income available to partners) of US Salt is presented only for the period subsequent to the acquisition on May 14, 2012. Basic and diluted net income per unit are the same, as there are no potentially dilutive units outstanding at September 30, 2012.

Fair Value

The carrying amounts of cash, accounts receivable, accounts payable and debt approximate their fair value.

76

INERGY MIDSTREAM, L.P.

(FORMERLY INERGY MIDSTREAM, LLC)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Transactions with Inergy and Inergy Propane, LLC

Inergy, through its subsidiary Inergy Propane, LLC, has historically provided the Company with funding to support its acquisition, capital expansion and working capital needs. The amounts provided by Inergy to finance acquisitions were considered to be permanent investments by Inergy and have accordingly been classified as parent company's investment on the consolidated financial statements of the Company. Amounts financed to support capital expansion and working capital needs, net of what the Company provided to Inergy Propane, LLC, were considered to be loans and were classified as payable to Inergy Propane, LLC and Inergy on the Company's consolidated financial statements. In connection with the Company's IPO on December 21, 2011, Inergy and Inergy Propane, LLC extinguished $152.8 million of indebtedness owed by the Company, which was treated as a capital contribution by Inergy.

Subsequent to the IPO, the Company intends to use its revolving credit facility to finance acquisitions and its capital expansion and working capital needs.

Interest on intercompany loans provided by Inergy was historically charged on the loan balances during the period of construction of the Company's expansion projects.

Allocation of Expenses

The Company shares common management, operating and administrative and overhead costs with Inergy. The shared costs allocated to the Company totaled $12.3 million (including $5.8 million of unit-based compensation charges) and $9.8 million for the years ended September 30, 2012 and 2011, respectively. In conjunction with its IPO, the Company entered into an Omnibus Agreement with Inergy that requires the Company to reimburse Inergy for all shared costs incurred on its behalf. As the Omnibus Agreement was not in place for the prior period, management estimated an allocation of these costs and this amount has been reflected in the financial statements. Management believes the assumptions and allocations were made on a reasonable basis. Due to the nature of these shared costs, it is not practicable to estimate what the costs would have been on a stand-alone basis. Accordingly, the accompanying financial statements may not necessarily be indicative of the conditions that would have existed, or the results of operations that would have occurred, if the Company had operated as a stand-alone entity.

Comprehensive Income (Loss)

Comprehensive income includes net income and other comprehensive income. Other comprehensive income includes the realized loss on a derivative instrument that the Company entered into to hedge the purchase of base gas for one storage facility. The amount included in other comprehensive income associated with this derivative is being reclassified to earnings over the same period that the hedged base gas is recorded in earnings. The amount reclassified to earnings was for the year ended September 30, 2012.

Property Tax Receivable

The Company receives property tax benefits under New York's Empire State Development program. The amounts due to be refunded to the Company under this program amounted to $5.7 million and $2.4 million as of September 30, 2012 and 2011, respectively. At September 30, 2012, $2.0 million of the amounts due to be refunded were classified in prepaid expenses and other current assets, and $3.7 million were classified in other long-term assets on the consolidated balance sheets. At September 30, 2011, $2.4 million were classified in prepaid expenses and other current assets on the consolidated balance sheets.

Prepaid Property Taxes

The Company prepays property taxes in certain taxing jurisdictions and thus records the amount of taxes relating to future periods in prepaid expenses and other current assets totaling $1.7 million and $1.5 million at September 30, 2012 and 2011, respectively.

Business Interruption Insurance

In December 2010, the Stagecoach natural gas storage facility experienced an event that caused damage to various components at its Stagecoach central compressor station near Owego, New York. The loss event caused the Company to incur additional costs to maintain operations, and revenues were lost in addition to the damage to the compressor equipment. The Company is

77

INERGY MIDSTREAM, L.P.

(FORMERLY INERGY MIDSTREAM, LLC)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

insured for such matters and has recorded $1.1 million, $3.4 million, and $2.1 million during fiscal 2012 to hub services revenues, storage related costs, and property plant and equipment, respectively, for insurance recoveries. The Company has accounted for the recoveries of business interruption insurance losses in accordance with Accounting Standards Codification 225 and recorded the yet to be collected insurance proceeds totaling $0.7 million in prepaid expenses and other current assets on the Company's balance sheet as of September 30, 2012.

Construction Work in Process Accrual

The Company has accrued for certain construction work in process relating to construction efforts on various growth projects. At September 30, 2012 the Company had accrued $40.3 million relating to construction work in process, of which $39.4 million was classified as accrued expenses, and $0.9 million was classified as accounts payable on the consolidated balance sheets. At September 30, 2011 the Company had accrued $15.4 million relating to construction work in process, of which $9.1 million was classified as accrued expenses, and $6.3 million was classified as accounts payable 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. The fair value of these AROs could not be made as settlement dates (or range of dates) associated with these assets were not estimable.

Accounting for Unit-Based Compensation

The Company has a unit-based employee compensation plan and all share-based payments to employees, including grants of employee stock options, are recognized in the income statement based on their fair values. The amount of compensation expense recorded by the company during the year ended September 30, 2012 was $6.5 million ($5.8 million allocated by Inergy for Inergy units and $0.7 million for Inergy Midstream units). The amount of compensation expense allocated to the Company during the years ended September 30, 2011 and 2010, was $1.8 million and $3.5 million, 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 reportable segments, the Company examined the way it organizes its business internally for making operating decisions and assessing business performance. See Note 12 for disclosures related to the Company's storage and transportation and salt segments.

Non-controlling Interest

The non-controlling interest on the consolidated statement of operations is related entirely to minority partners in the Company's Steuben natural gas storage facility. The non-controlling interest was acquired during the year ended September 30, 2010.

Recently Issued Accounting Pronouncements

In June 2011 the FASB issued Accounting Standards Update No. 2011-05, “Presentation of Comprehensive Income” (“ASU 2011-05”). Under ASU 2011-05, an entity has the option to present the total of comprehensive income, the components of net income, and the components of other comprehensive income either in a single continuous statement of comprehensive income or in two separate but consecutive statements. Under both options, an entity will be required to present each component of net income along with total net income, each component of other comprehensive income along with a total for other comprehensive income, and a total amount for comprehensive income. Furthermore, regardless of the presentation methodology elected, the entity will be required to present on the face of the financial statements reclassification adjustments for items that are reclassified from other comprehensive income to net income. In December 2011, the FASB issued Accounting Standards Update No. 2011-12, "Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05" ("ASU 2011-12") which deferred this requirement in order to allow the FASB more time to determine whether reclassification adjustments should be required to be presented on the face of the financial statements. The amendments contained in ASUs 2011-05 and 2011-12 do not change

78

INERGY MIDSTREAM, L.P.

(FORMERLY INERGY MIDSTREAM, LLC)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

the items that must be reported in other comprehensive income or when an item of other comprehensive income must be reclassified to net income. The amendments also do not affect how earnings per share is calculated or presented. The Company adopted ASUs 2011-05 and 2011-12 in the fourth quarter of the year ended September 30, 2012. The Company elected to present the total of comprehensive income in two separate but consecutive statements.

Note 3 - Certain Balance Sheet Information

Inventories

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

	September 30,
	2012		2011
Parts and supplies	$	4.2	$	3.7
Natural gas	0.4		0.6
Raw materials	0.2		0.2
Finished goods	0.8		0.6
Total inventories	$	5.6	$	5.1

Property, Plant and Equipment

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

	September 30,
	2012		2011
Plant equipment	$	225.3	$	173.4
Salt deposits	41.6		41.6
Land and buildings	393.3		358.0
Vehicles	3.0		2.5
Construction in progress	331.4		169.6
Base gas	73.1		71.1
Office furniture and equipment	1.0		0.7
	1,068.7		816.9
Less: accumulated depreciation	200.8		152.9
Total property, plant and equipment, net	$	867.9	$	664.0

Depreciation expense totaled $47.8 million, $40.8 million and $38.5 million for the years ended September 30, 2012, 2011 and 2010, respectively. Depletion expense totaled $0.2 million for the years ended September 30, 2012, 2011 and 2010.

79

INERGY MIDSTREAM, L.P.

(FORMERLY INERGY MIDSTREAM, LLC)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Intangible Assets

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

	September 30,
	2012			2011
Customer accounts	$	38.3		$	39.5
(accumulated amortization—customer accounts)	(13.4		)	(12.7		)
Covenants not to compete	—			7.5
(accumulated amortization—covenants not to compete)	—			(7.0		)
Deferred financing	5.2			—
(accumulated amortization—deferred financing costs)	(0.8		)	—
Total intangible assets, net	$	29.3		$	27.3

Amortization and interest expense associated with the above described intangible assets for the years ended September 30, 2012, 2011 and 2010, amounted to $3.3 million, $2.9 million and $3.7 million, respectively.

Note 4 - Acquisitions

Seneca Lake Natural Gas Storage acquisition

On July 13, 2011, the Company acquired the Seneca Lake natural gas storage facility in Schuyler County, New York, and two related pipelines for approximately $66.8 million from New York State Electric & Gas Corporation (“NYSEG”). The natural gas storage facility and its west storage lateral were acquired by Arlington and are subject to jurisdiction by the Federal Energy Regulatory Commission (“FERC”). The other pipeline, the East Pipeline (formerly known as the Seneca Lake east lateral), was acquired by Inergy Pipeline East, LLC and is subject to regulation by the New York State Public Service Commission. This acquisition was funded by an equity contribution from Inergy. This acquisition of assets collectively constitutes a business and has been accounted for under FASB Accounting Standards Codification 805.

The primary purpose of this acquisition was to acquire natural gas storage and transportation equipment. In addition to the equipment, the Company assumed a storage contract with one customer (Dominion) and entered into new long-term storage and transportation contracts with NYSEG. The Company believes these contracts are reflective of market conditions at the time of acquisition and, given the terms of the contracts, including the remaining tenure, no amounts have been reflected in the opening balance sheet for acquired intangible assets. The Company has determined that the fair value of the acquired property, plant and equipment is consistent with, and approximates, the total purchase price. Therefore, there are no amounts for acquired intangible assets or goodwill.

The following table summarizes the fair value of the assets acquired at the acquisition date (in millions):

	July 13, 2011
Plant equipment	$	66.3
Prepaid expenses	0.5
Net assets acquired	$	66.8

80

INERGY MIDSTREAM, L.P.

(FORMERLY INERGY MIDSTREAM, LLC)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following represents the unaudited pro forma consolidated statements of operations as if Seneca Lake had been included in the consolidated results of the Company for the years ended September 30, 2011 and 2010 (in millions).

	Pro Forma Consolidated Statements of Operations
	Year Ended		Year Ended
	September 30, 2011		September 30, 2010
Revenue	$	169.9	$	155.4
Net income	$	55.0	$	44.6

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

Note 5 - Long-Term Debt

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

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

The Company's outstanding balance on the Credit Facility at September 30, 2012 amounted to $416.5 million. Outstanding standby letters of credit under the Credit Facility amounted to $2.0 million at September 30, 2012. As a result, the Company has approximately $181.5 million of remaining capacity at September 30, 2012, subject to compliance with any applicable covenants under such facility.

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

• incur additional debt;

• make distributions on or redeem or repurchase units;

• make certain investments and acquisitions;

• incur or permit certain liens to exist;

• enter into certain types of transactions with affiliates;

• merge, consolidate or amalgamate with another company; and

• transfer or otherwise dispose of assets.

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

81

INERGY MIDSTREAM, L.P.

(FORMERLY INERGY MIDSTREAM, LLC)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Borrowings under the Credit Facility are generally secured by pledges of the equity interests in the Company's wholly owned subsidiaries, liens on substantially all of the Company's real and personal property, and guarantees issued by all of the Company's subsidiaries. Borrowings under the Credit Facility, other than swing line loans, will bear interest at its option at either:

• the Alternate Base Rate, which is defined as the highest of (i) the federal funds rate plus 0.50%; (ii) JP Morgan's prime rate; or (iii) the Adjusted LIBO Rate plus 1%; plus a margin varying from 0.75% to 1.75% depending on the Company'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 the Company'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 Credit Facility is subject to a commitment fee ranging from 0.30% to 0.50% per annum according to its most recent total leverage ratio. Interest on Alternative Base Rate loans is payable quarterly or, if the Adjusted LIBO Rate applies, it may be paid at more frequent intervals.

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

Note 6 - Partners’ Capital

Classes of Unitholders

The Company has three classes of unitholders which include general partner, limited partner and incentive distribution rights. The Company's partnership agreement requires that, within 45 days after the end of each quarter, beginning with the quarter ending December 31, 2011, the Company will distribute all available cash (as defined in the Company's partnership agreement) to common unitholders of record on the applicable record date. The general partner will not be entitled to distributions on its non-economic general partner interest. The incentive distribution rights are entitled to receive 50% of the cash distributed from operating surplus (as defined in the Company's partnership agreement) in excess of the initial quarterly distribution of $0.37.

Inergy, as the initial holder of the Company's incentive distribution rights, has the right under its partnership agreement to elect to relinquish the right to receive incentive distribution payments based on the initial quarterly distribution and to reset, at a higher level, the quarterly distribution amount (upon which the incentive distribution payments to Inergy would be set). If Inergy elects to reset the quarterly distribution, it will be entitled to receive a number of newly issued Inergy Midstream common units. The number of common units to be issued to Inergy will equal the number of common units that would have entitled the holder to the quarterly cash distribution in the prior quarter equal to the distribution to Inergy on the IDRs in such prior quarter. As the reset election has not been made, no additional units have been issued. For accounting purposes, diluted earnings per unit can be impacted, (even if the reset election has not been made), if the combined impact of issuing the additional units and resetting the cash target distribution is dilutive. Currently, diluted earnings per unit has not been impacted because the combined impact is antidilutive.

Common Unit Offerings

On December 21, 2011, the Company closed its initial public offering of 18,400,000 common units, which included 2,400,000 common units issued as a result of the underwriters exercising their overallotment provision. The common units began trading on the NYSE on December 16, 2011 under the symbol “NRGM.”

On May 14, 2012, the Company issued 473,707 shares to Inergy for partial consideration of US Salt. See Note 10 for additional information regarding the acquisition of US Salt.

82

INERGY MIDSTREAM, L.P.

(FORMERLY INERGY MIDSTREAM, LLC)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Quarterly Distributions of Available Cash

The Company is required to make quarterly cash distributions of all of its Available Cash, generally defined as income (loss) before income taxes plus depreciation and amortization, less maintenance capital expenditures and net changes in reserves established by the General Partner for future requirements. These reserves are retained to provide for the proper conduct of the Company's business, or to provide funds for distributions with respect to any one or more of the next four fiscal quarters.

The Company is expected to make distributions of its Available Cash within 45 days after the end of each fiscal quarter ending December, March, June and September to holders of record on the applicable record date. A summary of the Company's quarterly distributions for the year ended September 30, 2012, is presented below:

Year Ended
September 30, 2012
Record Date	Payment Date	Per Unit Rate (a)	Distribution Amount (in millions)
February 7, 2012	February 14, 2012	$0.04	$3.0
May 8, 2012	May 15, 2012	0.37	27.6
August 7, 2012	August 14, 2012	0.38	29.3
			$59.9

(a) The $0.04 cash distribution per limited partner unit corresponds to an initial quarterly cash distribution of $0.37 per quarter ($1.48 annually) and represents the prorated distribution for the period of time from December 21, 2011, the closing of the Company's initial public offering, through December 31, 2011, the end of the first fiscal quarter.

On November 14, 2012, a quarterly distribution of $0.385 per limited partner unit was paid to unitholders of record on November 7, 2012, with respect to the fourth fiscal quarter of 2012.

Long-Term Incentive Plan

Inergy Midstream's general partner sponsors the long-term incentive plan for its employees, consultants and directors and the employees of its affiliates that perform services for the Company. The long-term incentive plan currently permits the grant of awards covering an aggregate of 7,432,500 common units, which can be granted in the form of unit options, phantom units and/or restricted units. As of September 30, 2012, all long-term incentive plan activity has been issued in the form of restricted units.

Restricted Units

A restricted unit is a common unit that participates in distributions and vests over a period of time yet during such time is subject to forfeiture. The compensation committee may make grants of restricted units to employees, directors and consultants containing such terms as the compensation committee determines. The compensation committee will determine the period over which restricted units granted to participants will vest. The compensation committee, in its discretion, may base its determination upon the achievement of specified financial objectives or other events. In addition, the restricted units will vest upon a change in control as defined in the long-term incentive plan. If a grantee's employment, consulting arrangement or membership on the board of directors terminates for any reason, the grantee's restricted units will be automatically forfeited unless, and to the extent, the compensation committee or the terms of the award agreement provide otherwise.

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

The Company granted 383,223 restricted units during the year ended September 30, 2012. Some of the restricted units are 100% vested on the fifth anniversary of the grant date, subject to the provisions as outlined in the restricted unit award agreement. Some of the restricted units vest 25% after the third year, 25% after the fourth year and 50% after the fifth year. The Company recognizes expense on these units each quarter by multiplying the closing price of the Company's common units on the date of grant by the number of units granted, and expensing that amount over the vesting period on a straight-line basis.

83

INERGY MIDSTREAM, L.P.

(FORMERLY INERGY MIDSTREAM, LLC)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

A summary of the Company's weighted-average grant date fair value for restricted units for the year ended September 30, 2012, is as follows: 

	Weighted-Average  Grant Date Fair Value		Number of Units
Non-vested at October 1, 2011	$	—	—
Granted during the period ended September 30, 2012	$	21.62	383,223
Vested during the period ended September 30, 2012	$	—	—
Forfeited during the period ended September 30, 2012	$	—	—
Non-vested at September 30, 2012	$	21.62	383,223

The compensation expense recorded by the Company related to these restricted unit awards was $0.7 million for the year ended September 30, 2012.

As of September 30, 2012, there was $7.6 million of total unrecognized compensation cost related to unvested share-based compensation awards granted to employees under the restricted unit plan. That cost is expected to be recognized over a five-year period.

Note 7 - Employee Benefit Plans

The Company has no employees. Inergy sponsors a 401(k) plan which is available to all of its employees after meeting certain requirements. The plan permits employees to make contributions up to 75% of their salary, up to statutory limits, which was $17,000 in 2012. The plan provides for matching contributions by Inergy for employees completing one year of service of at least 1000 hours. Aggregate matching contributions allocated to the Company were $0.2 million in fiscal 2012, 2011 and 2010.

Note 8 - Commitments and Contingencies

The Company has entered into certain purchase commitments in connection with the identified growth projects primarily related to the Watkins Glen NGL development project and the MARC I Pipeline. The Watkins Glen NGL development project entails the conversion of certain caverns created by US Salt into 2.1 million barrels of NGL storage.  The MARC I Pipeline project is a 39 mile, 30 inch bi-directional pipeline that will extend between the Company's Stagecoach south lateral interconnect with Tennessee Gas Pipeline Company's 300 Line near its compressor station 319 and Transco's Leidy Line near its compressor station 517, and will provide 550 MMcf/d of firm transportation capacity. At September 30, 2012, the total of these firm purchase commitments was $22.2 million and the purchases associated with these commitments are expected to occur over the next twelve months.

The Company is periodically involved in litigation proceedings. The results of litigation proceedings cannot be predicted with certainty; however, management believes that the Company 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.

In June 2010, the Company 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.

84

INERGY MIDSTREAM, L.P.

(FORMERLY INERGY MIDSTREAM, LLC)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The Company utilizes third-party insurance subject to varying retention levels of self-insurance, which management considers prudent.

Note 9 - Related Party Transactions

The Company has recorded sales to Inergy of $11.8 million, $4.0 million and $0.5 million for the years ended September 30, 2012, 2011 and 2010, respectively. The sales relate to storage space leased at the Company's Bath storage facility. These sales increased the Company's net income by $7.8 million, $1.3 million and $0.5 million for the years ended September 30, 2012, 2011 and 2010, respectively.

NRGM GP, LLC Change of Control Event

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

As discussed in Note 2, prior to the Company's IPO, Inergy funded certain of the Company's activities.

Note 10 - US Salt Acquisition

On May 14, 2012, the Company completed the US Salt Acquisition. The Company paid $182.5 million in cash and issued 473,707 common units directly to Inergy for the acquisition of US Salt. Additionally, all intercompany balances between US Salt and Inergy were extinguished in conjunction with the US Salt Acquisition.

The US Salt Acquisition is reflected in the Company's consolidated financial statements based on the historical values and periods prior to the acquisition have been retrospectively adjusted to include the historical balances of US Salt. This accounting treatment is similar to the pooling of interests and is required as the transaction is amongst entities under common control. The effect of recasting the Company's financial statements to account for this common control transaction increased net income $7.8 million, $11.9 million and $11.8 million for the years ended September 30, 2012, 2011 and 2010, respectively.

In connection with the US Salt Acquisition, (i) US Salt's guarantee of Inergy's senior notes, as well as the lien granted to the lenders of Inergy's credit agreement on US Salt's membership interest and substantially all of its assets, were released; and (ii) US Salt's membership interests and substantially all of its assets were pledged as collateral under the Company's Credit Facility.

85

INERGY MIDSTREAM, L.P.

(FORMERLY INERGY MIDSTREAM, LLC)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 11. Leases

The Company has certain noncancelable operating leases, mainly for railcars and equipment, the majority of which expire at various times over the next three years.

Future minimum lease payments under noncancelable operating leases for the next five years ending September 30 and thereafter consist of the following (in millions):

Year Ending September 30,
2013	$	0.5
2014	0.4
2015	0.1
2016	—
2017	—
Thereafter	—
Total minimum lease payments	$	1.0

Rent expense for operating leases for the years ended September 30, 2012, 2011 and 2010, totaled $0.4 million, $0.6 million and $0.3 million, respectively.

Note 12 - Segments

Effective with the US Salt Acquisition, the Company's financial statements reflect two operating and reportable segments: storage and transportation operations and salt operations. The Company's storage and transportation operations include storage and transportation of natural gas and NGLs for third parties. The Company's salt operations include the production and sale of salt products.

The identifiable assets associated with each reportable segment include accounts receivable and inventories.

Revenues, gross profit, identifiable assets, goodwill, property, plant and equipment, total assets and expenditures for property, plant and equipment for each of the Company's reportable segments are presented below (in millions):

	Year Ended September 30, 2012
	Storage and Transportation Operations		Salt Operations		Total
Firm storage revenues	$	94.5	$	—	$	94.5
Salt revenues	—		52.0		52.0
Transportation revenues	28.4		—		28.4
Hub services revenues	14.9		—		14.9
Gross profit (excluding depreciation and amortization)	126.7		21.7		148.4
Identifiable assets	14.0		10.9		24.9
Goodwill	90.2		6.3		96.5
Property, plant and equipment	953.3		115.4		1,068.7
Total assets	925.9		102.0		1,027.9
Expenditures for property, plant and equipment	245.9		6.0		251.9

86

INERGY MIDSTREAM, L.P.

(FORMERLY INERGY MIDSTREAM, LLC)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

	Year Ended September 30, 2011
	Storage and Transportation Operations		Salt Operations		Total
Firm storage revenues	$	90.4	$	—	$	90.4
Salt revenues	—		52.3		52.3
Transportation revenues	14.0		—		14.0
Hub services revenues	6.5		—		6.5
Gross profit (excluding depreciation and amortization)	95.1		21.7		116.8
Identifiable assets	10.8		10.4		21.2
Goodwill	90.2		6.3		96.5
Property, plant and equipment	707.4		109.5		816.9
Total assets	702.4		111.3		813.7
Expenditures for property, plant and equipment	112.0		8.6		120.6

	Year Ended September 30, 2010
	Storage and Transportation Operations		Salt Operations		Total
Firm storage revenues	$	81.0	$	—	$	81.0
Salt revenues	—		52.2		52.2
Transportation revenues	12.1		—		12.1
Hub services revenues	1.6		—		1.6
Gross profit (excluding depreciation and amortization)	82.7		22.2		104.9
Identifiable assets	8.5		9.5		18.0
Goodwill	90.2		6.3		96.5
Property, plant and equipment	529.3		100.8		630.1
Total assets	559.6		107.9		667.5
Expenditures for property, plant and equipment	44.1		11.6		55.7

87

INERGY MIDSTREAM, L.P.

(FORMERLY INERGY MIDSTREAM, LLC)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 13 - Quarterly Financial Data (Unaudited)

The Company's summarized unaudited quarterly financial data is presented below (in millions, except per unit information):

	Quarter Ended
	December 31		March 31		June 30		September 30
	(a)		(a)		(b)		(b)
Fiscal 2012
Revenues	$	46.8	$	46.9	$	48.6	$	47.5
Operating income	17.6		16.4		18.7		14.8
Net income	17.6		16.4		18.0		13.7
Net income available to partners	1.5		13.4		16.4		13.7
Net income per limited partner unit:
Basic	0.02		0.18		0.21		0.17
Diluted	0.02		0.18		0.21		0.17
Fiscal 2011
Revenues	$	38.9	$	38.6	$	42.0	$	43.7
Operating income	11.9		12.3		15.5		13.8
Net income	11.9		12.3		15.5		13.8

(a) The fiscal 2012 and 2011 periods were retrospectively adjusted as described in Note 1.

(b) The fiscal 2011 period was retrospectively adjusted as described in Note 1.

Note 14 - Subsequent Events

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

On November 16, 2012, the Company entered into Amendment No. 1 (the “Amendment”) with JPMorgan Chase Bank, N.A., as administrative agent, and the other lenders party thereto, which amends the Company's existing Credit Facility, dated as of December 21, 2011.  The Amendment, among other things, (i) amends the definition of Consolidated EBITDA to include projected Consolidated EBITDA attributable to fixed fee contracts from the Company's pending acquisition of Rangeland Energy, LLC; (ii) increases the Maximum Total Leverage Ratio to 5.50 to 1.0 for any two consecutive fiscal quarters ending on or immediately after the date of the consummation of a Permitted Acquisition in excess of $50 million; and (iii) adds a Senior Secured Leverage Ratio of 3.75 to 1.00 on and after the cumulative issuance of $200 million or more of Permitted Junior Debt.  

On November 14, 2012, a quarterly distribution of $0.385 per limited partner unit was paid to unitholders of record on November 7, 2012, with respect to the fourth fiscal quarter of 2012.

On November 5, 2012, the Company announced the planned acquisition of 100% of the ownership interest of Rangeland Energy, LLC ("Rangeland") in exchange for $425 million in cash, net of cash acquired in the transaction and subject to certain closing adjustments. The Company has already entered into an agreement to sell $225 million through a private placement of common units to qualified institutional investors conditioned upon and closing contemporaneously with the closing of the Rangeland acquisition.

The primary purpose of this acquisition is to acquire the crude oil loading terminal, storage facility, and interconnecting pipeline assets of Rangeland, which are located in Williams County, North Dakota. The Company's valuation of the assets acquired and liabilities assumed has not been completed as the acquisition has not closed to date. The Company expects the significant components of the valuation to include property, plant and equipment, intangible contract assets and goodwill.

88

INERGY MIDSTREAM, L.P.

(FORMERLY INERGY MIDSTREAM, LLC)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following represents the pro forma consolidated statements of operations as if Rangeland had been included in the consolidated results of the Company for the year ended September 30, 2012 (in millions):

	(Unaudited) Pro Forma Consolidated Statement of Operations
	Year Ended September 30, 2012
Revenue	$	193.2
Net Income	$	7.4

These amounts are based on certain assumptions made as to the purchase accounting of the transaction. A final determination of the purchase accounting adjustments, including the allocation of the purchase price of the assets acquired and liabilities assumed based on their fair values, has not been made. Accordingly, the purchase accounting adjustments made in connection with the development of the unaudited pro forma are preliminary and subject to material change. Rangeland was a development stage entity (as defined by ASC Topic 915, Development Stage Entities) until recently, and began principal commercial operations during June 2012. The revenues and earnings for the acquired company are insignificant for the years ended September 30, 2011 and 2010 and thus are not presented. The acquisition is planned to close during December 2012, however, the Company provides no assurance regarding the timing or completion of the acquisition and additionally the amounts above are subject to change.

89

SIGNATURES

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 MIDSTREAM, L.P.
		By: NRGM GP, LLC
		(its general partner)
Dated:	November 20, 2012	By:	/s/    JOHN J. SHERMAN
			John J. Sherman, President, Chief Executive Officer and Director

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following officers and directors of NRGM GP, LLC, as general partner of Inergy Midstream, L.P., the registrant, in the capacities and on the dates indicated.

Date	Signature and Title
November 20, 2012	/S/    JOHN J. SHERMAN         John J. Sherman, President, Chief Executive Officer and Director (Principal Executive Officer)
November 20, 2012	/S/    MICHAEL J. CAMPBELL   Michael J. Campbell, Senior Vice President and Chief Financial Officer (Principal Financial Officer)
November 20, 2012	/S/    MICHAEL D. LENOX         Michael D. Lenox, Vice President and Chief Accounting Officer (Principal Accounting Officer)
November 20, 2012	/S/    WARREN H. GFELLER         Warren H. Gfeller, Director
November 20, 2012	/S/    ARTHUR B. KRAUSE         Arthur B. Krause, Director
November 20, 2012	/S/    RANDY E. MOEDER        Randy E. Moeder, Director

90

Schedule II

Inergy Midstream, L.P.

Valuation and Qualifying Accounts

(in millions)

Year Ended September 30,	Balance at beginning of period		Charged to costs and expenses		Other Additions		Deductions (write-offs)			Balance at end of period
Allowance for doubtful accounts
2012	$	—	$	—	$	—	$	—		$	—
2011	0.1		—		—		(0.1		)	—
2010	0.1		—		—		—			0.1

91