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EX-23.1 - CONSENT OF ERNST & YOUNG LLP - Crestwood Midstream Partners LPd221930dex231.htm
EX-3.1 - LIMITED LIABILITY COMPANY AGREEMENT OF INERGY MIDSTREAM LLC - Crestwood Midstream Partners LPd221930dex31.htm
Table of Contents
Index to Financial Statements

As filed with the Securities and Exchange Commission on October 7, 2011

Registration No. 333-176445

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Amendment No. 1

to

Form S-1

REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933

 

Inergy Midstream, LLC

 

(Exact Name of Registrant as Specified in Its Charter)

 

Delaware   4922   20-1647837
(State or Other Jurisdiction of
Incorporation or Organization)
  (Primary Standard Industrial
Classification Code Number)
  (I.R.S. Employer
Identification Number)

 

Two Brush Creek Boulevard

Suite 200

Kansas City, Missouri 64112

(816) 842-8181

(Address, Including Zip Code, and Telephone Number, Including Area Code, of Registrant’s Principal Executive Offices)

 

R. Brooks Sherman, Jr.

Two Brush Creek Boulevard

Suite 200

Kansas City, Missouri 64112

(816) 842-8181

(Name, Address, Including Zip Code, and Telephone Number, Including Area Code, of Agent for Service)

 

Copies to:

David P. Oelman

Gillian A. Hobson

Vinson & Elkins L.L.P.

1001 Fannin Street, Suite 2500

Houston, Texas 77002

(713) 758-2222

 

Joshua Davidson

Laura L. Tyson

Baker Botts L.L.P.

One Shell Plaza

910 Louisiana Street

Houston, Texas 77002

(713) 229-1234

 

Approximate date of commencement of proposed sale to the public: As soon as practicable after this Registration Statement becomes effective.

 

If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box.  ¨

 

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

 

If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

 

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

 

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 the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

 

Large accelerated filer  ¨    Accelerated filer  ¨    Non-accelerated filer  x    Smaller reporting company  ¨

(Do not check if a smaller reporting company)

 

The Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the Registration Statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.


Table of Contents
Index to Financial Statements

EXPLANATORY NOTE

 

Inergy Midstream, LLC, the Registrant whose name appears on the cover of this Registration Statement, is a Delaware limited liability company. Prior to the completion of the offering of common units pursuant to this Registration Statement, Inergy Midstream, LLC will be converted into a Delaware limited partnership and renamed Inergy Midstream, L.P. Common units representing limited partner interests in Inergy Midstream, L.P. are being offered by the prospectus included as part of this Registration Statement. Except for the historical financial statements, the presentation in the prospectus included as part of this Registration Statement speaks as if the conversion has occurred.


Table of Contents
Index to Financial Statements

PROSPECTUS (Subject to Completion)

Issued         , 2011

 

Common Units

Inergy Midstream, L.P.

 

REPRESENTING LIMITED PARTNER INTERESTS

 

 

 

This is the initial public offering of our common units representing limited partner interests. We are offering          common units. Prior to this offering, there has been no public market for our common units. We anticipate that the initial public offering price will be between $         and $        per common unit. We intend to apply to list our common units on the New York Stock Exchange under the symbol “NRGM.”

 

 

 

Investing in our common units involves risks. See “Risk Factors” beginning on page 18.

 

These risks include the following, among others:

 

   

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 the initial quarterly distribution to our common unitholders.

 

   

On a pro forma basis, we would have had insufficient cash available for distribution to pay the full initial quarterly distribution on all common units for the fiscal year ended September 30, 2010 and the twelve months ended June 30, 2011.

 

   

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

 

   

Our natural gas storage and transportation services are subject to extensive regulation by federal, state and local regulatory authorities; regulatory measures adopted by such authorities could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions.

 

   

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

 

   

We depend on third-party pipelines connected to our natural gas 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.

 

   

Increased competition from other companies that provide storage or transportation services, or services that can substitute for storage or transportation services, could have a negative impact on the demand for our services, which could adversely affect our financial results.

 

   

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

 

   

Our partnership agreement limits the liability of and reduces fiduciary duties owed by our general partner and also restricts the remedies available to our common unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty.

 

   

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

 

   

We will not have any subordinated units outstanding, and Inergy, L.P. is entitled to receive 50% of all cash that we distribute in excess of the initial quarterly distribution of $         per common unit. As a result, common units will bear any and all shortfalls in the amount of cash needed to pay the initial quarterly distribution and will not be entitled to arrearages.

 

   

Common unitholders will experience immediate and substantial dilution in net tangible book value per common unit of $        per common unit.

 

   

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

 

 

 

PRICE $         A COMMON UNIT

 

 

 

      

Price to Public

    

Underwriting
Discounts and
Commissions(1)

    

Proceeds to Inergy
Midstream, L.P.

Per Common Unit

     $                          $                          $                    

Total

     $                          $                          $                    

 

(1)   Excludes an aggregate structuring fee payable to Morgan Stanley & Co. LLC and Barclays Capital Inc. that is equal to 0.375% of the gross proceeds from this offering, or $            . For additional information about underwriting compensation, see “Underwriting.”

 

We have granted the underwriters a 30-day option to purchase up to an additional          common units from us on the same terms and conditions as set forth above if the underwriters sell more than          common units in this offering.

 

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

 

The underwriters expect to deliver the common units to purchasers on                     , 2011.

 

 

Joint Structuring Agents

 

MORGAN STANLEY    BARCLAYS CAPITAL

 

                    , 2011

 

The information in this prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and we are not soliciting an offer to buy these securities in any jurisdiction where the offer or sale is not permitted.


Table of Contents
Index to Financial Statements

TABLE OF CONTENTS

 

     Page  

SUMMARY

     1   

Inergy Midstream, L.P.

     1   

Inergy, L.P.

     4   

Risk Factors

     5   

Our Management

     6   

Summary of Conflicts of Interest and Fiduciary Duties

     7   

Principal Executive Offices

     7   

Formation Transactions and Partnership Structure

     7   

Ownership of Inergy Midstream, L.P.

     9   

The Offering

     10   

Summary Historical and Pro Forma Financial and Operating Data

     14   

Non-GAAP Financial Measures

     16   

RISK FACTORS

     18   

Risks Inherent in Our Business

     18   

Risks Inherent in an Investment in Us

     30   

Tax Risks to Common Unitholders

     39   

USE OF PROCEEDS

     43   

CAPITALIZATION

     44   

DILUTION

     45   

CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

     46   

General

     46   

Our Initial Quarterly Distribution

     48   

Unaudited Pro Forma Cash Available for Distribution

     49   

Estimated Cash Available for Distribution for the Twelve Months Ending December 31, 2012

     51   

Assumptions and Considerations

     53   

PROVISIONS OF OUR PARTNERSHIP AGREEMENT RELATING TO CASH DISTRIBUTIONS

     58   

Distributions of Available Cash

     58   

Operating Surplus and Capital Surplus

     59   

Capital Expenditures

     60   

Distributions of Available Cash from Operating Surplus

     61   

General Partner Interest

     61   

Incentive Distribution Rights

     61   

Percentage Allocations of Available Cash from Operating Surplus

     62   

NRGY’s Right to Reset Incentive Distribution Level

     62   

Distributions from Capital Surplus

     64   

Adjustment to the Initial Quarterly Distribution

     64   
     Page  

Distributions of Cash Upon Liquidation

     65   

SELECTED HISTORICAL AND PRO FORMA FINANCIAL AND OPERATING DATA

     66   

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

     69   

Overview

     69   

How We Generate Revenue

     70   

Factors That Impact Our Business

     70   

Future Trends and Outlook

     72   

How We Evaluate Our Operations

     73   

Results of Operations

     75   

Liquidity and Sources of Capital

     83   

Quantitative and Qualitative Disclosures About Market Risk

     87   

Recent Accounting Pronouncements

     87   

Critical Accounting Policies

     87   

Seasonality

     88   

NATURAL GAS INDUSTRY

     89   

Market Fundamentals

     89   

Natural Gas Storage Industry

     92   

Key Characteristics of Storage Facilities

     93   

Competition and Barriers to Entry

     94   

Value Drivers for Natural Gas Storage

     94   

NGL Industry Dynamics

     95   

BUSINESS

     97   

Overview

     97   

Our Assets

     97   

Our Growth Projects

     100   

Our Operations

     102   

Our Business Strategies

     105   

Our Competitive Strengths

     107   

Inergy, L.P.

     109   

Customers

     109   

Contracts

     110   

Competition

     110   

Regulation

     111   

Environmental and Occupational Safety and Health Regulation

     114   

Seasonality

     117   

Title to Properties and Rights-of-Way

     117   

Insurance

     117   

Employees

     117   

Legal Proceedings

     117   
 

 

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Index to Financial Statements
     Page  

MANAGEMENT

     118   

Management of Inergy Midstream, L.P.

     118   

Executive Officers and Directors of Our General Partner

     119   

Director Independence

     120   

Board Leadership Structure and Role in Risk Oversight

     120   

Committees of the Board of Directors

     120   

EXECUTIVE COMPENSATION

     122   

Compensation Discussion and Analysis

     122   

Long-Term Incentive Plan

     123   

Director Compensation

     123   

Compensation Committee Interlocks and Insider Participation

     123   

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

     124   

NRGM GP, LLC Change of Control Event

     124   

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

     125   

Distributions and Payments to Our General Partner and Its Affiliates

     125   

Agreements with Affiliates in Connection with the Transactions

     126   

NRGM GP, LLC Change of Control Event

     128   

Other Transactions with Related Persons

     128   

Procedures for Review, Approval and Ratification of Transactions with Related Persons

     129   

CONFLICTS OF INTEREST AND FIDUCIARY DUTIES

     130   

Conflicts of Interest

     130   

Fiduciary Duties

     135   

Indemnification

     136   

DESCRIPTION OF THE COMMON UNITS

     137   

The Common Units

     137   

Transfer Agent and Registrar

     137   

Transfer of Common Units

     137   

THE PARTNERSHIP AGREEMENT

     139   

Organization and Duration

     139   

Purpose

     139   

Cash Distributions

     139   

Capital Contributions

     139   

Limited Voting Rights

     140   

Applicable Law; Forum, Venue and Jurisdiction

     141   
     Page  

Limited Liability

     141   

Issuance of Additional Interests

     142   

Amendment of the Partnership Agreement

     143   

Merger, Consolidation, Conversion, Sale or Other Disposition of Assets

     145   

Dissolution

     145   

Liquidation and Distribution of Proceeds

     146   

Withdrawal or Removal of Our General Partner

     146   

Transfer of General Partner Interest

     147   

Transfer of Ownership Interests in the General Partner

     147   

Transfer of Incentive Distribution Rights

     147   

Change of Management Provisions

     147   

Limited Call Right

     148   

Non-Taxpaying Holders; Redemption

     148   

Non-Citizen Assignees; Redemption

     148   

Meetings; Voting

     149   

Voting Rights of Incentive Distribution Rights

     149   

Status as Limited Partner

     150   

Indemnification

     150   

Reimbursement of Expenses

     150   

Books and Reports

     151   

Right to Inspect Our Books and Records

     151   

Registration Rights

     151   

UNITS ELIGIBLE FOR FUTURE SALE

     152   

MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES

     153   

Taxation of the Partnership

     153   

Tax Consequences of Unit Ownership

     154   

Tax Treatment of Operations

     160   

Disposition of Units

     160   

Uniformity of Units

     163   

Tax-Exempt Organizations and Other Investors

     163   

Administrative Matters

     164   

State, Local and Other Tax Considerations

     166   

INVESTMENT IN INERGY MIDSTREAM, L.P. BY EMPLOYEE BENEFIT PLANS

     168   

UNDERWRITING

     169   

Listing

     170   

Lock-up Agreements

     170   

Price Stabilization and Short Positions

     171   

Indemnification

     171   

Pricing of the Offering

     171   
 

 

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     Page  

FINRA Conduct Rules

     171   

Conflicts of Interest

     171   

Electronic Distribution

     172   

VALIDITY OF OUR COMMON UNITS

     173   

EXPERTS

     173   

WHERE YOU CAN FIND MORE INFORMATION

     174   
 

 

You should rely only on the information contained in this prospectus or in any free writing prospectus we may authorize to be delivered to you. Neither we nor the underwriters have authorized anyone to provide you with additional or different information. We are offering to sell, and seeking offers to buy, our common units only in jurisdictions where offers and sales are permitted. The information in this prospectus is accurate only as of the date of this prospectus, regardless of the time of delivery of this prospectus or any sale of our common units.

 

The market data and certain other statistical information used throughout this prospectus are based on independent industry publications, government publications or other published independent sources. Some data is also based on our good faith estimates.

 

Until                     , 2011 (25 days after the date of this prospectus), all dealers that effect transactions in our common units, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealers’ obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.

 

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Index to Financial Statements

SUMMARY

 

This summary highlights information contained elsewhere in this prospectus. You should read the entire prospectus carefully, including the historical and pro forma consolidated financial statements and the notes to those financial statements, before investing in our common units. The information presented in this prospectus assumes (1) an initial public offering price of $             per common unit (the midpoint of the price range set forth on the cover page of this prospectus) and (2) unless otherwise indicated, that the underwriters’ option to purchase additional common units is not exercised. You should read “Risk Factors” beginning on page 18 for information about important risks that you should consider before buying our common units. We include a glossary of some of the terms used in this prospectus as Appendix B.

 

Prior to the closing of this offering, Inergy Midstream, LLC will convert from a Delaware limited liability company to a Delaware limited partnership and change its name to Inergy Midstream, L.P. Unless specifically stated, the information in this prospectus assumes that this conversion has occurred. References in this prospectus to “we,” “us,” “our” or similar terms when used in a historical context refer to Inergy Midstream, LLC and its subsidiaries, excluding Tres Palacios Gas Storage LLC and US Salt, LLC, which will be transferred to Inergy, L.P. in connection with the closing of this offering and are not reflected in the presentation of our financial statements. When used in the present tense or prospectively, those terms refer to Inergy Midstream, L.P. and its subsidiaries, as of the closing date of this offering. References in this prospectus to our “general partner” refer to NRGM GP, LLC, the general partner of Inergy Midstream, L.P. upon its conversion to a Delaware limited partnership. Unless the context indicates otherwise, (i) all references to “Inergy, L.P.” or “NRGY” refer to Inergy, L.P. (the parent company of NRGM GP, LLC) and its subsidiaries and affiliates other than Inergy Midstream, L.P., NRGM GP, LLC and their respective subsidiaries, as of the closing date of this offering, (ii) all references to volumes of natural gas storage capacity are expressed in billions of cubic feet, or Bcf, of natural gas and are approximations that have been rounded to the nearest 0.1 Bcf and (iii) all references to volumes of natural gas transportation capacity are expressed in millions of cubic feet of natural gas per day, or MMcf/d, and are approximations that have been rounded to the nearest 1.0 MMcf/d.

 

Inergy Midstream, L.P.

 

Overview

 

We are a fee-based, growth-oriented Delaware limited partnership formed by Inergy, L.P. (NYSE: NRGY) to own, operate, develop and acquire midstream energy assets. Our current asset base consists of natural gas and NGL storage and transportation assets located in the Northeast region of the United States. We own and operate four natural gas storage facilities located in New York and Pennsylvania that have an aggregate working gas storage capacity of 41.0 Bcf with high peak injection and withdrawal capabilities. We also own natural gas pipelines located in New York and Pennsylvania with 30 MMcf/d of intrastate transportation capacity and, upon completion of two pipeline projects that are currently under development, we will own 875 MMcf/d of interstate transportation capacity. In addition, we own and operate a 1.5 million barrel NGL storage facility located near Bath, New York. Our near-term strategy is to continue to develop a platform of interconnected natural gas assets that can be operated as an integrated Northeast storage and transportation hub.

 

Our business has expanded rapidly through internal growth initiatives and acquisitions since its inception in 2005. We have grown our natural gas storage capacity from 13.0 Bcf as of September 30, 2005 to 41.0 Bcf as of September 30, 2011, which does not include 38.4 Bcf of natural gas storage capacity owned by NRGY on the Texas Gulf Coast. We believe that our current asset base enables us to significantly expand our storage and transportation capacity through continued investment in attractive growth projects. We expect these growth projects will further increase connectivity among our natural gas facilities and with third-party pipelines, thereby resulting in increased demand for our services.

 

 

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Index to Financial Statements

Our significant growth projects include:

 

   

construction of the MARC I pipeline, a fully contracted natural gas transmission pipeline with 550 MMcf/d of interstate transportation service, which we expect to complete and place into service in July 2012 with contracts extending to 2022;

 

   

completion of our North/South expansion project, which involves the installation of additional compression facilities that will enable us to provide approximately 325 MMcf/d of interstate transportation service on a fully contracted basis, which we expect to complete and place into service in late October 2011 with contracts extending to 2016;

 

   

development of a 2.1 million barrel NGL storage facility located near Watkins Glen, New York, which is approximately 95% contracted and which we expect to complete and place into service by June 2012 with a contract extending to 2016; and

 

   

expansion of our Seneca Lake natural gas storage facility by an additional 0.6 Bcf of working gas storage capacity, which we expect to complete and place into service by December 2012.

 

Through our current assets, growth projects and potential acquisitions from NRGY and third parties, we believe we are well-positioned to benefit from the anticipated long-term growth in demand for natural gas and NGL storage and transportation services in the United States.

 

Our Assets

 

Our assets are strategically located close to or within demand-based market areas in the Northeast region of the United States, with access to multiple natural gas and NGL supply points, including Marcellus shale production volumes. We believe that our geographic location provides us with a competitive advantage for the services we offer. In determining which midstream assets we would continue to own in connection with this offering, we understand that NRGY identified assets that it believed would collectively generate stable cash flows and also have sufficient scale to enable us to grow through acquisitions and internal growth projects.

 

Natural Gas Storage

 

We own and operate the following four natural gas storage facilities, which are regulated by the Federal Energy Regulatory Commission, or FERC:

 

   

Stagecoach, a 26.3 Bcf high performance, multi-cycle 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 Bcf high performance, multi-cycle natural gas storage facility located in Steuben County, New York;

 

   

Seneca Lake, a 1.5 Bcf high performance, multi-cycle natural gas storage facility located in Schuyler County, New York; and

 

   

Steuben, a 6.2 Bcf single-turn natural gas storage facility located in Steuben County, New York.

 

Natural Gas Transportation

 

Our interstate transportation assets consist of our proposed MARC I pipeline and the facilities associated with our North/South expansion project. Our intrastate transportation asset consists of a 37.5-mile, 12-inch diameter intrastate pipeline, which we acquired in July 2011, that is located in New York and runs within approximately three miles of our Stagecoach north lateral’s point of interconnection with the Millennium Pipeline.

 

 

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NGL Storage

 

We own and operate a 1.5 million barrel NGL storage facility located near Bath, New York. The Bath storage facility is located approximately 210 miles northwest of New York City and 60 miles from our Stagecoach facility. It is supported by both rail and truck terminal facilities capable of loading and unloading 23 railcars per day and 17 truck transports per day.

 

Our Business Strategies

 

Our primary business strategy is to increase the cash distributions that we pay to our common unitholders by capitalizing on the anticipated long-term growth in the production of and demand for natural gas by owning, reliably operating and expanding interconnected natural gas and NGL storage and transportation assets in and around major North American production and demand centers. In executing this strategy, we intend to increase the scale and improve the functionality of our facilities to best serve our current and future customers’ needs, thereby increasing our cash flow and profitability over time. Our plan for executing this strategy includes the following key components:

 

   

Expand our existing Northeast facilities through internal growth projects to create an integrated storage and transportation hub. Our current development plans include (i) increasing transportation functionality and interconnectivity through our MARC I pipeline and North/South expansion project, (ii) increasing NGL storage capacity through our proposed Watkins Glen facility and (iii) adding natural gas storage capacity at our Seneca Lake facility.

 

   

Provide an unparalleled level of commitment and service to our customers through the ownership and development of critical energy infrastructure. We intend to continually enhance our storage and transportation services and increase our facilities’ connectivity in order to provide our customers with the highest possible level of service.

 

   

Pursue potential acquisitions from NRGY and third parties. In addition to acquisitions from third parties, we expect to have the opportunity to make acquisitions directly from NRGY in the future. However, NRGY is entitled under the omnibus agreement to review and has the first option on any third-party acquisition opportunities, is under no obligation to make acquisition opportunities available to us, is not restricted from competing with us and 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. NRGY’s midstream assets include:

 

   

the Tres Palacios natural gas storage facility located in Texas, which has 38.4 Bcf of existing storage capacity with potential expansion to approximately 48.0 Bcf upon the development of a fourth storage cavern;

 

   

US Salt, LLC, or US Salt, a solution-mining and salt production business with salt caverns that can be developed into natural gas and NGL storage capacity, with NRGY having identified for potential development certain salt caverns having up to approximately 10.0 Bcf of natural gas storage capacity by 2014; and

 

   

a West Coast NGL business located near Bakersfield, California.

 

   

Maintain stable cash flows supported by long-term, fee-based contracts. We will seek to minimize our direct commodity price exposure and maintain stable cash flows by generating substantially all of our revenues pursuant to multi-year, firm storage and transportation contracts with strong, creditworthy customers.

 

   

Maintain a conservative and flexible capital structure and target investment grade credit metrics in order to lower our overall cost of capital. We intend to maintain a balanced capital structure and target investment grade credit metrics which, when combined with our stable fee-based cash flows, will afford us efficient access to the capital markets at a competitive cost of capital.

 

 

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Our Competitive Strengths

 

We believe we are well positioned to execute our business strategies successfully because of the following competitive strengths:

 

   

Strategically located assets proximate to prolific shale plays (including the Marcellus shale) and high demand metropolitan markets in the Northeast. We believe that our location in and around the Marcellus shale and within 200 miles of the New York metropolitan market provides us with a distinct competitive advantage.

 

   

Inventory of internal growth projects in the attractive Northeast market. We are developing approximately $380 million in internal growth projects around our existing assets designed to enhance our profitability and increase our operating scale. We anticipate that these projects will allow us to better serve our customers’ storage and transportation needs, increase margins and enhance our ability to obtain contracts for the use of our assets.

 

   

Affiliation with NRGY, a leading propane and midstream master limited partnership. By virtue of NRGY’s significant economic stake in us, NRGY has a vested interest in our success and a strong incentive to support our growth. In addition, NRGY’s retained midstream business and expansion opportunities are of strategic interest to us and would complement our existing asset base by diversifying our cash flow sources. However, NRGY is not obligated to sell these assets to us or to jointly develop them with us.

 

   

High quality assets with multiple sources of supply and connectivity to service growing demand markets. Our assets are connected to diverse sources of supply, and we have connectivity to key long-haul pipelines that deliver natural gas to demand markets.

 

   

Stable, fee-based cash flows with long-term contracts and high quality customer base. Our operations consist predominantly of fee-based services that generate stable cash flows. As of August 31, 2011, approximately 95% of our revenue was obtained from fixed reservation fees under long-term agreements with strong, creditworthy customers, such as large East Coast utilities and major natural gas marketing firms.

 

   

Significant barriers to entry. Competitors who seek to add substantial capacity in the markets in which we currently operate may face significant obstacles to development. Particular development challenges include scarcity of unexploited reservoirs and high upfront capital costs.

 

   

Experienced management team. Our management team has significant expertise owning, developing and operating storage and transportation assets, as well as significant relationships with participants across the natural gas supply chain, and has a proven track record of successfully developing midstream assets in a reliable and cost-effective manner.

 

Inergy, L.P.

 

NRGY and its predecessor have been active participants in the energy industry since the mid-1990s. NRGY has a long history of successfully expanding its energy businesses through complimentary acquisitions and, to a lesser extent, internal growth projects. Since NRGY’s initial public offering in 2001, NRGY has grown its asset base from approximately $150 million to over $3.3 billion and increased the annualized distribution on its limited partner units by over 100%, from $1.20 per unit (adjusted for unit splits) as of NRGY’s initial public offering to $2.82 per unit for the distribution paid on August 12, 2011.

 

 

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Index to Financial Statements

We believe NRGY’s significant presence in the energy sector, its successful track record of growth and its significant investment in, and sponsorship and support of, our business will enhance our ability to increase cash distributions. Through our relationship with NRGY, we will have access to a significant pool of management talent and strong commercial relationships throughout the energy industry. While NRGY is not obligated to promote and support the successful execution of our growth plan and strategy, upon completion of this offering, NRGY’s continued significant economic stake in us may, however, provide NRGY with a strong incentive to do so.

 

Risk Factors

 

An investment in our common units involves risks associated with our business, our regulatory and legal matters, our limited partnership structure and the tax characteristics of our common units. You should carefully consider the risks described in “Risk Factors” beginning on page 18 of this prospectus and the other information in this prospectus before deciding whether to invest in our common units.

 

Risks Inherent in Our Business

 

   

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 the initial quarterly distribution to our common unitholders.

 

   

The assumptions underlying our estimate of cash available for distribution included in “Cash Distribution Policy and Restrictions on Distributions” are inherently uncertain and subject to significant business, economic, financial, regulatory and competitive risks and uncertainties that could cause cash available for distribution to differ materially from our estimates.

 

   

On a pro forma basis, we would have had insufficient cash available for distribution to pay the full initial quarterly distribution on all common units for the twelve months ended September 30, 2010 and June 30, 2011.

 

   

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

 

   

Our natural gas storage and transportation services are subject to extensive regulation by federal, state and local regulatory authorities; regulatory measures adopted by such authorities could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions.

 

   

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

 

   

We depend on third-party pipelines connected to our natural gas 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.

 

   

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

 

   

Increased competition from other companies that provide storage or transportation services, or services that can substitute for storage or transportation services, could have a negative impact on the demand for our services, which could adversely affect our financial results.

 

Risks Inherent in an Investment in Us

 

   

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

 

 

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Index to Financial Statements
   

Our partnership agreement limits the liability of and reduces fiduciary duties owed by our general partner and also restricts the remedies available to our common unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty.

 

   

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

 

   

We will not have any subordinated units outstanding, and NRGY is entitled to receive 50% of all cash that we distribute in excess of the initial quarterly distribution of $         per common unit. As a result, common units will bear any and all shortfalls in the amount of cash needed to pay the initial quarterly distribution and will not be entitled to arrearages.

 

   

Common unitholders will experience immediate and substantial dilution in net tangible book value per common unit of $         per common unit.

 

Tax Risks to Common Unitholders

 

   

Our tax treatment depends on our status as a partnership for U.S. federal income tax purposes. If the IRS were to treat us as a corporation for federal income tax purposes, then our cash available for distribution to you would be substantially reduced.

 

   

The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

 

   

If we were subjected to a material amount of additional entity-level taxation by individual states, then our cash available for distribution to you would be substantially reduced.

 

   

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

 

Our Management

 

We are managed and operated by the board of directors and executive officers of our general partner, NRGM GP, LLC, a wholly owned subsidiary of NRGY. Following this offering, NRGY will own, directly or indirectly, approximately         % of our outstanding common units and all of our incentive distribution rights, or IDRs. As a result of owning our general partner, the board of directors of NRGY’s general partner will have the right to appoint all members of the board of directors of our general partner, 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, in connection with this offering, NRGY and Inergy Holdings GP, LLC, or Holdings GP, the indirect owner of NRGY’s general partner, expect to enter into an agreement under which Holdings GP will be required to purchase our general partner in the event that (i) a change of control of NRGY occurs at a time when NRGY is entitled to receive less than 50% of all cash distributed with respect to our limited partner interests and incentive distribution rights or (ii) through dilution or a distribution to the NRGY common unitholders of NRGY’s interests in us, NRGY is entitled to receive less than 25% of all cash distributed with respect to our limited partner interests and incentive distribution rights. Please read “Security Ownership of Certain Beneficial Owners and Management.”

 

Under the listing requirements of the New York Stock Exchange, or NYSE, the board of directors of our general partner will be required to have at least three independent directors meeting the NYSE’s independence standards. At least one of our independent directors will be appointed prior to the date our common units are listed for trading on the NYSE. NRGY will appoint our second independent director within three months of the date our common units begin trading on the NYSE and will appoint our third independent director within one year from such date.

 

 

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Index to Financial Statements

In connection with the closing of this offering, we will enter into an omnibus agreement with NRGY and certain of its affiliates, pursuant to which we will agree upon certain aspects of our relationship with them, including the provision by NRGY to us of certain administrative services and employees, our agreement to reimburse NRGY for the cost of such services and employees, certain indemnification obligations, the use by us of the name “Inergy” and related marks, NRGY’s right to review and first option with respect to business opportunities, and other matters. Neither our general partner nor NRGY will 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 will reimburse our general partner and its affiliates, including NRGY, for all expenses they incur and payments they make on our behalf pursuant to the omnibus agreement. 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. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us. Please read “Certain Relationships and Related Party Transactions.”

 

Summary of Conflicts of Interest and Fiduciary Duties

 

Our general partner has a legal duty to manage our partnership in a manner beneficial to us and the holders of our common units. This legal duty commonly is referred to as a “fiduciary duty.” However, the officers and directors of our general partner also have fiduciary duties to manage our general partner in a manner beneficial to its owner, NRGY. Additionally, each of our executive officers and one or more of our directors may also be officers or directors of NRGY. As a result, conflicts of interest may arise in the future between us and our common unitholders, on the one hand, and NRGY and our general partner, on the other hand.

 

Delaware law provides that Delaware limited partnerships may, in their partnership agreements, restrict, eliminate or expand the fiduciary duties owed by the general partner to limited partners and the partnership. Our partnership agreement limits the liability of, and reduces the fiduciary duties owed by, our general partner to our common unitholders. Our partnership agreement also restricts the remedies available to our common unitholders for actions that might otherwise constitute a breach of fiduciary duty by our general partner or its officers and directors. By purchasing a common unit, the purchaser agrees to be bound by the terms of our partnership agreement, and each common unitholder is treated as having consented to various actions and potential conflicts of interest contemplated in the partnership agreement that might otherwise be considered a breach of fiduciary or other duties under applicable state law.

 

Principal Executive Offices

 

Our principal executive offices are located at Two Brush Creek Boulevard, Suite 200, Kansas City, Missouri 64112, and our telephone number is (816) 842-8181. Our website address will be                     . We intend to make our periodic reports and other information filed with or furnished to the Securities and Exchange Commission, or SEC, available, free of charge, through our website, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus.

 

Formation Transactions and Partnership Structure

 

We were formed by NRGY as a Delaware limited liability company in September 2004 for the purpose of holding certain of NRGY’s midstream investments. Prior to the closing of this offering, Inergy Midstream, LLC will convert to a Delaware limited partnership and change its name to Inergy Midstream, L.P.

 

 

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Index to Financial Statements

In connection with this offering, the following will occur:

 

   

NRGY will restructure its midstream businesses, such that we will (i) transfer 100% of our ownership interests in Tres Palacios Gas Storage LLC and US Salt to a newly formed subsidiary, NRGY MS, LLC, and then (ii) transfer 100% of our ownership interests in NRGY MS, LLC to NRGY;

 

   

all indebtedness that we owe to a subsidiary of NRGY, which was approximately $121.5 million as of August 31, 2011, will be extinguished and treated as a capital contribution by NRGY to us;

 

   

we will assume approximately $         million of indebtedness from NRGY under a $         million revolving credit facility that will be assigned to us (which we refer to in this prospectus as our revolving credit facility) of which we will repay $         million using net proceeds of this offering;

 

   

we expect to re-borrow $80 million under our revolving credit facility to fund a cash distribution to NRGY for reimbursement of capital expenditures associated with our assets;

 

   

we will issue to NRGY an aggregate of          common units, assuming that the underwriters do not exercise their option to purchase          additional common units and that we issue those common units to NRGY;

 

   

we will issue to NRGY the incentive distribution rights, which entitle the holder to 50.0% of the cash we distribute in excess of our initial quarterly distribution of $         per common unit per quarter, as described under “Cash Distribution Policy and Restrictions on Distributions”;

 

   

NRGM GP, LLC will maintain its non-economic general partner interest in us;

 

   

we will issue          common units to the public (         common units if the underwriters exercise their option in full); and

 

   

we will enter into the omnibus agreement with NRGY and certain of its affiliates. Please read “Certain Relationships and Related Party Transactions—Agreements with Affiliates in Connection with the Transactions—Omnibus Agreement.”

 

 

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Index to Financial Statements

Ownership of Inergy Midstream, L.P.

 

The following diagram illustrates our simplified organizational structure and ownership based on total common units outstanding after giving effect to the offering and the related formation transactions and assumes that the underwriters’ option to purchase additional common units is not exercised.

 

Public Common Units

      

Common Units owned by NRGY

      

Non-Economic General Partner Interest

    
  

 

 

 

Total

     100.0
  

 

 

 

 

LOGO

 

(1)   Owned by management and other investors.

 

 

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Index to Financial Statements

The Offering

 

Common units offered to the public

          common units.

 

           common units if the underwriters exercise their option to purchase an additional        common units (the “option units”) in full.

 

Common units outstanding after this offering

                     common units, regardless of whether or not the underwriters exercise their option to purchase up to an additional                      common units. Of this amount,                      common units will be issued to NRGY at the closing of this offering and, assuming the underwriters do not exercise their option to purchase up to an additional          option units, all                      option units will be issued to NRGY 30 days following this offering upon the expiration of the underwriters’ option exercise period. However, if the underwriters do exercise their option to purchase any portion of the option units, we will (i) issue to the public the number of option units purchased by the underwriters pursuant to such exercise and (ii) issue to NRGY, upon the expiration of the option exercise period, all remaining option units that had not previously been issued to the public. Any such option units issued to NRGY will be issued for no additional consideration. Accordingly, the exercise of the underwriters’ option will not affect the total number of common units outstanding. In addition, these unit numbers exclude common units reserved for issuance under our long-term incentive plan.

 

Use of proceeds

We intend to use the estimated net proceeds of approximately $        million from this offering, after deducting the estimated underwriting discounts and commissions, the structuring fee and offering expenses payable by us, to repay approximately $        million of indebtedness outstanding under our revolving credit facility. Any remaining net proceeds will be used for general partnership purposes. We expect to re-borrow $80 million under our revolving credit facility to fund a cash distribution to NRGY for reimbursement of capital expenditures associated with our assets.

 

  If the underwriters exercise their option to purchase        additional common units in full, the additional net proceeds would be approximately $        million. The net proceeds from any exercise of such option will be distributed to NRGY. Please read “Use of Proceeds.”

 

Affiliates of certain of the underwriters are lenders under our revolving credit facility and, accordingly, will receive a substantial portion of the proceeds from this offering. Please read “Underwriting.”

 

Cash distributions

Upon completion of this offering, our general partner will establish an initial quarterly distribution of $        per common unit ($        per common unit on an annualized basis). Before we pay any

 

 

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Index to Financial Statements
 

distributions on our common units, we will establish reserves and pay fees and expenses, including reimbursements to our general partner and its affiliates, including NRGY, 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. We estimate reimbursements of these expenses to be approximately $5 million for the twelve months ending December 31, 2012. However, 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. We refer to the cash available after establishment of reserves and payment of fees and expenses as “available cash,” and it is defined in our partnership agreement included in this prospectus as Appendix A. Our ability to pay the initial quarterly distribution is subject to various restrictions and other factors described in more detail under the caption “Cash Distribution Policy and Restrictions on Distributions.”

 

  For the first quarter that we are publicly traded, we will pay investors in this offering a prorated distribution covering the period from the completion of this offering through December 31, 2011, based on the actual length of that period.

 

  Our partnership agreement requires us to distribute 100% of our available cash each quarter to the holders of our common units, until each common unit has received the initial quarterly distribution of $        .

 

  Our general partner will not receive cash distributions on its non-economic general partner interest. Common units will not accrue arrearages. Therefore, to the extent we do not pay the initial quarterly distribution on our common units, our common unitholders will not be entitled to receive such payments in the future.

 

  If cash distributions to our common unitholders exceed our initial quarterly distribution of $        per common unit in any quarter, NRGY will receive 50% of the cash we distribute in excess of that amount in respect of its incentive distribution rights.

 

  Our common unitholders and NRGY, in respect of its incentive distribution rights, will receive distributions according to the following percentage allocations based on a specified distribution level:

 

     Marginal Percentage
Interest in Distributions
 

Total Quarterly

Distribution Amount

   Common
Unitholders
    IDR
Holder
 

up to $

     100.0     0.0

above $

     50.0     50.0

 

 

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Index to Financial Statements
  We refer to the additional distributions to NRGY of 50% of the cash we distribute in excess of $        as “incentive distributions.” Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions—Distributions of Available Cash—Incentive Distribution Rights.”

 

  We believe, based on our financial forecast and related assumptions included in “Cash Distribution Policy and Restrictions on Distributions,” that we will have sufficient available cash to pay the initial quarterly distribution of $         on all of our common units for each quarter in the twelve months ending December 31, 2012. However, we do not have a legal obligation to pay quarterly distributions at our initial quarterly distribution rate or at any other rate except as provided in our partnership agreement. There is no guarantee that we will distribute quarterly cash distributions to our common unitholders in any quarter. We estimate that our pro forma cash available for distribution for the fiscal year ended September 30, 2010 and the nine months ended June 30, 2011 would have been sufficient to pay only             % and             %, respectively, of the full initial quarterly distribution on all of our common units for those periods. Please read “Cash Distribution Policy and Restrictions on Distributions.”

 

NRGY’s right to reset the initial quarterly distribution

NRGY, as the initial holder of all of our incentive distribution rights, has the right to reset, at a higher level, the initial quarterly distribution based on our cash distributions at the time of the exercise of the reset election. If NRGY transfers all or a portion of our incentive distribution rights in the future, then the holder or holders of a majority of our incentive distribution rights will be entitled to exercise this right. The following assumes that NRGY holds all of the incentive distribution rights at the time that a reset election is made. Following a reset election, the initial quarterly distribution will be adjusted to equal the reset initial quarterly distribution.

 

  If NRGY elects to reset the initial quarterly distribution, it will be entitled to receive newly issued common units. The number of common units to be issued to NRGY will equal the number of common units that would have entitled the holder to a quarterly cash distribution in the prior quarter equal to the distribution to NRGY on its incentive distribution rights in such prior quarter. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions—NRGY’s Right to Reset Incentive Distribution Level.”

 

Issuance of additional units

Our partnership agreement authorizes us to issue an unlimited number of additional units without the approval of our common unitholders. Please read “Units Eligible for Future Sale” and “The Partnership Agreement—Issuance of Additional Interests.”

 

Limited voting rights

Our general partner will manage and operate us. Unlike the holders of common stock in a corporation, our common unitholders will have

 

 

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Index to Financial Statements
 

only limited voting rights on matters affecting our business. Our common unitholders will have no right to elect our general partner or its directors on an annual or other continuing basis. Our general partner may not be removed except by a vote of the holders of at least 66 2/3% of the outstanding common units, including any common units owned by our general partner and its affiliates, voting together as a single class. Upon completion of this offering, NRGY will own an aggregate of         % of our outstanding common units (or         % of our outstanding common units, if the underwriters exercise their option to purchase additional common units in full). This will give NRGY the ability to prevent the removal of our general partner. Please read “The Partnership Agreement—Limited Voting Rights.”

 

Limited call right

If at any time our general partner and its affiliates own more than         % of the outstanding common units, our general partner has the right, but not the obligation, to purchase all of the remaining common units at a price equal to the greater of (1) the highest price paid by our general partner or any of its affiliates for any limited partner interests of the class purchased within the 90 days preceding the date on which our general partner first mails notice of its election to purchase those limited partner interests and (2) the average of the daily closing prices of the partnership securities of such class over the 20 consecutive trading days immediately preceding the date three days before the date the notice is mailed. Please read “The Partnership Agreement—Limited Call Right.”

 

Estimated ratio of taxable income to distributions

We estimate that if you own the common units you purchase in this offering through the record date for distributions for the period ending December 31, 2014, you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be         % or less of the cash distributed to you with respect to that period. For example, if you receive an annual distribution of $         per unit, we estimate that your average allocable federal taxable income per year will be no more than approximately $         per unit. Thereafter, the ratio of allocable taxable income to cash distributions to you could substantially increase. Please read “Material U.S. Federal Income Tax Consequences—Tax Consequences of Unit Ownership.”

 

Material U.S. federal income tax consequences

For a discussion of the material U.S. federal income tax consequences that may be relevant to prospective common unitholders, you should read “Material U.S. Federal Income Tax Consequences.” All statements of legal conclusions contained in “Material U.S. Federal Income Tax Consequences,” unless otherwise noted, are the opinion of Vinson & Elkins L.L.P. with respect to the matters discussed therein.

 

Exchange listing

We intend to apply to list our common units on the NYSE under the symbol “NRGM.”

 

 

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Index to Financial Statements

Summary Historical and Pro Forma Financial and Operating Data

 

The following table presents our summary historical financial and operating data and summary pro forma financial data as of the dates and for the periods indicated. The summary historical financial data presented as of September 30, 2008 and June 30, 2010 are derived from our unaudited historical consolidated financial statements, which are not included in this prospectus. The summary historical financial data presented as of September 30, 2009 and 2010 and for the fiscal years ended September 30, 2008, 2009 and 2010 are derived from our audited historical consolidated financial statements that are included elsewhere in this prospectus. The summary historical financial data presented as of June 30, 2011 and for the nine months ended June 30, 2010 and 2011 are derived from our unaudited historical consolidated financial statements that are included elsewhere in this prospectus. The summary historical financial and operating data and summary pro forma financial data as of the dates and for the periods indicated below are derived from the financial statements of Inergy Midstream, LLC and its subsidiaries, excluding Tres Palacios Gas Storage LLC and US Salt, which will be transferred to NRGY in connection with the closing of this offering and are not reflected in the presentation of our financial statements.

 

The summary pro forma financial data presented for the fiscal year ended September 30, 2010 and as of and for the nine months ended June 30, 2011 are derived from our unaudited pro forma condensed consolidated financial statements included elsewhere in this prospectus. Our unaudited pro forma condensed consolidated financial statements give pro forma effect to:

 

   

the change in our organizational structure from a limited liability company to a limited partnership;

 

   

the extinguishment of all indebtedness that we owe to a subsidiary of NRGY, which will be treated as a capital contribution by NRGY to us and which was approximately $121.5 million as of August 31, 2011;

 

   

our assumption from NRGY of $         million of indebtedness under a $         million revolving credit facility of which we will repay $         million from the net proceeds of this offering;

 

   

our re-borrowing of $80 million under our revolving credit facility to fund a distribution to NRGY for reimbursement of capital expenditures associated with our assets;

 

   

the issuance by us to NRGY of              common units and all of our incentive distribution rights;

 

   

the issuance by us to our general partner of a non-economic general partner interest in us; and

 

   

the issuance by us to the public of              common units and the use of the net proceeds from this offering as described under “Use of Proceeds.”

 

The unaudited pro forma balance sheet data assume the events listed above occurred as of June 30, 2011. The unaudited pro forma statement of operations data for the fiscal year ended September 30, 2010 assume the events listed above occurred as of October 1, 2009 and for the nine months ended June 30, 2011 assume the events listed above occurred as of October 1, 2010. We have not given pro forma effect to incremental external administrative expenses of approximately $3.0 million that we expect to incur annually as a result of being a publicly traded partnership. These incremental expenses include, costs associated with SEC reporting requirements, including annual and quarterly reports to common unitholders, tax return and Schedule K-1 preparation and distribution, independent auditor fees, investor relations activities, Sarbanes-Oxley Act compliance, NYSE listing, registrar and transfer agent fees, director and officer liability insurance costs, and director compensation. In future periods, the board of directors of our general partner may grant awards to our key employees and our outside directors pursuant to our long-term incentive plan; however, the board has not yet made any determination as to the number of awards or when the awards would be granted. Such incremental administrative expenses are not reflected in our historical and pro forma financial statements.

 

For a detailed discussion of the summary historical financial information contained in the following table, including factors impacting the comparability of information in the table, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” The following table should also be read in

 

 

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conjunction with “Use of Proceeds” and our audited historical consolidated financial statements and our unaudited pro forma condensed consolidated financial statements included elsewhere in this prospectus. Among other things, the historical and unaudited pro forma condensed consolidated financial statements include more detailed information regarding the basis of presentation for the information in the following table.

 

The following table presents a non-GAAP financial measure, Adjusted EBITDA, which we use in our business as it is an important supplemental measure of our performance and liquidity. Adjusted EBITDA is not calculated or presented in accordance with generally accepted accounting principles, or GAAP. We explain this measure under “—Non-GAAP Financial Measures” and reconcile it to its most directly comparable financial measures calculated and presented in accordance with GAAP.

 

                                   Pro Forma  
     Year Ended September 30,     Nine Months Ended
June 30,
    Year
Ended
September  30,
     Nine Months
Ended
June 30,
 
     2008     2009     2010     2010     2011     2010      2011  
     ($ in millions)  

Statement of operations data:

               

Revenue

   $ 82.7      $ 87.5      $ 94.7      $ 69.1      $ 80.3      $ 94.7       $ 80.3   

Cost of services sold (excluding depreciation and amortization as shown below):

     12.4        17.8        12.0        9.7        11.9        12.0         11.9   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

    

 

 

 

Gross profit

     70.3        69.7        82.7        59.4        68.4        82.7         68.4   

Expenses:

               

Operating and administrative

     11.7        10.8        15.0        11.3        10.1        15.0         10.1   

Depreciation and amortization

     24.5        29.2        36.2        26.7        27.3        36.2         27.3   

(Gain) loss on disposal of assets

     (1.9            0.9        0.9               0.9           
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

    

 

 

 

Operating income

     36.0        29.7        30.6        20.5        31.0        30.6         31.0   

Interest expense, net

                                        1.3         1.0   

Other income

     0.8               0.8                      0.8           
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

    

 

 

 

Net income

     36.8        29.7        31.4        20.5        31.0        30.1         30.0   

Net income attributable to non-controlling partners

     1.4        1.4        0.8        0.8               0.8           
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

    

 

 

 

Net income attributable to member/partners

   $ 35.4      $ 28.3      $ 30.6      $ 19.7      $ 31.0      $ 29.3       $ 30.0   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

    

 

 

 

Balance sheet data (at end of period):

               

Total assets

   $ 480.8      $ 561.0      $ 559.5      $ 560.5      $ 607.3         $ 607.3   

Total debt

     10.9        8.3               6.3                  80.0   

Member’s/partners’ capital

     384.8        414.3        444.8        434.0        475.9           519.6   

Other financial data:

               

Adjusted EBITDA

   $ 57.7      $ 57.7      $ 70.4      $ 49.2      $ 59.2      $ 70.4       $ 59.2   

Maintenance capital expenditures

     0.2               0.3        0.3        2.5        

Net cash provided by operating activities

     62.9        59.5        83.5        56.8        65.2        

Net cash used in investing activities

     (108.9     (74.1     (49.8     (38.4     (64.1     

Net cash provided by (used in) financing activities

     48.9        15.3        (37.3     (20.0     8.3        

Operating data:

               

Natural gas storage capacity (Bcf)

     32.5        32.5        39.5        39.5        39.5        

% of revenue generated from firm contracts

     98     96     98     98     96     

 

 

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Non-GAAP Financial Measures

 

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 expenses, transaction costs and interest of non-controlling partners. Transaction costs are third-party professional fees and other costs that are incurred in conjunction with closing a transaction.

 

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.

 

We believe that the presentation of Adjusted EBITDA will provide useful information to investors in assessing our financial condition and results of operations. The GAAP measures most directly comparable to Adjusted EBITDA are net income and net cash provided by operating activities. Our non-GAAP financial measure of Adjusted EBITDA should not be considered as an alternative to GAAP net income or net cash provided by operating activities. Adjusted EBITDA has important limitations as an analytical tool because it excludes some but not all items that affect net income. You should not consider Adjusted EBITDA in isolation or as a substitute for analysis of our results as reported under GAAP. Because Adjusted EBITDA may be defined differently by other companies in our industry, our definition of Adjusted EBITDA may not be comparable to similarly titled measures of other companies, thereby diminishing its utility.

 

The following table presents a reconciliation of EBITDA and Adjusted EBITDA to their most directly comparable GAAP financial measures, on a historical basis and pro forma basis, as applicable, for each of the periods indicated.

 

                                    Pro Forma  
     Year Ended
September 30,
    Nine Months
Ended June 30,
     Year Ended
September 30,
    Nine Months
Ended
June 30,
 
     2008     2009     2010     2010     2011      2010     2011  
     ($ in millions)  

Reconciliation of net income to EBITDA and Adjusted EBITDA:

               

Net income

   $ 36.8      $ 29.7      $ 31.4      $ 20.5      $ 31.0       $ 30.1      $ 30.0   

Depreciation and amortization

     24.5        29.2        36.2        26.7        27.3         36.2        27.3   

Interest expense, net

                                         1.3        1.0   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

    

 

 

   

 

 

 

EBITDA

   $ 61.3      $ 58.9      $ 67.6      $ 47.2      $ 58.3       $ 67.6      $ 58.3   

Long-term incentive and equity compensation expense

     0.5        0.7        2.7        2.0        0.9         2.7        0.9   

(Gain) loss on disposal of assets

     (1.9            0.9        0.9                0.9          

Transaction costs

                   0.2        0.1                0.2          

Net income attributable to non-controlling partners

     (1.4     (1.4     (0.8     (0.8             (0.8       

Interest of non-controlling partners in consolidated ITDA(a)

     (0.8     (0.5     (0.2     (0.2             (0.2       
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

    

 

 

   

 

 

 

Adjusted EBITDA

   $ 57.7      $ 57.7      $ 70.4      $ 49.2      $ 59.2       $ 70.4      $ 59.2   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

    

 

 

   

 

 

 

 

 

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     Year Ended
September 30,
    Nine Months
Ended June 30,
 
     2008     2009     2010     2010     2011  
     ($ in millions)  

Reconciliation of net cash provided by operating activities to EBITDA and Adjusted EBITDA:

          

Net cash provided by operating activities

   $ 62.9      $ 59.5      $ 83.5      $ 56.8      $ 65.2   

Net changes in working capital balances

     (3.5     (0.6     (15.0     (8.7     (6.9

Gain (loss) on disposal of assets

     1.9               (0.9     (0.9       
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

EBITDA

   $ 61.3      $ 58.9      $ 67.6      $ 47.2      $ 58.3   

Long-term incentive and equity compensation expense

     0.5        0.7        2.7        2.0        0.9   

(Gain) loss on disposal of assets

     (1.9            0.9        0.9          

Transaction costs

                   0.2        0.1          

Interest of non-controlling partners in consolidated EBITDA

     (2.2     (1.9     (1.0     (1.0       
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Adjusted EBITDA

   $ 57.7      $ 57.7      $ 70.4      $ 49.2      $ 59.2   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

(a)   Interest, tax, depreciation and amortization expense attributable to non-controlling partners.

 

 

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RISK FACTORS

 

Limited partner interests are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. You should carefully consider the following risk factors together with all of the other information included in this prospectus in evaluating an investment in our common units.

 

If any of the following risks were to occur, our business, financial condition, results of operations and cash available for distribution could be materially adversely affected. In that case, we might not be able to make distributions on our common units, the trading price of our common units could decline and you could lose all or part of your investment.

 

Risks Inherent in Our Business

 

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 the initial quarterly distribution to our common unitholders.

 

We may not have sufficient cash each quarter to pay the full amount of our initial quarterly distribution of $         per unit, or $         per unit per year, which will require us to have available cash of approximately $         million per quarter, or $         million per year, based on the number of common units to be outstanding after the completion of this offering. 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 NRGY, 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. We estimate reimbursements of these expenses to be approximately $5 million for the twelve months ending December 31, 2012. However, 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. Please read “Certain Relationships and Related Party Transactions—Agreements with Affiliates in Connection with the Transactions—Omnibus Agreement.”

 

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, on a seasonal and long-term basis, governmental regulation of our rates and services and our ability to obtain permits for internal growth projects;

 

   

damage to our or third-party pipelines, facilities, related equipment and surrounding properties caused by floods, fires, severe weather, explosions and other natural disasters and acts of terrorism or inadvertent damage to pipelines from construction, farm and utility equipment;

 

   

prevailing economic and market conditions;

 

   

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

 

   

leaks or accidental releases of products or other materials into the environment, whether as a result of human error or otherwise;

 

   

difficulties in collecting our receivables because of our customers’ credit or financial problems;

 

   

changes in tax laws; and

 

   

force majeure events.

 

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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.

 

For a description of additional restrictions and factors that may affect our ability to pay cash distributions, please read “Cash Distribution Policy and Restrictions on Distributions.”

 

The assumptions underlying our estimate of cash available for distribution included in “Cash Distribution Policy and Restrictions on Distributions” are inherently uncertain and subject to significant business, economic, financial, regulatory and competitive risks and uncertainties that could cause cash available for distribution to differ materially from our estimates.

 

The estimate of cash available for distribution set forth in “Cash Distribution Policy and Restrictions on Distributions” is based on assumptions that are inherently uncertain and are subject to significant business, economic, financial, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those estimated. If we do not achieve the estimated results, we may not be able to pay the initial quarterly distribution or any amount on our common units, in which event the market price of our common units may decline materially. Please read “Cash Distribution Policy and Restrictions on Distributions—Assumptions and Considerations.”

 

On a pro forma basis, we would have had insufficient cash available for distribution to pay the full initial quarterly distribution on all common units for the fiscal year ended September 30, 2010 and the twelve months ended June 30, 2011.

 

To pay our cash distributions at our initial quarterly distribution rate of $         per common unit per quarter, or $         per common unit per year, we will require available cash of approximately $         million per quarter, or $         million per year, based on the number of common units outstanding after this offering. Our pro forma cash available for distribution generated during the fiscal year ended September 30, 2010 and the twelve months ended June 30, 2011 of $65.8 million and $73.4 million, respectively, would have been insufficient to allow us to pay the full initial quarterly distribution on all of the common units. The shortfall in available cash for distribution for the fiscal year ended September 30, 2010 and the twelve months ended June 30, 2011 would have resulted in distributions with respect to our common units representing approximately         % and         %, respectively, of our initial quarterly distribution. For a calculation of our ability to make distributions to our common unitholders based on our pro forma results in the fiscal year ended September 30, 2010 and the twelve months ended June 30, 2011, please read “Cash Distribution Policy and Restrictions on Distributions—Unaudited Pro Forma Cash Available for Distribution.”

 

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

 

The principal focus of our strategy is to continue to grow the cash distributions on our common units by growing our business. Our ability to grow depends on our ability to complete internal growth projects and make acquisitions from NRGY and third parties that result in an increase in cash generated from operations on a per unit basis (i.e., are accretive). However, NRGY is entitled under the omnibus agreement to review and has the first option on any third-party acquisition opportunities, is under no obligation to make acquisition opportunities available to us, is not restricted from competing with us and 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 internal growth projects or acquisitions for any of the following reasons:

 

   

we are unable 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 are unable to raise financing for such projects or acquisitions on economically acceptable terms;

 

   

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

 

   

we are unable to obtain governmental approvals or other rights, licenses or consents needed to complete such projects or acquisitions.

 

Our natural gas storage and transportation services are subject to extensive regulation by federal, state and local regulatory authorities; regulatory measures adopted by such authorities could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions.

 

Our natural gas storage and transportation services are subject to extensive regulation by federal, state and local regulatory authorities. 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 of 1938, or NGA. Federal regulation under the NGA 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. The rates and terms and conditions for interstate services provided by the Steuben facility are found in the FERC-approved tariff of our wholly owned subsidiary Steuben Gas Storage Company, or Steuben Gas. The rates and terms and conditions for interstate services provided by Stagecoach are found in the FERC-approved tariff of our wholly owned subsidiary Central New York And Gas Company, L.L.C., or CNYOG. The rates and terms and conditions for interstate services provided by the Thomas Corners and Seneca Lake facilities are found in the FERC-approved tariff of our wholly owned subsidiary Arlington Storage Company, LLC, or ASC.

 

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Pursuant to the NGA, 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 over the Stagecoach north and south lateral pipelines. 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 are likely to be lower than our current market-based rates.

 

Interstate storage services provided at the Steuben facility are currently subject to cost-of-service regulation. FERC’s cost-of-service regulations limit the maximum rates for storage services to the cost of providing service plus a reasonable return. In each rate case, the FERC must approve service costs, the allocation of costs, the allowed rate of return on capital investment, rate design, and other rate factors. A negative determination on any of these rate factors could adversely affect our business, financial condition, results of operations and ability to make distributions. Although we intend to request FERC authorization to allow Steuben to charge market-based storage rates, we cannot guarantee that the FERC will grant that authorization. If the FERC does not authorize us to charge market-based rates at the Steuben facility, we will continue to charge cost-of-service 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 NGA, 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 storage contracts.

 

Our primary exposure to market risk occurs at the time our existing storage contracts expire and are subject to renegotiation and renewal. As of September 30, 2011, the weighted average remaining tenor of our existing portfolio of firm storage contracts is approximately 3.6 years. For the fiscal year ended September 30, 2010, Consolidated Edison of New York, Inc., or ConEdison, accounted for approximately 28% of our total revenue. The extension or replacement of existing contracts, including our contracts with ConEdison, depends on a number of factors beyond our control, including:

 

   

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

 

   

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

 

   

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 natural gas 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. Our Stagecoach facility depends on Tennessee Gas Pipeline Company’s, or TGP’s, 300 Line and the Millennium Pipeline, currently the only pipelines to which it is directly interconnected; the Steuben and Seneca Lake facilities depend on Dominion Transmission Inc., or Dominion; and the Thomas Corners facility depends on TGP’s 400 Line and the Millennium Pipeline. 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 natural gas 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 constructing new midstream assets subjects us to risks.

 

Our growth projects, which are a key part of our growth strategy, include construction of the MARC I pipeline, completion of our North/South expansion project, development of a 2.1 million barrel NGL storage facility located near Watkins Glen, New York and expansion of our Seneca Lake natural gas storage facility by an additional 0.6 Bcf of working gas storage capacity. These projects are expected to be completed throughout 2011 and 2012 at a total expected cost of approximately $380 million, of which approximately $97.7 million has been incurred through June 30, 2011. The development and construction of storage facilities and pipelines 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 internal growth projects must receive certificate authority from FERC prior to construction, such as our MARC I pipeline. 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 certificate authorization will be granted or, if granted, that such authorization will be free of burdensome or expensive conditions.

 

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

 

Even if we complete internal growth projects or acquisitions that we believe will be accretive, such projects or acquisitions may nevertheless reduce our cash available for distribution on a per common unit basis 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 internal 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 internal growth project was completed;

 

   

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

 

   

the failure to successfully integrate internal 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.

 

If we complete future internal 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 internal growth projects or acquisitions we ultimately complete are not accretive to our cash available for distribution per common unit, our ability to make distributions may be reduced.

 

We will be required to make capital expenditures to expand our asset base. If we are unable to obtain needed capital or financing on satisfactory terms, 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.

 

While we have historically received funding from our affiliates, we do not have any commitment with our general partner or other affiliates, including NRGY, to fund our cash flow deficits or provide other direct or indirect financial assistance to us following the closing of this offering. In addition, the indentures governing NRGY’s outstanding senior notes would substantially restrict the types, amounts and terms of any such assistance that NRGY might desire to provide us.

 

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Increased competition from other companies that provide storage or transportation services, or services that can substitute for storage or transportation services, 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, local distribution companies, or 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. Our principal natural gas storage competitors include, among others, Dominion Resources, Inc., NiSource Inc. and El Paso Corporation. These major pipeline natural gas transmission companies have existing storage facilities connected to their systems that compete with certain of our facilities. 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 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. 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 liquefied natural gas, or LNG, facilities. In addition, natural gas as a fuel 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.

 

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, 2010, ConEdison accounted for approximately 28% of our total revenue. The loss, nonpayment, nonperformance or impaired creditworthiness of one of these customers could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions.

 

Any significant and prolonged change in or stabilization of natural gas prices could have a negative impact on our natural gas storage business.

 

Historically, natural gas prices have been seasonal and volatile, which has enhanced demand for our storage services. The natural gas storage business has benefited from significant price fluctuations resulting from seasonal price sensitivity, which impacts the level of demand for our services and the rates we are able to charge

 

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for such services. On a system-wide basis, natural gas is typically injected into storage between April and October when natural gas prices are generally lower and withdrawn during the winter months of November through March when natural gas prices are typically higher. However, the market for natural gas may not continue to experience volatility and seasonal price sensitivity in the future at the levels previously seen. 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, 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 operational risks, some of which may not be fully covered by insurance. If a significant accident or event occurs for which we are not fully insured, our operations and financial results could be adversely affected.

 

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

 

   

reduction of our available storage capacity at our salt caverns over time due to (i) unexpected increases in the temperature of our caverns, which reduces capacity as a result of the expansion of the stored natural gas, (ii) the long-term effect of pressure differentials between the caverns and the surrounding salt formations (known as “salt creep”) or (iii) problems with the structural integrity of our salt caverns;

 

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Index to Financial Statements
   

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 (including from construction, farm and utility equipment), 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 or our water treatment facilities; 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. 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.

 

In addition, we share insurance coverage with NRGY, for which we will reimburse NRGY pursuant to the terms of the omnibus agreement. To the extent NRGY 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.

 

In connection with this offering, we expect to assume from NRGY a $         million revolving credit facility, with an expected maturity date five years from the closing of this offering. We expect the revolving credit facility to be available to fund working capital and our internal growth projects, make acquisitions and for general partnership purposes.

 

We expect that this revolving credit facility will restrict 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.

 

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Furthermore, our revolving credit facility will contain covenants requiring us to maintain certain financial ratios. We expect that borrowings under our revolving credit facility will be secured by liens on substantially all of our assets and guaranteed by our existing and future subsidiaries.

 

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.

 

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.

 

For more information regarding our debt agreements, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Sources of Capital.”

 

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

 

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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.

 

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 the natural gas or NGLs we store as part of our midstream services. 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 or NGLs we store and transport as part of our business. For instance, the U.S. Environmental Protection Agency, or 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 only recently released a report on August 11, 2011, recommending the implementation of a variety of measures to reduce the environmental impacts from shale-gas production. Similarly, the U.S. 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.

 

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

 

In December 2009, the EPA determined that emissions of carbon dioxide, methane and other greenhouse gases, or 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 in the United States on an annual basis, beginning in 2011 for 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

 

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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. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations.

 

The credit and risk profile of our general partner and its owner, NRGY, 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 NRGY may be factors considered in credit evaluations of us. This is because our general partner, which is owned by NRGY, controls our business activities, including our cash distribution policy and growth strategy. Any adverse change in the financial condition of NRGY, including the degree of its financial leverage and its dependence on cash flow from us to service its indebtedness, 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 NRGY, as credit rating agencies such as Standard & Poor’s Ratings Services and Moody’s Investors Service may consider the leverage and credit profile of NRGY 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.

 

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 exclusively on revenues generated from storage and transportation assets that we own, which are exclusively located 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.

 

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If we fail to develop or 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.

 

Prior to this offering, we have not been required to file reports with the SEC. Upon the completion of this offering, we will become subject to the public reporting requirements of the Securities Exchange Act of 1934, as amended, or the Exchange Act. We prepare our consolidated financial statements in accordance with GAAP, but our internal accounting controls may not currently meet all standards applicable to companies with publicly traded securities. 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 develop and 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 will require 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. We must comply with Section 404 for our fiscal year ending September 30, 2013. 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.

 

Terrorist attacks aimed at our facilities or surrounding areas could adversely affect our business.

 

The U.S. government has issued warnings that energy assets, specifically the nation’s pipeline and terminal infrastructure, may be the future targets of terrorist organizations. Any terrorist attack at our facilities, those of our customers and, in some cases, those of other pipelines, refineries or terminals could materially and adversely affect our business, financial condition, results of operations or cash flows.

 

Risks Inherent in an Investment in Us

 

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

 

Following this offering, NRGY will own and control our general partner and will appoint all of the directors of our general partner. Although our general partner has a fiduciary duty to manage our partnership in a manner beneficial to us and our common unitholders, the executive officers and directors of our general partner have a fiduciary duty to manage our general partner in a manner beneficial to NRGY. Therefore, conflicts of interest may arise between our general partner and its affiliates, including NRGY, 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. These conflicts include the following situations, among others:

 

   

neither our partnership agreement nor any other agreement requires NRGY to pursue a business strategy that favors us, and directors and officers of NRGY’s general partner have a fiduciary duty to make these decisions in the best interests of the owners of NRGY, which may be contrary to our interests;

 

   

NRGY is entitled under the omnibus agreement to review and has the first option on any third-party acquisition opportunities, is under no obligation to make acquisition opportunities available to us and may compete with us;

 

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certain of our officers may devote the majority of their time to our business, while other officers will have responsibilities for both us and NRGY and will devote less than a majority of their time to our business;

 

   

our general partner and its affiliates are allowed to take into account the interests of parties other than us in resolving conflicts of interest;

 

   

our partnership agreement limits the liability of and reduces fiduciary duties owed by our general partner and also restricts the remedies available to our common unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty;

 

   

except in limited circumstances, our general partner has the power and authority to conduct our business without common unitholder approval

 

   

our general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings, issuances of additional partnership securities and the creation, reduction or increase of reserves, each of which can affect the amount of cash that is distributed to our common unitholders;

 

   

our general partner determines which costs incurred by it and its affiliates are reimbursable by us;

 

   

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

 

   

our general partner may exercise its right to call and purchase all of the common units not owned by it and its affiliates if our general partner and its affiliates own more than                     % of the outstanding common units;

 

   

our general partner controls the enforcement of its and its affiliates’ obligations to us;

 

   

our general partner decides whether to retain separate counsel, accountants or others to perform services for us;

 

   

NRGY may elect to cause us to issue common units to it in connection with a resetting of the initial quarterly distribution related to its incentive distribution rights, 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;

 

   

our general partner determines the amount and timing of any capital expenditure and whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus. Our partnership agreement does not set a limit on the amount of maintenance capital expenditures that our general partner may estimate. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions—Capital Expenditures” for a discussion on when a capital expenditure constitutes a maintenance capital expenditure or an expansion capital expenditure. This determination can affect the amount of cash that is distributed to our common unitholders. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions”;

 

   

our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make incentive distributions;

 

   

our partnership agreement permits us to distribute up to $         million as operating surplus, even if it is generated from non-operating sources such as asset sales, issuances of securities and long-term borrowings that would otherwise be distributed as capital surplus. Please read “Provisions of our Partnership Agreement Relating to Cash Distributions.” This cash may be used to fund distributions on the incentive distribution rights; and

 

   

our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with its affiliates on our behalf.

 

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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 fiduciary 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 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 will be no limitations in our partnership agreement, and we do not expect to have limitations 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.

 

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

 

Our partnership agreement contains provisions that modify and reduce the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law. 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 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 elect to reset the initial quarterly distribution; and

 

   

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. Please read “Conflicts of Interest and Fiduciary Duties—Fiduciary Duties.”

 

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Our partnership agreement limits the liability of and reduces fiduciary duties owed by our general partner and also restricts the remedies available to our common unitholders for actions that, without the limitations, might 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 fiduciary duty under state fiduciary duty law. For example, our partnership agreement provides that:

 

   

whenever our general partner makes a determination or takes, or declines to take, any other action in its capacity as our general partner, our general partner is required to make such determination, or take or decline to take such other action, in good faith, meaning that it believed that the decision was in the best interests of our partnership, and will not be subject to any other or different standard imposed by our partnership agreement, Delaware law or any other law, rule or regulation, or at equity;

 

   

our general partner will 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 will not be liable for monetary damages to us or our limited partners resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers and directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal.

 

NRGY 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 NRGY, are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us. NRGY 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, NRGY is entitled under the omnibus agreement to review and has the first option on any third-party acquisition opportunities 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, NRGY may compete with us for investment opportunities, and NRGY may own an interest in entities that compete with us.

 

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 NRGY. 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. Please read “Conflicts of Interest and Fiduciary Duties.”

 

We will not have any subordinated units outstanding, and NRGY is entitled to receive 50% of all cash that we distribute in excess of the initial quarterly distribution of $         per common unit.

 

Unlike most publicly traded partnerships with incentive distribution rights, we will not have any subordinated units held by our general partner and its affiliates the distributions on which would be reduced in order to support a distribution to common unitholders. Because there will not be a security junior to the common units to absorb a shortfall in the distribution from the initial quarterly distribution, the common units will bear any and all shortfalls in the amount of cash needed to pay the initial quarterly distribution on all units. Similarly,

 

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the common units will not be entitled to arrearages in the event the initial quarterly distribution is not paid in a quarter. Furthermore, unlike many publicly traded partnerships with incentive distribution rights that only increase to 50% after moving through several increasing target distributions above a minimum quarterly distribution, NRGY is entitled to receive 50% of all cash that we distribute in excess of the initial quarterly distribution per common unit, including cash generated from our existing internal growth projects. As a result of our incentive distribution structure, if we are successful in increasing our distribution per common unit over time, we may have a higher equity cost of capital than many other publicly traded partnerships, which may make it more difficult for us to compete for acquisitions or to consummate acquisitions or internal growth projects that result in meaningful accretion to our common unitholders.

 

NRGY may elect to cause us to issue common units to it in connection with a resetting of the initial quarterly distribution related to its incentive distribution rights, 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.

 

NRGY has the right to reset, at a higher level, the initial quarterly distribution based on our cash distributions at the time of the exercise of the reset election. Following a reset election by NRGY, the initial 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 initial quarterly distribution”).

 

If NRGY elects to reset the initial quarterly distribution, it will be entitled to receive a number of newly issued common units. The number of common units to be issued to NRGY 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 NRGY on the incentive distribution rights in such prior quarter. It is possible that NRGY 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 incentive distribution rights and may, therefore, desire to be issued common units rather than retain the right to receive incentive distributions based on the initial 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 NRGY in connection with resetting the initial quarterly distribution. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions—NRGY’s Right to Reset Incentive Distribution Level.”

 

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 will 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 NRGY, as a result of it owning our general partner, and not by our common unitholders. Please read “Management—Management of Inergy Midstream, L.P.” and “Certain Relationships and Related Party Transactions.” 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.

 

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

 

If our common unitholders are dissatisfied with the performance of our general partner, they will have limited ability to remove our general partner. Common unitholders initially will be unable to remove our general partner without its consent because NRGY will own sufficient units upon the completion of this offering to be able to prevent its removal. The vote of the holders of at least 66 2/3% of all our outstanding common units is

 

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required to remove our general partner. Following the closing of this offering, NRGY will own, directly or indirectly, an aggregate of         % of our common units (or         % of our common units, if the underwriters exercise their option to purchase additional common units in full).

 

Common unitholders will experience immediate and substantial dilution in net tangible book value per common unit of $          per common unit.

 

The assumed initial public offering price of $         per common unit (the midpoint of the price range set forth on the cover page of this prospectus) exceeds pro forma net tangible book value of $         per common unit. Based on the assumed initial public offering price of $         per common unit, common unitholders will incur immediate and substantial dilution in net tangible book value per common unit of $         per common unit. This dilution results primarily because our assets are recorded at their historical cost in accordance with GAAP, and not their fair value. Please read “Dilution.”

 

Our general partner interest and our incentive distribution rights may be transferred without common unitholder consent.

 

Our partnership agreement provides that our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets 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, in connection with this offering, NRGY and Holdings GP, the indirect owner of NRGY’s general partner, expect to enter into an agreement under which Holdings GP will be required to purchase our general partner in the event that (i) a change of control of NRGY occurs at a time when NRGY is entitled to receive less than 50% of all cash distributed with respect to our limited partner interests and incentive distribution rights or (ii) through dilution or a distribution to the NRGY common unitholders of NRGY’s interests in us, NRGY is entitled to receive less than 25% of all cash distributed with respect to our limited partner interests and incentive distribution rights. Please read “Security Ownership of Certain Beneficial Owners and Management.” As a result, subject to receiving Holding GP’s consent, the member of our general partner may transfer its membership interest in our general partner to a third party. The new member of our general partner 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 incentive distribution rights may transfer those interests to a third party at any time without the consent of our common unitholders. NRGY indirectly owns all of our incentive distribution rights. If NRGY transfers its incentive distribution rights to a third party, NRGY 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 incentive distribution rights.

 

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         % 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 (1) the highest price paid by our general partner or any of its affiliates for any limited partner interests of the class purchased within the 90 days preceding the date on which our general partner first mails notice of its election to purchase those limited partner interests and (2) the average of the daily closing prices of the partnership securities of such class over the 20 consecutive trading days immediately preceding the date three days before the date 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

 

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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. Upon completion of this offering, and assuming no exercise of the underwriters’ option to purchase additional common units, NRGY will own, directly or indirectly, an aggregate of         % of our common units. For additional information about the limited call right, please read “The Partnership Agreement—Limited Call Right.”

 

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. Please read “The Partnership Agreement—Issuance of Additional Interests.”

 

The market price of our common units could be adversely affected by sales of substantial amounts of our common units in the public or private markets, including sales by NRGY or other large common unitholders.

 

Upon completion of this offering, we will have          common units outstanding, which includes the          common units we are selling in this offering that may be resold in the public market immediately (          if the underwriters exercise in full their option to purchase additional common units). All of the common units (          if the underwriters exercise in full their option to purchase additional common units) that are issued to NRGY will be subject to resale restrictions under a 180-day lock-up agreement with the underwriters. Each of the lock-up agreements with the underwriters may be waived in the discretion of certain of the underwriters. Sales of a substantial number of our common units by NRGY or other large common unitholders in the public markets following this offering, or the perception that such sales might occur, could have a material adverse effect on the price of our common units or could impair our ability to obtain capital through an offering of equity securities. In addition, we have agreed to provide registration rights to NRGY. Under our partnership agreement, our general partner and its affiliates have registration rights relating to the offer and sale of any units that they hold, subject to certain limitations. Please read “Units Eligible for Future Sale.”

 

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.

 

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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 NRGY, for all expenses they incur and payments they make on our behalf pursuant to the omnibus agreement, which we expect to be approximately $5 million for the twelve months ending December 31, 2012. 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. Please read “Certain Relationships and Related Party Transactions—Agreements with Affiliates in Connection with the Transactions—Omnibus Agreement.” 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. 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. Please read “Cash Distribution Policy and Restrictions on Distributions.”

 

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.

 

There is no existing market for our common units, and a trading market that will provide you with adequate liquidity may not develop. The price of our common units may fluctuate significantly, and common unitholders could lose all or part of their investment.

 

Prior to this offering, there has been no public market for the common units. Upon completion of this offering, there will be only        publicly traded common units held by our public unitholders (        common units if the underwriters exercise their option to purchase additional common units in full). We do not know the extent to which investor interest will lead to the development of a trading market or how liquid that market might be. Unitholders may not be able to resell their common units at or above the initial public offering price. Additionally, the lack of liquidity may result in wide bid-ask spreads, contribute to significant fluctuations in the market price of the common units and limit the number of investors who are able to buy the common units.

 

The initial public offering price for our common units will be determined by negotiations between us and the representatives of the underwriters and may not be indicative of the market price of the common units that will prevail in the trading market. The market price of our common units may decline below the initial public offering price. The market price of our common units may also be influenced by many factors, some of which are beyond our control, including:

 

   

our quarterly distributions;

 

   

our quarterly or annual earnings or those of other companies in our industry;

 

   

announcements by us or our competitors of significant contracts or acquisitions;

 

   

changes in accounting standards, policies, guidance, interpretations or principles;

 

   

general economic conditions;

 

   

the failure of securities analysts to cover our common units after this offering or changes in financial estimates by analysts;

 

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future sales of our common units; and

 

   

the other factors described in these “Risk Factors.”

 

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, or 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. 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. Please read “The Partnership Agreement—Limited Liability.”

 

The NYSE does not require a publicly traded partnership like us to comply with certain of its corporate governance requirements.

 

We intend to apply to list our common units on the NYSE. Because we will be a publicly traded partnership, the NYSE does not require us to have a majority of independent directors on our general partner’s board of directors or establish a compensation committee or a nominating and corporate governance committee. Accordingly, common unitholders will not have the same protections afforded to most corporations that are subject to all of the NYSE corporate governance requirements. Please read “Management—Management of Inergy Midstream, L.P.”

 

We will incur increased costs as a result of being a publicly traded partnership.

 

We have no history operating as a publicly traded partnership. As a publicly traded partnership, we will incur significant legal, accounting and other expenses that we did not incur prior to this offering. In addition, the Sarbanes-Oxley Act of 2002, or Sarbanes-Oxley Act, as well as rules implemented by the SEC and the NYSE, require publicly traded entities to adopt various corporate governance practices that will further increase our costs. Before we are able to make distributions to our common unitholders, we must first pay or reserve cash for our expenses, including the costs of being a publicly traded partnership. As a result, the amount of cash we have available for distribution to our common unitholders will be affected by the costs associated with being a publicly traded partnership.

 

Prior to this offering, we have not filed reports with the SEC. Following this offering, we will become subject to the public reporting requirements of the Exchange Act. We expect these rules and regulations to increase certain of our legal and financial compliance costs and to make activities more time-consuming and

 

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costly. For example, as a result of becoming a publicly traded partnership, we are required to have at least three independent directors, create an audit committee and adopt policies regarding internal controls and disclosure controls and procedures, including the preparation of reports on internal controls over financial reporting. In addition, we will incur additional costs associated with our SEC reporting requirements.

 

We estimate that we will incur approximately $3.0 million of incremental external costs per year and additional internal costs associated with being a publicly traded partnership; however, it is possible that our actual incremental costs of being a publicly traded partnership will be higher than we currently estimate.

 

Tax Risks to Common Unitholders

 

In addition to reading the following risk factors, please read “Material U.S. Federal Income Tax Consequences” for a more complete discussion of the expected material U.S. federal income tax consequences of owning and disposing of common units.

 

Our tax treatment depends on our status as a partnership for U.S. federal income tax purposes. If the IRS were to treat us as a corporation for federal income tax purposes, then our cash available for distribution to you 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 a “qualifying income” requirement.

 

Failing to meet the qualifying income requirement or a change in current law may cause us to be treated as a corporation for federal income tax purposes. If we were subject to federal income tax as a corporation, our cash available to pay distributions would be reduced. Therefore, our treatment as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to our common unitholders, likely causing a substantial reduction in the value of our common units.

 

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 income tax purposes, then the initial quarterly distribution may be adjusted to reflect the impact of that law on us.

 

The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

 

The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. For example, members of Congress have recently considered substantive changes to the existing federal income tax laws that affect publicly traded partnerships. Any modification to the U.S. federal income tax laws and interpretations thereof may be applied retroactively and could make it more difficult or impossible to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes or otherwise subject us to taxation as an entity. We are unable to predict whether any of these changes, or other proposals will be reintroduced or will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units.

 

If we were subjected to a material amount of additional entity-level taxation by individual states, then our cash available for distribution to you would be substantially reduced.

 

Future changes in current state law may subject us to additional entity-level taxation by individual states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject

 

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partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of any such taxes may substantially reduce our cash available for distribution to you. Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to additional amounts of entity-level taxation, then the initial quarterly distribution may be adjusted to reflect the impact of that law on us.

 

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

 

Because our common unitholders will be treated as partners to whom we will allocate taxable income that could be different in amount than the cash we distribute, you will be required to pay any federal income taxes and, in some cases, state and local income taxes on your share of our taxable income whether or not you receive 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.

 

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

 

We will be considered to have terminated our partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. Immediately following this offering, NRGY will own, directly and indirectly, more than 50% of the total interests in our capital and profits interests. Therefore, a transfer by NRGY (including a deemed transfer as a result of a termination of NRGY) of all or a portion of its interests in us could result in a termination of our partnership for federal income tax purposes. Our termination would, among other things, result in the closing of our taxable year for all common unitholders and could result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a common unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. Our termination currently 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. Please read “Material U.S. Federal Income Tax Consequences—Disposition of Units—Constructive Termination” for a discussion of the consequences of our termination for federal income tax purposes.

 

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 the amount realized and your tax basis in those common units. Because distributions in excess of your allocable share of our net taxable income decrease 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 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 items, including depreciation recapture. In addition, because the amount realized includes a common 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. Please read “Material U.S. Federal Income Tax Consequences—Disposition of Units—Recognition of Gain or Loss” for a further discussion of the foregoing.

 

Tax-exempt entities 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, such as employee benefit plans and individual retirement accounts, or IRAs, and non-U.S. persons raises issues unique to them. For example, virtually all of our

 

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income allocated to organizations that are exempt from federal income tax, including IRAs 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 at the highest applicable effective tax rate, and non-U.S. persons will be required to file U.S. federal 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.

 

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.

 

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 some or all of 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. Our costs of any contest with the IRS will be borne indirectly by our common unitholders because the costs will reduce our cash available for distribution.

 

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

 

Due to a number of factors, including our inability to match transferors and transferees of common units, we will adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to you. It also could affect the timing of these tax benefits or the amount of gain from your sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to your tax returns. Please read “Material U.S. Federal Income Tax Consequences—Tax Consequences of Unit Ownership—Section 754 Election” for a further discussion of the effect of the depreciation and amortization positions we adopt.

 

We will 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. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our common unitholders.

 

We will generally prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular common unit is transferred. Nonetheless, we allocate certain deductions for depreciation of capital additions based upon the date the underlying property is placed in service. The use of this proration method may not be permitted under existing Treasury Regulations, and although the U.S. Treasury Department issued proposed Treasury Regulations allowing a similar monthly simplifying convention, such regulations are not final and do not specifically authorize the use of the proration method we have adopted. Accordingly, our counsel is unable to opine as to the validity of this method. If the IRS were to successfully challenge our proration method, we may be required to change the allocation of items of income, gain, loss, and deduction among our common unitholders. Please read “Material U.S. Federal Income Tax Consequences—Disposition of Units—Allocations Between Transferors and Transferees” for further discussion of the methods that we use for allocations between transferors and transferees.

 

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

 

Because there is no tax concept of loaning a partnership interest, a unitholder whose common units are loaned to a “short seller” to cover a short sale of common units may be considered as having disposed of the

 

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loaned units. In that case, he may no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income. Common unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller should modify any applicable brokerage account agreements to prohibit their brokers from borrowing their common units.

 

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

 

In addition to U.S. federal income taxes, you will likely be subject to other taxes, including foreign, state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if you do not live in any of those jurisdictions. You will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, you may be subject to penalties for failure to comply with those requirements. We will initially own assets and conduct business in the states of New York and Pennsylvania. Each of these states currently imposes a personal income tax and also imposes income taxes on corporations and other entities. As we make acquisitions or expand our business, we may own assets or conduct business in additional states or foreign jurisdictions that impose a personal income tax. It is your responsibility to file all U.S. federal, foreign, state and local tax returns. Our counsel has not rendered an opinion on the foreign, state or local tax consequences of an investment in our common units.

 

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USE OF PROCEEDS

 

We intend to use the estimated net proceeds of approximately $         million from this offering, after deducting the estimated underwriting discounts and commissions, the structuring fee and offering expenses payable by us, to repay approximately $         million of indebtedness outstanding under our revolving credit facility. Any remaining net proceeds will be used for general partnership purposes.

 

The borrowings under our revolving credit facility that we will assume from NRGY in connection with our formation transactions were primarily incurred to fund acquisitions and growth projects at NRGY. Borrowings under our revolving credit facility bear interest at approximately         %. We expect our revolving credit facility will mature on                     , 2016.

 

We expect to re-borrow $80 million under our revolving credit facility to fund a cash distribution to NRGY for reimbursement of capital expenditures associated with our assets.

 

If and to the extent the underwriters exercise their option to purchase all or a portion of the          additional common units, the number of common units purchased by the underwriters pursuant to such exercise will be issued to the public and the remainder of the          additional common units, if any, will be issued to NRGY. Any such units issued to NRGY will be issued for no additional consideration. If the underwriters exercise their option to purchase          additional common units in full, the additional net proceeds would be approximately $         million. The net proceeds from any exercise of such option will be distributed to NRGY. If the underwriters do not exercise their option to purchase additional common units, we will issue          common units to NRGY upon the option’s expiration. We will not receive any additional consideration from NRGY in connection with such issuance. Accordingly, the exercise of the underwriters’ option will not affect the total number of common units outstanding or the amount of cash needed to pay the initial quarterly distribution on all common units. Please read “Underwriting.”

 

A $1.00 increase or decrease in the assumed initial public offering price of $         per common unit would cause the net proceeds from this offering, after deducting the estimated underwriting discounts and commissions, the structuring fee and offering expenses payable by us, to increase or decrease, respectively, by approximately $         million. In addition, we may also increase or decrease the number of common units we are offering. Each increase of 1.0 million common units offered by us, together with a concurrent $1.00 increase in the assumed public offering price to $         per common unit, would increase net proceeds to us from this offering by approximately $         million. Similarly, each decrease of 1.0 million common units offered by us, together with a concurrent $1.00 decrease in the assumed initial offering price to $         per common unit, would decrease the net proceeds to us from this offering by approximately $         million.

 

Affiliates of certain of the underwriters are lenders under our revolving credit facility and, accordingly, will receive a substantial portion of the proceeds from this offering. Please read “Underwriting.”

 

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CAPITALIZATION

 

The following table shows our cash and cash equivalents and capitalization as of June 30, 2011:

 

   

on an actual basis; and

 

   

as adjusted to reflect this offering of our common units, the other transactions described under “Summary—Formation Transactions and Partnership Structure” and the application of the net proceeds from this offering as described under “Use of Proceeds.”

 

This table is derived from, and should be read together with, the unaudited pro forma condensed consolidated financial statements and the accompanying notes included elsewhere in this prospectus. You should also read this table in conjunction with “Summary—Formation Transactions and Partnership Structure,” “Use of Proceeds” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

 

     As of June 30, 2011  
     Actual      As Adjusted  
     (In millions)  

Cash and cash equivalents

   $ 9.4       $     
  

 

 

    

 

 

 

Debt:

     

Revolving credit facility

   $       $ 80.0 (a) 

Member’s/partners’ capital:

     

Held by public:

     

Common units

          

Held by NRGY:

     

Net parent capital

     475.9           

Common units

          

General partner interest

          
  

 

 

    

 

 

 

Total member’s/partners’ capital

   $ 475.9       $     
  

 

 

    

 

 

 

Total capitalization

   $ 475.9       $            
  

 

 

    

 

 

 

 

(a)   Reflects (i) our assumption of approximately $         million of indebtedness from NRGY under our revolving credit facility that will be assigned to us of which we will repay $         million using the net proceeds of this offering and (ii) our re-borrowing of approximately $80 million under our revolving credit facility, which will be used to reimburse NRGY for capital expenditures incurred prior to this offering related to our assets.

 

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DILUTION

 

Dilution is the amount by which the offering price paid by the purchasers of common units sold in this offering will exceed the net tangible book value per common unit after the offering. Assuming an initial public offering price of $        per common unit (the midpoint of the price range set forth on the cover page of this prospectus), on a pro forma basis as of June 30, 2011, after giving effect to the offering of common units and the related transactions, our net tangible book value was approximately $        million, or $        per common unit. Purchasers of our common units in this offering will experience substantial and immediate dilution in net tangible book value per common unit for financial accounting purposes, as illustrated in the following table.

 

Assumed initial public offering price per common unit

      $                

Pro forma net tangible book value per common unit before the offering(1)

   $                   

Increase in net tangible book value per common unit attributable to purchasers in the offering

     
  

 

 

    

Less: Pro forma net tangible book value per common unit after the offering(2)

     
     

 

 

 

Immediate dilution in net tangible book value per common unit to purchasers in the offering(3)(4)

      $     
     

 

 

 

 

(1)   Determined by dividing the pro forma net tangible book value of our assets and liabilities by the number of common units (         common units, assuming no exercise of the underwriters’ option to purchase additional common units) to be issued to our affiliates.
(2)   Determined by dividing our pro forma net tangible book value, after giving effect to the use of the net proceeds of the offering, by the total number of common units (         common units, assuming no exercise of the underwriters’ option to purchase additional common units) to be outstanding after the offering.
(3)   Each $1.00 increase or decrease in the assumed public offering price of $         per common unit would increase or decrease, respectively, our pro forma net tangible book value by approximately $         million, or approximately $         per common unit, and dilution per common unit to investors in this offering by approximately $         per common unit, after deducting the estimated underwriting discounts and commissions, the structuring fee and offering expenses payable by us. We may also increase or decrease the number of common units we are offering. An increase of 1.0 million common units offered by us, together with a concurrent $1.00 increase in the assumed offering price to $         per common unit, would result in a pro forma net tangible book value of approximately $         million, or $         per common unit, and dilution per common unit to investors in this offering would be $         per common unit. Similarly, a decrease of 1.0 million common units offered by us, together with a concurrent $1.00 decrease in the assumed public offering price to $         per common unit, would result in an pro forma net tangible book value of approximately $         million, or $         per common unit, and dilution per common unit to investors in this offering would be $         per common unit. The information discussed above is illustrative only and will be adjusted based on the actual public offering price and other terms of this offering determined at pricing.
(4)   Because the total number of units outstanding following this offering will not be impacted by any exercise of the underwriters’ option to purchase additional common units and any net proceeds from such exercise will not be retained by us, there will be no change to the dilution in net tangible book value per common unit to purchasers in the offering due to any such exercise of the option.

 

The following table sets forth the number of common units that we will issue and the total consideration contributed to us by NRGY and by the purchasers of our common units in this offering upon completion of the transactions contemplated by this prospectus.

 

     Common Units     Total Consideration  
     Number    Percent     Amount      Percent  

NRGY(1)(2)

               $                          

Purchasers in the offering(2)

               $               
  

 

  

 

 

   

 

 

    

 

 

 

Total

            100   $               100
  

 

  

 

 

   

 

 

    

 

 

 

 

(1)   Upon the completion of the transactions contemplated by this prospectus, NRGY will own             common units, assuming no exercise of the underwriters’ option to purchase additional common units.
(2)   A $1.00 increase (decrease) in the assumed initial public offering price of $         per common unit would increase (decrease) total consideration paid by purchasers in this offering by $         million, and total consideration provided by NRGY by $         million, in each case assuming the number of common units offered hereby, as set forth on the cover page of this prospectus, remains the same.

 

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CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

 

You should read the following discussion of our cash distribution policy in conjunction with “—Assumptions and Considerations” below, which includes the factors and assumptions upon which we base our cash distribution policy. In addition, you should read “Forward-Looking Statements” and “Risk Factors” for information regarding statements that do not relate strictly to historical or current facts and certain risks inherent in our business.

 

For additional information regarding our historical and pro forma results of operations, you should refer to our audited historical consolidated financial statements as of September 30, 2009 and 2010 and for the fiscal years ended September 30, 2008, 2009 and 2010, our unaudited historical consolidated financial statements as of June 30, 2011 and for the nine months ended June 30, 2010 and 2011 and our unaudited pro forma condensed consolidated financial statements for the fiscal year ended September 30, 2010 and as of and for the nine months ended June 30, 2011 included elsewhere in this prospectus.

 

General

 

Rationale for Our Cash Distribution Policy

 

Our partnership agreement requires us to distribute all of our available cash quarterly. Our cash distribution policy reflects a judgment that our common unitholders will be better served by our distributing rather than retaining our available cash. Our partnership agreement generally defines available cash as, for each quarter, (i) all cash on hand at the end of that quarter, less the amount of cash reserves established by our general partner to provide for the proper conduct of our business, comply with applicable law, any of our debt agreements or other agreement or provide funds for distributions to our common unitholders for any one or more of the next four quarters, plus (ii) cash on hand resulting from working capital borrowings made after the end of the quarter. Because we are not subject to an entity-level federal income tax, we expect to have more cash to distribute to our common unitholders than would be the case were we subject to entity-level federal income tax.

 

Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy

 

There is no guarantee that we will distribute quarterly cash distributions to our common unitholders. Our cash distribution policy may be changed at any time and is subject to certain restrictions, including:

 

   

We expect that our cash distribution policy will be subject to restrictions on distributions under our revolving credit facility, and other debt agreements that we enter into in the future may have similar restrictions. Specifically, the agreement governing our revolving credit facility is expected to contain financial covenants that we must satisfy. Should we be unable to satisfy these restrictions or if we are otherwise in default under our revolving credit facility, we would be prohibited from making cash distributions to you notwithstanding our stated cash distribution policy. For a discussion of these restrictions, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Sources of Capital—Revolving Credit Facility.”

 

   

Our general partner will have the authority to establish cash reserves for the prudent conduct of our business and for future cash distributions to our common unitholders, and the establishment of or increase of those reserves could result in a reduction in cash distributions from levels we currently anticipate pursuant to our stated cash distribution policy. Our partnership agreement does not set a limit on the amount of cash reserves that our general partner may establish. Any decision to establish cash reserves made by our general partner in good faith will be binding on our common unitholders.

 

   

Although our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including provisions requiring us to make cash distributions contained therein, may be amended. Our partnership agreement generally can be amended with the consent of our general partner

 

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and the approval of a majority of the outstanding common units (including common units held by NRGY). At the closing of this offering, NRGY will own, directly or indirectly, approximately          % of the outstanding common units. Please read “The Partnership Agreement—Amendment of the Partnership Agreement.”

 

   

Even if our cash distribution policy is not modified or revoked, the amount of distributions we pay under our cash distribution policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement.

 

   

Under Section 17-607 of the Delaware Act, we may not make a distribution if the distribution would cause our liabilities to exceed the fair value of our assets.

 

   

We may lack sufficient cash to pay distributions to our common unitholders due to cash flow shortfalls attributable to a number of operational, commercial or other factors as well as increases in our operating and administrative expenses (including the reimbursement to our general partner and its affiliates under the omnibus agreement for all direct and indirect expenses they incur on our behalf), principal and interest payments on our debt, tax expenses, working capital requirements and anticipated cash needs. Our cash available for distribution to common unitholders is directly impacted by our cash expenses necessary to run our business and will be reduced dollar-for-dollar to the extent such uses of cash increase. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions—Distributions of Available Cash.”

 

   

Prior to making any distribution on our common units, we will reimburse our general partner and its affiliates, including NRGY, for all expenses they incur and payments they make on our behalf pursuant to the omnibus agreement, which we expect to be approximately $5 million for the twelve months ending December 31, 2012. 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. Please read “Certain Relationships and Related Party Transactions—Agreements with Affiliates in Connection with the Transactions—Omnibus Agreement.” 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. 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.

 

   

Our ability to make distributions to our common unitholders depends on the performance of our subsidiaries and their ability to distribute cash to us. The ability of our subsidiaries to make distributions to us may be restricted by, among other things, the provisions of future indebtedness, applicable state partnership and limited liability company laws and other laws and regulations.

 

   

If we make distributions out of capital surplus, as opposed to operating surplus, any such distributions would constitute a return of capital and would result in a reduction in the initial quarterly distribution. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions—Adjustment to the Initial Quarterly Distribution.” We do not anticipate that we will make any distributions from capital surplus.

 

Our Ability to Grow is Dependent on Our Ability to Access External Expansion Capital

 

Our partnership agreement requires us to distribute all of our available cash to our common unitholders on a quarterly basis. As a result, we expect that we will rely primarily upon external financing sources, including borrowings under our revolving credit facility and issuances of debt and equity securities, to fund expansion capital expenditures. Moreover, while we have historically received funding from our affiliates, we do not have any commitment with our general partner or other affiliates, including NRGY, to fund our cash flow deficits or provide other direct or indirect financial assistance to us following the closing of this offering. NRGY’s

 

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significant economic stake in us may, however, provide NRGY with a strong incentive to promote and support the successful execution of our growth plan and strategy, including by providing us with direct or indirect financial assistance. However, the indentures governing NRGY’s outstanding senior notes would substantially restrict the types, amounts and terms of any such assistance that NRGY might desire to provide us.

 

Our cash distribution policy may significantly impair our ability to grow if we are unable to access these external sources to finance our growth. In addition, because we distribute all of our available cash, our growth may not be as fast as businesses that reinvest all of their available cash to expand ongoing operations. To the extent we issue additional units, 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 no limitations in our partnership agreement 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 would result in increased interest expense, which in turn may impact the available cash that we have to distribute to our common unitholders.

 

Our Initial Quarterly Distribution

 

Upon the completion of this offering, the board of directors of our general partner will establish an initial quarterly distribution of $        per unit for each complete quarter, or $        per year, to be paid within 45 days after the end of each quarter, beginning with the quarter ending December 31, 2011. This equates to an aggregate cash distribution of $        million per quarter, or $        million per year, based on the number of common units that will be outstanding immediately after completion of this offering. Our ability to make cash distributions at the initial quarterly distribution rate will be subject to the restrictions described above under “—General—Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy.”

 

If the underwriters do not exercise their option to purchase additional common units, we will issue common units to NRGY at the expiration of the option period. If and to the extent the underwriters exercise their option to purchase additional common units, the number of common units purchased by the underwriters pursuant to such exercise will be sold to the public and any units not purchased by the underwriters pursuant to their option will be issued to NRGY as part of our formation transactions. Accordingly, the exercise of the underwriters’ option will not affect the total number of units outstanding or the amount of cash needed to pay the initial quarterly distribution on all common units. Please read “Underwriting.”

 

The table below sets forth the amount of common units that will be outstanding immediately after the closing of this offering and the available cash needed to pay the aggregate initial quarterly distribution on all of such units for a single fiscal quarter and a four quarter period:

 

            Distributions  
     Number of Units      One Quarter      Annualized  

Publicly held common units

      $         $     

Common units held by NRGY

        

General partner interest(1)

                       
  

 

 

    

 

 

    

 

 

 

Total

      $                    $                
  

 

 

    

 

 

    

 

 

 

 

(1)   Our general partner owns a non-economic general partner interest.

 

As of the date of this offering, NRGY will hold the incentive distribution rights, which entitle the holder to 50.0% of the cash we distribute in excess of $         per unit per quarter.

 

We do not have a legal obligation to pay distributions at our initial distribution rate or at any other rate, except as provided in our partnership agreement. Our cash distribution policy is consistent with the terms of our partnership agreement, which requires that we distribute all of our available cash quarterly. Although holders of

 

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our common units may pursue judicial action to enforce provisions of our partnership agreement, including those related to requirements to make cash distributions as described above, our partnership agreement provides that any determination made by our general partner in its capacity as our general partner must be made in good faith and that any such determination will not be subject to any other standard imposed by the Delaware Act or any other law, rule or regulation or at equity. Our partnership agreement provides that, in order for a determination by our general partner to be made in “good faith,” our general partner must believe that the determination is in our best interest. Please read “Conflicts of Interest and Fiduciary Duties.”

 

The actual amount of our cash distributions for any quarter is subject to fluctuations based on, among other things, the amount of cash we generate from our business and the amount of reserves our general partner establishes in accordance with our partnership agreement. We will pay our distributions no later than 45 days following the end of each quarter to common unitholders of record on the record date selected by our general partner in its reasonable discretion. We will adjust the first quarterly distribution following this offering on a pro rata basis for the period from the closing date of this offering through December 31, 2011 based on the actual length of the period.

 

In the sections that follow, we present in detail the basis for our belief that we will be able to fully fund our initial quarterly distribution of $         per quarter for the twelve months ending December 31, 2012. In those sections, we present two tables, consisting of:

 

   

“Unaudited Pro Forma Cash Available for Distribution,” in which we present the amount of cash we would have had available for distribution on a pro forma basis for our fiscal year ended September 30, 2010 and the twelve months ended June 30, 2011, derived from our unaudited pro forma financial data that are included in this prospectus, as adjusted to give pro forma effect to the offering and the formation transactions; and

 

   

“Estimated Cash Available for Distribution for the Twelve Months Ending December 31, 2012,” in which we demonstrate our ability to generate the estimated Adjusted EBITDA necessary for us to pay the initial quarterly distribution on all units for each quarter for the twelve months ending December 31, 2012.

 

Unaudited Pro Forma Cash Available for Distribution

 

If we had completed the transactions contemplated in this prospectus on October 1, 2009, our unaudited pro forma cash available for distribution for the twelve months ended September 30, 2010, would have been approximately $65.8 million. If we had completed the transactions contemplated in this prospectus on July 1, 2010, our pro forma cash available for distribution for the twelve months ended June 30, 2011, would have been approximately $73.4 million. These amounts would have been insufficient to make the initial quarterly distribution of $         per unit per quarter (or $         per unit on an annualized basis) on all of our common units during such periods. We estimate that our pro forma cash available for distribution for the fiscal year ended September 30, 2010 and the nine months ended June 30, 2011 would have been sufficient to pay only         % and         %, respectively, of the full initial quarterly distribution on all of our common units for those periods.

 

Unaudited pro forma cash available for distribution includes direct, incremental administrative expenses of approximately $3.0 million that we expect to incur as a result of being a publicly traded partnership. These incremental expenses include, costs associated with SEC reporting requirements, including annual and quarterly reports to common unitholders, tax return and Schedule K-1 preparation and distribution, independent auditor fees, investor relations activities, Sarbanes-Oxley Act compliance, NYSE listing, registrar and transfer agent fees, director and officer liability insurance costs, and director compensation. In future periods, the board of directors of our general partner may grant awards to our key employees and our outside directors pursuant to our long-term incentive plan; however, the board has not yet made any determination as to the number of awards or when the awards would be granted. Such incremental administrative expenses are not reflected in our historical and pro forma financial statements.

 

We based the pro forma financial statements upon currently available information and specific estimates and assumptions. The pro forma cash amounts do not purport to present our results of operations had the transactions

 

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contemplated in this prospectus actually been completed as of the dates indicated. Furthermore, cash available for distribution is primarily a cash accounting concept, while our unaudited pro forma financial statements have been prepared on an accrual basis. As a result, you should view the amount of pro forma cash available for distribution only as a general indication of the amount of cash available for distribution that we might have generated had we been formed and completed the transactions contemplated in this prospectus in earlier periods.

 

The footnotes to the table below provide additional information about the pro forma adjustments and should be read along with the table.

 

Inergy Midstream, L.P.

Unaudited Pro Forma Cash Available for Distribution

 

     Year Ended     Twelve Months Ended  
     September 30, 2010     June 30, 2011  
     ($ in millions)  

Pro Forma Net Income

   $ 30.1      $ 40.4  
  

 

 

   

 

 

 

Add:

    

Depreciation and amortization

     36.2       36.8  

Interest expense, net(1)

     1.3       1.5  

Net income attributable to non-controlling partners

     (0.8       

Interest of non-controlling partners in consolidated ITDA(2)

     (0.2       

Long-term incentive and equity compensation expense(3)

     2.7        1.7   

Loss on disposal of assets

     0.9         

Transaction costs

     0.2          

Income tax expense

              
  

 

 

   

 

 

 

Pro Forma Adjusted EBITDA(4)

   $     70.4     $     80.4  

Adjustments to reconcile pro forma Adjusted EBITDA to pro forma cash available for distribution:

    

Less:

    

Estimated incremental administrative expense(5)

     3.0       3.0  

Cash interest expense(6)

     1.3        1.5  

Cash tax expense(7)

              

Maintenance capital expenditures

     0.3       2.5  

Expansion capital expenditures(8)

     49.5        73.0  

Add:

    

Borrowings to fund expansion capital expenditures(7)

     49.5        73.0  
  

 

 

   

 

 

 

Pro Forma Cash Available for Distribution

   $ 65.8      $ 73.4  
  

 

 

   

 

 

 

Pro Forma Cash Distributions

    

Annualized initial quarterly distributions per unit

    

Distributions to public common unitholders

    

Distributions to NRGY—common units

    

Total annualized initial quarterly cash distributions

    
  

 

 

   

 

 

 

Excess (shortfall)

   $        $     
  

 

 

   

 

 

 

Percent of initial quarterly distributions payable to common unitholders

     %        %   

 

(1)   Interest expense is based upon our estimates of: (i) average borrowings under our revolving credit facility of $104.8 million during the fiscal year ended September 30, 2010, and $116.5 million during the twelve months ended June 30, 2011; (ii) interest incurred at a rate of 3.5% per annum (based on LIBOR rates during the period plus a margin); and (iii) commitment fees on the unused portion of our revolving credit facility of 0.375% per annum. Interest expense also includes the amortization of debt issuance costs of approximately $         million per year incurred in connection with our revolving credit facility.
(2)   Interest, tax, depreciation and amortization expense attributable to non-controlling partners.
(3)   Represents expense associated with grants under NRGY’s long-term incentive plan to employees that are dedicated to our operations.
(4)   Adjusted EBITDA is defined in “Summary—Non-GAAP Financial Measures.”
(5)   Represents estimated incremental cash expense associated with our being a publicly traded partnership.
(6)   Cash interest expense reflects our interest expense less the non-cash amortization of deferred financing costs incurred in connection with our revolving credit facility.
(7)   As a limited liability company, we did not pay income tax during the applicable period.
(8)   Expansion capital expenditures for the fiscal year ended September 30, 2010, and for the twelve months ended June 30, 2011, were $49.5 million and $73.0 million, respectively, and were primarily incurred to fund our growth projects. We assumed that these capital expenditures were funded by borrowings on our revolving credit facility.

 

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Estimated Cash Available for Distribution for the Twelve Months Ending December 31, 2012

 

We forecast that our estimated cash available for distribution during the twelve months ending December 31, 2012 will be approximately $121.0 million. This amount would exceed by $         the amount needed to pay the initial quarterly distribution of $         per unit on all of our common units for each quarter in the four quarters ending December 31, 2012.

 

We are providing the forecast of Estimated Cash Available for Distribution to supplement our historical and pro forma financial statements in support of our belief that we will have sufficient cash available to allow us to pay cash distributions on all of our common units for each quarter in the twelve months ending December 31, 2012 at the initial quarterly distribution rate. Please read “—Assumptions and Considerations” for further information as to the assumptions we have made for the forecast. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies” for information as to the accounting policies we have followed for the financial forecast.

 

Our forecast reflects our judgment as of the date of this prospectus of conditions we expect to exist and the course of action we expect to take during the twelve months ending December 31, 2012. We believe that our actual results of operations will approximate those reflected in our forecast, but we can give no assurance that our forecasted results will be achieved. If our estimates are not achieved, we may not be able to pay distributions on our common units at the initial quarterly distribution rate of $         per unit each quarter (or $         per unit on an annualized basis) or any other rate. The assumptions and estimates underlying the forecast are inherently uncertain and, though we consider them reasonable as of the date of this prospectus, are subject to a wide variety of significant business, economic and competitive risks and uncertainties that could cause actual results to differ materially from those contained in the forecast, including, among others, risks and uncertainties contained in “Risk Factors.” Accordingly, there can be no assurance that the forecast is indicative of our future performance or that actual results will not differ materially from those presented in the forecast. Inclusion of the forecast in this prospectus should not be regarded as a representation by any person that the results contained in the forecast will be achieved.

 

We have prepared the following forecast to present the estimated cash available for distribution to our common unitholders during the forecasted period. The accompanying prospective financial information was not prepared with a view toward complying with the guidelines established by the American Institute of Certified Public Accountants with respect to prospective financial information, but, in our view, was prepared on a reasonable basis, reflects the best currently available estimates and judgments, and presents, to the best of management’s knowledge and belief, the expected course of action and our expected future financial performance. However, this information is not necessarily indicative of future results.

 

Neither our independent registered public accounting firm, nor any other independent accountants, have compiled, examined or performed any procedures with respect to the prospective financial information contained herein, nor have they expressed any opinion or any other form of assurance on such information or its achievability, and assume no responsibility for, and disclaim any association with, the prospective financial information. The independent registered public accounting firm’s report included in this prospectus relates to historical financial information. It does not extend to prospective financial information and should not be read to do so.

 

We do not undertake any obligation to release publicly the results of any future revisions we may make to the financial forecast or to update this financial forecast or the assumptions used to prepare the forecast to reflect events or circumstances after the completion of this offering. In light of this, the statement that we believe that we will have sufficient cash available for distribution to allow us to make the full initial quarterly distribution on all of our outstanding common units for each quarter through December 31, 2012, should not be regarded as a representation by us, the underwriters or any other person that we will make such distribution. Therefore, you are cautioned not to place undue reliance on this information.

 

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Inergy Midstream, L.P.

Estimated Cash Available for Distribution

 

     Twelve  Months
Ending

December 31, 2012
 
     (In millions)  

Revenue

  

Firm storage

   $ 104.7   

Transportation

     42.5   

Hub services

     11.5   
  

 

 

 

Total Revenue

     158.7   

Cost of Services Sold (excluding depreciation and amortization as shown below)

  

Storage

     4.4   

Transportation

     7.4   
  

 

 

 

Gross Profit

     146.9   

Operating Expenses

  

Operating and administrative

     22.7   

Depreciation and amortization

     54.3   
  

 

 

 

Total Operating Expenses

     77.0   

Operating Income

     69.9   

Interest expense, net(1)

     2.8   
  

 

 

 

Net Income

     67.1   

Adjustments to reconcile net income to estimated Adjusted EBITDA:

  

Add:

  

Income tax expense(2)

       

Interest expense, net

     2.8   

Depreciation and amortization expense

     54.3   

Long-term incentive and equity compensation expense(3)

     1.6   
  

 

 

 

Estimated Adjusted EBITDA(4)

     125.8   

Adjustments to reconcile estimated Adjusted EBITDA to estimated cash available for distribution:

  

Less:

  

Cash interest expense(5)

     2.8   

Estimated expansion capital expenditures(1)

     176.1   

Estimated maintenance capital expenditures

     2.0   

Add:

  

Borrowings to fund expansion capital expenditures

     176.1   
  

 

 

 

Estimated Cash Available for Distribution

   $ 121.0   
  

 

 

 

Annualized initial quarterly distributions per unit

  

Distributions to public common unitholders

   $     

Distributions to NRGY—common units

  
  

 

 

 

Total annualized initial quarterly cash distributions

   $     
  

 

 

 

Excess of cash available for distribution over aggregate annualized initial quarterly cash distributions

  

Calculation of estimated Adjusted EBITDA necessary to pay aggregate annualized initial quarterly cash distributions:

  

Estimated Adjusted EBITDA

   $ 125.8   

Excess of cash available for distribution over annualized initial quarterly cash distributions

  

Estimated Adjusted EBITDA necessary to pay aggregate annualized initial quarterly cash distributions

   $     

 

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(1)   Cash paid for capitalized interest is treated as an “expansion capital expenditure” for purposes of our determination of cash available for distribution. Estimated cash paid to settle capitalized interest during the period is approximately $3.7 million and is included as a component of “Expansion capital expenditures.”
(2)   As a limited partnership, we do not expect to pay income tax during the forecast period.
(3)   Represents expense associated with grants under NRGY’s long-term incentive plan to employees that are dedicated to our operations.
(4)   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, and our ability to service debt obligations. Please read “Summary—Non-GAAP Financial Measures.”
(5)   Cash interest expense is book interest expense less amortization of deferred financing costs.

 

Assumptions and Considerations

 

We believe our estimated available cash for distribution for the twelve months ending December 31, 2012 will not be less than $121.0 million. This amount of estimated minimum available cash for distribution is approximately $55.2 million, or approximately 84%, more than the unaudited pro forma available cash for distribution for the fiscal year ended September 30, 2010, and approximately $47.6 million, or approximately 65%, more than the unaudited pro forma available cash for distribution for the twelve month period ended June 30, 2011. Substantially all of this increase in available cash for distribution is attributable to additional storage and transportation capacity we recently acquired or expect to place into service and for which we have secured contracts for substantially all incremental capacity, as described below. Our estimates do not assume any incremental revenue, expenses or other costs associated with potential future acquisitions.

 

While the assumptions disclosed in this prospectus are not all-inclusive, the assumptions listed are those that we believe are significant to our forecasted results of operations and any discussions not discussed below were not deemed significant. We believe our actual results of operations will approximate those reflected in our forecast, but we can give no assurance that our forecasted results, including without limitation, the anticipated in service dates of our growth projects, will be achieved.

 

In addition to our existing businesses, the forecast of our results of operations for the twelve months ending December 31, 2012, assumes and reflects:

 

   

construction of the MARC I pipeline, a fully contracted natural gas transmission pipeline with 550 MMcf/d of interstate transportation service, which we expect to complete and place into service in July 2012 with contracts extending to 2022. The MARC I pipeline is expected to contribute approximately $16.8 million of available cash for distribution;

 

   

completion of our North/South expansion project, which involves the installation of additional compression facilities that will enable us to provide approximately 325 MMcf/d of interstate transportation service on a fully contracted basis, which we expect to complete and place into service in late October 2011 with contracts extending to 2016. The North/South expansion project is expected to contribute approximately $12.7 million of available cash for distribution;

 

   

development of a 2.1 million barrel NGL storage facility located near Watkins Glen, New York, which is approximately 95% contracted and which we expect to complete and place into service in June 2012 with a contract extending to 2016. The Watkins Glen NGL storage facility is expected to contribute approximately $3.7 million of available cash for distribution; and

 

   

the impact of our acquisition of our Seneca Lake natural gas storage facility in July 2011. The acquisition of Seneca Lake is expected to contribute approximately $9.6 million of available cash for distribution. Seneca Lake is supported by long-term firm storage contracts for approximately 0.9 Bcf of storage capacity and long-term firm transportation contracts for capacity on the pipelines acquired with

 

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this facility. In addition to the contracts currently in place, we expect to lease approximately 0.6 Bcf of the remaining capacity currently available at rates comparable to those currently charged at the facility. We plan to expand the facility by an additional 0.6 Bcf of working gas storage capacity, which we expect to complete and place into service by December 2012; however, given the expected timing and size of the expansion, these revenues are not material to our forecasted cash available for distribution.

 

For additional information related to our significant growth projects, including capital expenditures and their scheduled completion and in-service dates, please read “Business—Our Growth Projects.”

 

Revenue

 

We estimate that our total revenues for the twelve months ending December 31, 2012 will be approximately $158.7 million, as compared to approximately $94.7 million and $105.9 million for the fiscal year ended September 30, 2010, and the twelve months ended June 30, 2011, respectively. Our forecast is based primarily on the following assumptions:

 

Firm Storage

 

We estimate that approximately 66%, or approximately $104.7 million, of our total revenue will be generated from firm storage services. This compares to approximately 85%, or approximately $81.0 million, of our total revenues that were generated from firm storage revenues during the fiscal year ended September 30, 2010, and approximately 85%, or approximately $89.7 million, of our total revenues that were generated from firm storage revenues during the twelve months ended June 30, 2011. Furthermore, we have assumed that:

 

Natural Gas

 

   

Firm natural gas storage revenue is forecast to be approximately $87.1 million as compared to approximately $73.1 million and approximately $80.6 million provided in the fiscal year ended September 30, 2010 and the twelve months ended June 30, 2011, respectively. The increase of approximately $14.0 million in revenue as compared to the fiscal year ended September 30, 2010 is primarily the result of the increase in our storage capacity from the acquisition of the Seneca Lake natural gas storage facility and the full fiscal year results from firm storage revenue at the Thomas Corners natural gas storage facility, which was not reflected in the historical period. The $6.5 million increase in revenue as compared to the twelve months ended June 30, 2011 is primarily the result of the increase in our firm storage capacity from the acquisition of the Seneca Lake natural gas storage facility.

 

   

approximately 73%, or approximately $76.9 million, of our total firm storage revenue covering 31.3 Bcf of working gas storage capacity will be generated from firm storage services provided under contracts in existence as of September 30, 2011, that expire after the forecast period; and

 

   

approximately 10%, or approximately $10.2 million, of our total firm storage revenue is expected to be generated from firm storage contracts covering approximately 5.3 Bcf of working gas capacity entered into or renewed during the forecast period, including the 1.2 Bcf of additional capacity of which 0.6 Bcf is currently operational at our Seneca Lake natural gas storage facility. This compares to 0.6 Bcf and 14.3 Bcf of storage capacity which we have re-contracted at rates substantially similar to historical rates in the fiscal year ended September 30, 2010 and the twelve months ended June 30, 2011, respectively. We have assumed we will earn storage rates under new and renewed contracts that are consistent with rates under new contracts and contract extensions over the last 12 months.

 

NGL

 

   

approximately 17%, or approximately $17.6 million, of our total firm storage revenue will be generated from NGL storage services provided under contracts in existence as of September 30, 2011, that expire after the forecast period, including (a) approximately 1.5 million barrels, or 100%, of the operationally

 

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available capacity at our Bath storage facility, and (b) two million barrels of storage at our 2.1 million barrel Watkins Glen facility under development, which we expect to place into service on June 1, 2012. This compares to approximately $7.9 million and approximately $9.0 million of storage revenue generated from firm NGL storage services provided for the fiscal year ended September 30, 2010 and the twelve months ended June 30, 2011, respectively. Approximately $4.5 million of the increase in revenue for the forecast period as compared to the historical periods is attributable to the introduction of new capacity at the Watkins Glen facility and the remaining increase in the period is driven by an increase in contracted rates at the Bath storage facility.

 

Transportation

 

We estimate that approximately 27%, or approximately $42.5 million, of our total revenue will be generated from firm transportation services. This compares to approximately 13%, or approximately $12.1 million, of our total revenues that were generated from transportation revenues during the fiscal year ended September 30, 2010, and approximately 12%, or approximately $12.5 million, of our total revenues that were generated from transportation revenues during the twelve months ended June 30, 2011. Our historical transportation revenue is primarily attributable to the capacity we contracted for on TGP’s interstate natural gas pipeline and then released to our natural gas storage customers. Our estimate for the forecast period assumes a significant increase in firm wheeling and transportation service revenue resulting from the completion and placement into service of our North/South Project and MARC I pipeline, as well as the operation of our intrastate pipeline located in New York that we purchased in July 2011, as discussed below. This increase in revenue is offset by a decline of approximately $7.8 million and $8.2 million as compared to the fiscal year ended September 30, 2010 and the twelve months ended June 30, 2011, respectively, due to our decision to reduce the capacity contracted and released on the TGP interstate natural gas pipeline from 490 MMcf/d to 90 MMcf/d beginning January 2012. Furthermore, we have assumed that:

 

   

approximately 34%, or approximately $14.2 million, of our total transportation revenue will be generated from services provided under binding agreements covering 325 MMcf of interstate wheeling capacity, commencing November 1, 2011;

 

   

approximately 45%, or approximately $19.3 million, of our total transportation revenue will be generated from services provided under binding agreements covering 550 MMcf of interstate transportation capacity over the MARC I pipeline, commencing July 1, 2012; and

 

   

approximately 11%, or approximately $4.6 million, of our total transportation revenue will be generated from services provided under a binding agreement covering 30 MMcf of intrastate firm transportation capacity throughout calendar year 2012.

 

Hub Services

 

We estimate that approximately 7%, or approximately $11.5 million, of our total revenue will be generated from natural gas hub services. This compares to approximately 2%, or approximately $1.6 million, of our total revenues that were generated from hub services revenues during the fiscal year ended September 30, 2010, and approximately 3%, or approximately $3.7 million, of our total revenues that were generated from hub services revenues during the twelve months ended June 30, 2011. The increase in hub services revenue is primarily driven by our expectation that we will transport more interruptible wheeling volume for shippers desiring to move gas between TGP’s 300 Line, the Millennium Pipeline and intermediate points on our Stagecoach laterals, and to a lesser extent from improved interconnectivity resulting from projects placed into service in 2011 and 2012.

 

Cost of Services Sold

 

Our cost of services sold consists primarily of utility and fuel expenses and the costs to obtain transportation capacity on certain interstate pipelines. We estimate that our cost of services sold will be approximately $11.8 million for the twelve months ending December 31, 2012, as compared to approximately $12.0 million and $14.2 million for the fiscal year ended September 30, 2010, and the twelve months ended June 30, 2011, respectively.

 

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The decrease in our cost of services sold is attributable to our decision to reduce the transportation capacity we contracted for on the TGP interstate pipeline from 490 MMcf/d to 90 MMcf/d beginning January 2012, offset partially by an increase in utility and fuel expenses due to placing into service 825 MMcf/d of new transportation capacity and the acquisition of the Seneca Lake natural gas storage facility.

 

Operating and Administrative Expenses

 

We estimate that operating and administrative expenses will be approximately $22.7 million for the twelve months ending December 31, 2012, as compared to approximately $15.0 million and $13.8 million for the fiscal year ended September 30, 2010 and the twelve months ended June 30, 2011, respectively. The estimated operating and administrative expenses includes approximately $5.5 million from incremental expenses that we expect we will incur to support our expansion projects and the July 2011 Seneca Lake acquisition, plus approximately $3.0 million in incremental administrative expenses we will incur as a result of becoming a publicly traded partnership. In connection with the closing of this offering, the board of directors of our general partner may grant awards to our key employees and our outside directors pursuant to our long-term incentive plan; however, the board has not yet made any determination as to the number of awards, the type of awards or when the awards would be granted. Therefore, we have assumed no additional equity compensation expense in our forecast. Certain of our key employees hold grants under NRGY’s long-term incentive plan. Please read “Certain Relationships and Related Party Transactions—Agreements with Affiliates in Connection with the Transactions—Omnibus Agreement.”

 

Depreciation and Amortization

 

We estimate that depreciation and amortization expense will be approximately $54.3 million for the twelve months ending December 31, 2012, as compared to approximately $36.2 million and $36.8 million for the fiscal year ended September 30, 2010 and the twelve months ended June 30, 2011, respectively. Depreciation expense is expected to increase for the twelve months ending December 31, 2012, compared to the fiscal year ended September 30, 2010, and the twelve months ended June 30, 2011, due to the recent Seneca Lake acquisition and the expansion projects we expect to place into service in 2011 and 2012.

 

Capital Expenditures

 

We estimate that total capital expenditures for the twelve months ending December 31, 2012, will be $178.1 million. This forecast is based on the following assumptions:

 

   

Our estimated maintenance capital expenditures will be $2.0 million for the twelve months ending December 31, 2012, as compared to actual maintenance capital expenditures of approximately $0.3 million and $2.5 million for the fiscal year ended September 30, 2010 and the twelve months ended June 30, 2011, respectively. Our maintenance capital expenditures in the forecast period are relatively low in comparison to the size of our asset base because our storage and transportation assets and related equipment are relatively new. We expect to fund maintenance capital expenditures from cash generated by our operations.

 

   

Our expansion capital expenditures will be approximately $176.1 million for the twelve months ending December 31, 2012, as compared to expansion capital expenditures incurred of approximately $49.5 million and $73.0 million for the fiscal year ended September 30, 2010, and the twelve months ended June 30, 2011, respectively. Capital expenditures related to our MARC I pipeline, North/South expansion project and proposed NGL storage facility in Watkins Glen of approximately $27.2 million and $66.7 million were incurred for the fiscal year ended September 30, 2010 and the twelve months ended June 30, 2011, respectively. We expect to incur in the aggregate an additional $95.6 million related to these projects between June 30, 2011 and December 31, 2011. The $176.1 million of expansion capital expenditures anticipated to be spent during the forecast period are related to the MARC I pipeline and the NGL storage facility being developed at Watkins Glen, New York. We expect to fund our expansion capital expenditures with borrowings under our revolving credit facility.

 

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Financing

 

We estimate that interest expense will be approximately $2.8 million, net of $3.7 million in capitalized interest for the twelve months ending December 31, 2012. Our interest expense for the forecast period is based on the following assumptions:

 

   

through December 31, 2012, we expect to fund our expansion capital expenditures primarily under our revolving credit facility, with an estimated weighted-average rate of 3.5%. This rate is based on a forecast of LIBOR rates during the period plus the margin and the anticipated commitment fees of 0.375% for the unused portion of our revolving credit facility;

 

   

our re-borrowing of $80 million under our revolving credit facility to fund a distribution to NRGY for reimbursement of capital expenditures associated with our assets; and

 

   

interest expense also includes the amortization of debt issuance costs of $         million incurred in connection with our revolving credit facility.

 

Regulatory, Industry and Economic Factors

 

The forecast of our results of operations for the twelve months ending December 31, 2012 incorporates assumptions that (i) there will not be any new federal, state or local regulations or any new interpretations of existing regulations, that would materially impact our or our customers’ operations, and (ii) there will not be any major adverse economic changes in the portions of the energy industry in which we operate, or in general economic conditions, that would be materially adverse to our business during the forecast period.

 

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PROVISIONS OF OUR PARTNERSHIP AGREEMENT RELATING TO CASH DISTRIBUTIONS

 

Set forth below is a summary of the significant provisions of our partnership agreement that relate to cash distributions.

 

Distributions of Available Cash

 

General

 

Our partnership agreement requires that, within 45 days after the end of each quarter, beginning with the quarter ending December 31, 2011, we distribute all of our available cash to common unitholders of record on the applicable record date. We will adjust the initial quarterly distribution for the period from the closing of this offering through December 31, 2011.

 

Definition of Available Cash

 

Available cash, for any quarter, consists of all cash and cash equivalents on hand at the end of that quarter:

 

   

less, the amount of cash reserves established by our general partner 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 our common unitholders for any one or more of the next four quarters;

 

   

plus, if our general partner so determines, all or a portion of 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.

 

The purpose and effect of the last bullet point above is to allow our general partner, if it so decides, to use cash from working capital borrowings made after the end of the quarter but on or before the date of determination of available cash for that quarter to pay distributions to common unitholders. Under our partnership agreement, working capital borrowings are borrowings that are made under a credit agreement, commercial paper facility or similar financing arrangement, and in all cases are used solely for working capital purposes or to pay distributions to partners and with the intent of the borrower to repay such borrowings within twelve months from sources other than additional working capital borrowings.

 

Intent to Distribute the Initial Quarterly Distribution

 

We intend to distribute to the holders of common units on a quarterly basis at least the initial quarterly distribution of $          per unit, or $          per unit on an annualized basis, to the extent we have sufficient cash from our operations after establishment of cash reserves and payment of fees and expenses, including payments to our general partner and its affiliates. However, there is no guarantee that we will pay the initial quarterly distribution on the common units in any quarter. Even if our cash distribution policy is not modified or revoked, the amount of distributions paid under our policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement.

 

General Partner Interest

 

Our general partner will not be entitled to distributions on its non-economic general partner interest.

 

Incentive Distribution Rights

 

NRGY will hold incentive distribution rights that entitle it to receive 50.0% of the cash we distribute from operating surplus (as defined below) in excess of the initial quarterly distribution. Any such distribution would be in addition to any distributions that NRGY may receive on any common units that it owns.

 

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Operating Surplus and Capital Surplus

 

General

 

All cash distributed will be characterized as either “operating surplus” or “capital surplus.” Our partnership agreement requires that we distribute available cash from operating surplus differently than available cash from capital surplus.

 

Operating Surplus

 

We define operating surplus as:

 

   

$          million (as described below); plus

 

   

all of our cash receipts after the closing of this offering, excluding cash from interim capital transactions (as defined below under “—Capital Surplus”); plus

 

   

working capital borrowings made after the end of the period but on or before the date of determination of operating surplus for the period; plus

 

   

cash distributions paid in respect of equity issued (including incremental distributions on incentive distribution rights), other than equity issued in this offering, to finance all or a portion of expansion capital expenditures in respect of the period from such financing until the earlier to occur of the date the capital asset commences commercial service and the date that it is abandoned or disposed of; plus

 

   

cash distributions paid in respect of equity issued (including incremental distributions on incentive distribution rights), other than equity issued in this offering, to pay interest on debt incurred, or to pay distributions on equity issued, to finance the expansion capital expenditures referred to above, in each case, in respect of the period from such financing until the earlier to occur of the date the capital asset commences commercial service and the date that it is abandoned or disposed of; less

 

   

all of our operating expenditures (as defined below) after the closing of this offering; less

 

   

the amount of cash reserves established by our general partner to provide funds for future operating expenditures; less

 

   

all working capital borrowings not repaid within twelve months after having been incurred; less

 

   

any loss realized on disposition of an investment capital expenditure.

 

As described above, operating surplus does not reflect actual cash on hand that is available for distribution to our common unitholders and is not limited to cash generated by our operations. For example, it includes a basket of $          million that will enable us, if we choose, to distribute as operating surplus cash we receive in the future from non-operating sources such as asset sales, issuances of securities and long-term borrowings that would otherwise be distributed as capital surplus. In addition, the effect of including, as described above, certain cash distributions on equity interests in operating surplus will be to increase operating surplus by the amount of any such cash distributions. As a result, we may also distribute as operating surplus up to the amount of any such cash that we receive from non-operating sources.

 

The proceeds of working capital borrowings increase operating surplus and repayments of working capital borrowings are generally operating expenditures, as described below, and thus reduce operating surplus when made. However, if a working capital borrowing is not repaid during the twelve-month period following the borrowing, it will be deemed repaid at the end of such period, thus decreasing operating surplus at such time. When such working capital borrowing is in fact repaid, it will be excluded from operating expenditures because operating surplus will have been previously reduced by the deemed repayment.

 

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We define operating expenditures in the partnership agreement, and it generally means all of our cash expenditures, including, but not limited to, taxes, reimbursement of expenses to our general partner or its affiliates, payments made under interest rate hedge agreements or commodity hedge agreements (provided that (1) with respect to amounts paid in connection with the initial purchase of an interest rate hedge contract or a commodity hedge contract, such amounts will be amortized over the life of the applicable interest rate hedge contract or commodity hedge contract and (2) payments made in connection with the termination of any interest rate hedge contract or commodity hedge contract prior to the expiration of its stipulated settlement or termination date will be included in operating expenditures in equal quarterly installments over the remaining scheduled life of such interest rate hedge contract or commodity hedge contract), officer compensation, repayment of working capital borrowings, debt service payments and maintenance capital expenditures, provided that operating expenditures will not include:

 

   

repayment of working capital borrowings deducted from operating surplus pursuant to the penultimate bullet point of the definition of operating surplus above when such repayment actually occurs;

 

   

payments (including prepayments and prepayment penalties) of principal of and premium on indebtedness, other than working capital borrowings;

 

   

expansion capital expenditures;

 

   

investment capital expenditures;

 

   

payment of transaction expenses relating to interim capital transactions;

 

   

distributions to our partners (including distributions in respect of our incentive distribution rights); or

 

   

repurchases of equity interests except to fund obligations under employee benefit plans.

 

Capital Surplus

 

Capital surplus is defined in our partnership agreement as any distribution of available cash in excess of our operating surplus. Accordingly, capital surplus would generally be generated only by the following (which we refer to as “interim capital transactions”):

 

   

borrowings other than working capital borrowings;

 

   

sales of our equity and debt securities; and

 

   

sales or other dispositions of assets for cash, other than inventory, accounts receivable and other assets sold in the ordinary course of business or as part of normal retirement or replacement of assets.

 

Characterization of Cash Distributions

 

Our partnership agreement requires that we treat all available cash distributed as coming from operating surplus until the sum of all available cash distributed since the closing of this offering equals the operating surplus from the closing of this offering through the end of the quarter immediately preceding that distribution. Our partnership agreement requires that we treat any amount distributed in excess of operating surplus, regardless of its source, as capital surplus. As described above, operating surplus includes up to $         million, which does not reflect actual cash on hand that is available for distribution to our common unitholders. Rather, it is a provision that will enable us, if we choose, to distribute as operating surplus up to this amount of cash we receive in the future from interim capital transactions that would otherwise be distributed as capital surplus. We do not anticipate that we will make any distributions from capital surplus.

 

Capital Expenditures

 

Maintenance capital expenditures are those capital expenditures required to maintain our long-term operating capacity or revenues. Capital expenditures made solely for investment purposes will not be considered maintenance capital expenditures.

 

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Expansion capital expenditures are those capital expenditures that we expect will increase our operating capacity or revenues over the long term. Expansion capital expenditures will also include interest (and related fees) on debt incurred to finance all or any portion of the construction of such capital improvement in respect of the period that commences when we enter into a binding obligation to commence construction of a capital improvement and ending on the earlier to occur of the date any such capital improvement commences commercial service and the date that it is disposed of or abandoned. Capital expenditures made solely for investment purposes will not be considered expansion capital expenditures.

 

Investment capital expenditures are those capital expenditures that are neither maintenance capital expenditures nor expansion capital expenditures. Investment capital expenditures largely will consist of capital expenditures made for investment purposes. Examples of investment capital expenditures include traditional capital expenditures for investment purposes, such as purchases of securities, as well as other capital expenditures that might be made in lieu of such traditional investment capital expenditures, such as the acquisition of a capital asset for investment purposes or development of assets that are in excess of the maintenance of our existing operating capacity or revenues, but which are not expected to expand, for more than the short term, our operating capacity or revenues.

 

Neither investment capital expenditures nor expansion capital expenditures are included in operating expenditures, and thus will not reduce operating surplus. Because expansion capital expenditures include interest payments (and related fees) on debt incurred to finance all or a portion of the construction or improvement of a capital asset in respect of the period that begins when we enter into a binding obligation to commence construction of a capital improvement and ending on the earlier to occur of the date any such capital asset commences commercial service and the date that it is abandoned or disposed of, such interest payments also do not reduce operating surplus. Losses on disposition of an investment capital expenditure will reduce operating surplus when realized and cash receipts from an investment capital expenditure will be treated as a cash receipt for purposes of calculating operating surplus only to the extent the cash receipt is a return on principal.

 

Capital expenditures that are made in part for maintenance capital purposes, investment capital purposes and/or expansion capital purposes will be allocated as maintenance capital expenditures, investment capital expenditures or expansion capital expenditures by our general partner.

 

Distributions of Available Cash from Operating Surplus

 

Our partnership agreement requires that we make distributions of available cash from operating surplus for any quarter in the following manner:

 

   

first, 100.0% to all common unitholders, pro rata, until we distribute for each common unit an amount equal to the initial quarterly distribution for that quarter; and

 

   

thereafter, 50.0% to all common unitholders, pro rata, and 50.0% to NRGY in respect of the incentive distribution rights. Please read “—Incentive Distribution Rights” below.

 

The preceding discussion is based on the assumption that we do not issue additional classes of equity interests.

 

General Partner Interest

 

Our partnership agreement provides that our general partner will not be entitled to distributions that we make prior to our liquidation on its non-economic general partner interest.

 

Incentive Distribution Rights

 

Incentive distribution rights represent the right to receive 50% of quarterly distributions of available cash from operating surplus after the initial quarterly distribution has been achieved. Upon the closing of this offering, NRGY will hold all of our incentive distribution rights and may transfer these rights without the consent of our common unitholders.

 

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Percentage Allocations of Available Cash from Operating Surplus

 

The following table illustrates the percentage allocations of available cash from operating surplus between the common unitholders and IDR holders based on the quarterly distribution level. The amounts set forth under “Marginal Percentage Interest in Distributions” are the percentage interests of the common unitholders and IDR holders in any available cash from operating surplus we distribute up to and including the corresponding amount in the column “Total Quarterly Distribution Per Common Unit.” The percentage interests shown for our common unitholders and IDR Holders for the initial quarterly distribution are also applicable to quarterly distribution amounts that are less than the initial quarterly distribution.

 

            Marginal Percentage
Interest in Distributions
 
     Total Quarterly  Distribution
Per Common Unit
     Common
Unitholders
    IDR Holders  

Initial Quarterly Distribution

     $        100.0       

Thereafter

     above $        50.0     50.0

 

NRGY’s Right to Reset Incentive Distribution Level

 

NRGY, as the initial holder of our incentive distribution rights, has the right under our 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 initial quarterly distribution amount (upon which the incentive distribution payments to NRGY would be set). If NRGY transfers all or a portion of our incentive distribution rights in the future, then the holder or holders of a majority of our incentive distribution rights will be entitled to exercise this right. The following discussion assumes that NRGY holds all of the incentive distribution rights at the time that a reset election is made. The right to reset the initial quarterly distribution may be exercised, without approval of our common unitholders or the conflicts committee of the board of directors of our general partner, at any time when we have made cash distributions to the holders of the incentive distribution rights for the prior fiscal quarter. The reset initial quarterly distribution will be higher than the initial quarterly distribution prior to the reset such that there will be no incentive distributions paid under the reset initial quarterly distribution until cash distributions per unit following this event increase as described below.

 

In connection with the resetting of the initial quarterly distribution and the corresponding relinquishment by NRGY of incentive distribution payments based on the initial quarterly distribution prior to the reset, NRGY will be entitled to receive a number of newly issued common units based on a predetermined formula described below that takes into account the “cash parity” value of the cash distribution related to the incentive distribution rights received by NRGY for the quarter prior to the reset event as compared to the cash distribution per common unit for the prior quarter.

 

The number of common units that NRGY would be entitled to receive from us in connection with a resetting of the initial quarterly distribution then in effect would be equal to the quotient determined by dividing (x) the amount of cash distributions received by NRGY in respect of its incentive distribution rights for the quarter prior to the date of such reset election by (y) the amount of cash distributed per common unit for such quarter.

 

Following a reset election, the initial quarterly distribution amount 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 initial quarterly distribution”) such that we would distribute all of our available cash from operating surplus for each quarter thereafter as follows:

 

   

first, 100.0% to all common unitholders, pro rata, until each common unitholder receives an amount per unit equal to 150.0% of the reset initial quarterly distribution for that quarter; and

 

   

thereafter, 50.0% to all common unitholders, pro rata, and 50.0% to NRGY in respect of the incentive distribution rights.

 

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The following table illustrates the percentage allocation of available cash from operating surplus between the common unitholders and IDR holders (1) pursuant to the cash distribution provisions of our partnership agreement in effect at the closing of this offering, as well as (2) following a hypothetical reset of the initial quarterly distribution based on the assumption that the quarterly cash distribution amount per common unit for the quarter preceding the reset election was $            .

 

     Quarterly Distribution Per
Common Unit Prior to Reset
     Common
Unitholders
    IDR
Holders
    Quarterly Distribution Per Unit
Following Hypothetical Reset
 

Initial quarterly distribution

   $          100.0          $          (1) 

Thereafter

   above $          50.0     50.0   above $          (1)

 

(1)   This amount is 150% of the hypothetical reset initial quarterly distribution.

 

The following table illustrates the total amount of available cash from operating surplus that would be distributed to the common unitholders and IDR holders in respect of incentive distribution rights based on the amount distributed for the quarter prior to the reset. The table assumes that immediately prior to the reset there would be              common units outstanding and the distribution to each common unit would be $          per quarter for the quarter prior to the reset.

 

          Cash
Distributions
to Common
Unitholders
Prior to Reset
    Cash Distributions to IDR Holders Prior to Reset  
    Quarterly Distribution Per
Unit Prior to Reset
      Common
Units
    Incentive
Distribution
Rights
    Total     Total
Distributions
 

Initial quarterly distribution

  $       $        $        $        $        $     

Thereafter

  above $              
   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
    $           $           $           $           $        
   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

The following table illustrates the total amount of available cash from operating surplus that would be distributed to the common unitholders and IDR holders in respect of incentive distribution rights with respect to the quarter in which the reset occurs. The table reflects that as a result of the reset there would be         common units outstanding and the distribution to each common unit would be $            . The number of common units to be issued to IDR holders upon the reset was calculated by dividing (1) the amount received by IDR holders in respect of incentive distribution rights for the quarter prior to the reset as shown in the table above, or $         million, by (2) the average available cash distributed on each common unit for the quarter prior to the reset as shown in the table above, or $            .

 

     Quarterly Distribution Per
Unit After Reset
     Cash
Distributions
to Common
Unitholders
After Reset
     Cash Distributions to IDR Holders After Reset  
           Common
Units
     Incentive
Distribution
Rights
     Total      Total
Distributions
 

Initial quarterly distribution

   $        $         $         $         $         $     

Thereafter

   above $                   
     

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 
      $            $            $            $            $        
     

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

NRGY, as the initial holder of all of the incentive distribution rights, will be entitled to cause the initial quarterly distribution amount to be reset on more than one occasion.

 

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Distributions from Capital Surplus

 

How Distributions from Capital Surplus Will Be Made

 

Our partnership agreement requires that we make distributions of available cash from capital surplus, if any, in the following manner:

 

   

first, 100.0% to all common unitholders, pro rata, until we distribute for each common unit that was issued in this offering, an amount of available cash from capital surplus equal to the initial public offering price; and

 

   

thereafter, we will make all distributions of available cash from capital surplus as if they were from operating surplus.

 

The preceding paragraph assumes that we do not issue additional classes of equity interests.

 

Effect of a Distribution from Capital Surplus

 

Our partnership agreement treats a distribution of capital surplus as the repayment of the initial unit price from this initial public offering, which is a return of capital. The initial public offering price less any distributions of capital surplus per unit is referred to as the “unrecovered initial unit price.” Each time a distribution of capital surplus is made, the initial quarterly distribution will be reduced in the same proportion as the corresponding reduction in the unrecovered initial unit price. Because distributions of capital surplus will reduce the initial quarterly distribution after any of these distributions are made, it may be easier for NRGY to receive incentive distributions. However, any distribution of capital surplus before the unrecovered initial unit price is reduced to zero cannot be applied to the payment of the initial quarterly distribution.

 

Once we distribute capital surplus on a common unit issued in this offering in an amount equal to the initial unit price, our partnership agreement specifies that the initial quarterly distribution will be reduced to zero. Our partnership agreement specifies that we then make all future distributions from operating surplus, with 50.0% being paid to the holders of common units and 50.0% to IDR holders.

 

Adjustment to the Initial Quarterly Distribution

 

In addition to adjusting the initial quarterly distribution to reflect a distribution of capital surplus, if we combine our common units into fewer common units or subdivide our common units into a greater number of common units, our partnership agreement specifies that the following items will be proportionately adjusted:

 

   

the initial quarterly distribution; and

 

   

the unrecovered initial unit price.

 

For example, if a two-for-one split of the common units should occur, the initial quarterly distribution and the unrecovered initial unit price would each be reduced to 50.0% of its initial level. Our partnership agreement provides that we do not make any adjustment by reason of the issuance of additional units for cash or property.

 

In addition, if legislation is enacted or if existing law is modified or interpreted by a governmental taxing authority, so that we become taxable as a corporation or otherwise subject to taxation as an entity for federal, state or local income tax purposes, our partnership agreement specifies that the initial quarterly distribution for each quarter may, in the sole discretion of the general partner, be reduced by multiplying each distribution level by a fraction, the numerator of which is available cash for that quarter and the denominator of which is the sum of available cash for that quarter plus our general partner’s estimate of our aggregate liability for the quarter for such income taxes payable by reason of such legislation or interpretation. To the extent that the actual tax liability differs from the estimated tax liability for any quarter, the difference will be accounted for in subsequent quarters.

 

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Distributions of Cash Upon Liquidation

 

General

 

If we dissolve in accordance with the partnership agreement, we will sell or otherwise dispose of our assets in a process called liquidation. We will first apply the proceeds of liquidation to the payment of our creditors. We will distribute any remaining proceeds to the common unitholders and the IDR holders, in accordance with their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation.

 

Manner of Adjustments for Gain

 

The manner of the adjustment for gain is set forth in the partnership agreement. We will generally allocate any gain to the partners in the following manner:

 

   

first, 100.0% to the common unitholders, pro rata, until the capital account for each common unit is equal to the sum of: (1) the unrecovered initial unit price and (2) the amount of the initial quarterly distribution for the quarter during which our liquidation occurs; and

 

   

thereafter, 50.0% to the common unitholders, pro rata, and 50.0% to IDR holders.

 

Manner of Adjustments for Losses

 

We will generally allocate any loss to the partners in the following manner:

 

   

first, 50.0% to common unitholders, pro rata, and 50.0% to IDR holders, until the capital accounts of the IDR holders has been reduced to zero; and

 

   

thereafter, 100.0% to common unitholders, pro rata.

 

Adjustments to Capital Accounts

 

Our partnership agreement requires that we make adjustments to capital accounts upon the issuance of additional units. In this regard, our partnership agreement specifies that we allocate any unrealized and, for U.S. federal income tax purposes, unrecognized gain or loss resulting from the adjustments to the common unitholders and IDR holders in the same manner as we allocate gain or loss upon liquidation. In the event that we make positive adjustments to the capital accounts upon the issuance of additional units, our partnership agreement requires that we generally allocate any later negative adjustments to the capital accounts resulting from the issuance of additional units or upon our liquidation in a manner which results, to the extent possible, in the partners’ capital account balances equaling the amount which they would have been if no earlier positive adjustments to the capital accounts had been made.

 

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SELECTED HISTORICAL AND PRO FORMA FINANCIAL AND OPERATING DATA

 

The following table presents our selected historical financial and operating data and selected pro forma financial data as of the dates and for the periods indicated. The selected historical financial data presented as of September 30, 2006, 2007 and 2008 and June 30, 2010 and for the fiscal years ended September 30, 2006 and 2007 are derived from our unaudited historical consolidated financial statements, which are not included in this prospectus. The selected historical financial data presented as of September 30, 2009 and 2010 and for the fiscal years ended September 30, 2008, 2009 and 2010 are derived from our audited historical consolidated financial statements that are included elsewhere in this prospectus. The selected historical financial data presented as of June 30, 2011 and for the nine months ended June 30, 2010 and 2011 are derived from our unaudited historical consolidated financial statements that are included elsewhere in this prospectus. The selected historical financial and operating data and selected pro forma financial data as of the dates and for the periods indicated below are derived from the financial statements of Inergy Midstream, LLC and its subsidiaries, excluding Tres Palacios Gas Storage LLC and US Salt, which will be transferred to NRGY in connection with the closing of this offering and are not reflected in the presentation of our financial statements.

 

The selected pro forma financial data presented for the fiscal year ended September 30, 2010 and as of and for the nine months ended June 30, 2011 are derived from our unaudited pro forma condensed consolidated financial statements included elsewhere in this prospectus. Our unaudited pro forma condensed consolidated financial statements give pro forma effect to:

 

   

the change in our organizational structure from a limited liability company to a limited partnership;

 

   

the extinguishment of all indebtedness that we owe to a subsidiary of NRGY, which will be treated as a capital contribution by NRGY to us and which was approximately $121.5 million as of August 31, 2011;

 

   

our assumption from NRGY of $         million of indebtedness under a $         million revolving credit facility of which we will repay $         million from the net proceeds of this offering;

 

   

our re-borrowing of $80 million under our revolving credit facility to fund a distribution to NRGY for reimbursement of capital expenditures associated with our assets;

 

   

the issuance by us to NRGY of              common units and all of our incentive distribution rights;

 

   

the issuance by us to our general partner of a non-economic general partner interest in us; and

 

   

the issuance by us to the public of              common units and the use of the net proceeds from this offering as described under “Use of Proceeds.”

 

The unaudited pro forma balance sheet data assume the events listed above occurred as of June 30, 2011. The unaudited pro forma statement of operations data for the fiscal year ended September 30, 2010 assume the events listed above occurred as of October 1, 2009 and for the nine months ended June 30, 2011 assume the events listed above occurred as of October 1, 2010. We have not given pro forma effect to incremental external administrative expenses of approximately $3.0 million that we expect to incur annually as a result of being a publicly traded partnership. These incremental expenses include, costs associated with SEC reporting requirements, including annual and quarterly reports to common unitholders, tax return and Schedule K-1 preparation and distribution, independent auditor fees, investor relations activities, Sarbanes-Oxley Act compliance, NYSE listing, registrar and transfer agent fees, director and officer liability insurance costs, and director compensation. In future periods, the board of directors of our general partner may grant awards to our key employees and our outside directors pursuant to our long-term incentive plan; however, the board has not yet made any determination as to the number of awards or when the awards would be granted. Such incremental administrative expenses are not reflected in our historical and pro forma financial statements.

 

For a detailed discussion of the selected historical financial information contained in the following table, including factors impacting the comparability of information in the table, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” The following table should also be read in conjunction with “Use of Proceeds” and our audited historical consolidated financial statements and our unaudited pro forma condensed consolidated financial statements included elsewhere in this prospectus. Among other things, the historical and unaudited pro forma condensed consolidated financial statements include more detailed information regarding the basis of presentation for the information in the following table.

 

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The following table presents a non-GAAP financial measure, Adjusted EBITDA, which we use in our business as it is an important supplemental measure of our performance and liquidity. Adjusted EBITDA is not calculated or presented in accordance with GAAP. We explain this measure under “—Non-GAAP Financial Measures” and reconcile it to its most directly comparable financial measures calculated and presented in accordance with GAAP.

 

                                              Pro Forma  
    Year Ended September 30,     Nine Months Ended
June 30,
    Year
Ended
September 30,
    Nine Months
Ended
June 30,
 
    2006     2007     2008     2009     2010     2010     2011     2010     2011  
    ($ in millions)  

Statement of operations data:

                 

Revenue

  $ 42.2      $ 56.2      $ 82.7      $ 87.5      $ 94.7      $ 69.1      $ 80.3      $ 94.7      $ 80.3   

Cost of services sold (excluding depreciation and amortization as shown below):

    16.3        14.4        12.4        17.8        12.0        9.7        11.9        12.0        11.9   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Gross profit

    25.9        41.8        70.3        69.7        82.7        59.4        68.4        82.7        68.4   

Expenses:

                 

Operating and administrative

    5.6        6.6        11.7        10.8        15.0        11.3        10.1        15.0        10.1   

Depreciation and amortization

    11.5        16.4        24.5        29.2        36.2        26.7        27.3        36.2        27.3   

(Gain) loss on disposal of assets

    (0.3     0.2        (1.9            0.9        0.9               0.9          
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating income

    9.1        18.6        36.0        29.7        30.6        20.5        31.0        30.6        31.0   

Interest expense, net

    0.3                                                  1.3        1.0   

Other income

                  0.8               0.8                      0.8          
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income

    8.8        18.6        36.8        29.7        31.4        20.5        31.0        30.1        30.0   

Net income attributable to non-controlling partners

                  1.4        1.4        0.8        0.8               0.8          
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income attributable to member/partners

  $ 8.8      $ 18.6      $ 35.4      $ 28.3      $ 30.6      $ 19.7      $ 31.0      $ 29.3      $ 30.0   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Balance sheet data (at end of period):

                 

Total assets

  $ 250.2      $ 371.3      $ 480.8      $ 561.0      $ 559.5      $ 560.5      $ 607.3        $ 607.3   

Total debt

                  10.9        8.3               6.3                 80.0   

Member’s/partners’ capital

    227.5        311.1        384.8        414.3        444.8        434.0        475.9          519.6   

Other financial data:

                 

Adjusted EBITDA

  $ 20.4      $ 35.3      $ 57.7      $ 57.7      $ 70.4      $ 49.2      $ 59.2      $ 70.4      $ 59.2   

Maintenance capital expenditures

    0.2        0.1        0.2               0.3        0.3        2.5       

Net cash provided by operating activities

    13.1        34.3        62.9        59.5        83.5        56.8        65.2       

Net cash used in investing activities

    (16.6     (103.4     (108.9     (74.1     (49.8     (38.4     (64.1    

Net cash provided by (used in) financing activities

    4.3        68.2        48.9        15.3        (37.3     (20.0     8.3       

Operating data:

                 

Natural gas storage capacity (Bcf)

    13.6        26.3        32.5        32.5        39.5        39.5        39.5       

% of revenue generated from firm contracts

    95     91     98     96     98     98     96    

 

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Non-GAAP Financial Measures

 

For a discussion of the non-GAAP financial measures EBITDA and Adjusted EBITDA, please read “Summary—Non-GAAP Financial Measures.” The following table presents a reconciliation of EBITDA and Adjusted EBITDA to their most directly comparable GAAP financial measures, on a historical basis and pro forma basis, as applicable, for each of the periods indicated.

 

                                              Pro Forma  
    Year Ended
September 30,
    Nine Months
Ended
June 30,
    Year Ended
September 30,
    Nine
Months
Ended
June 30,
 
    2006     2007     2008     2009     2010     2010     2011     2010     2011  
    ($ in millions)  

Reconciliation of net income to EBITDA and Adjusted EBITDA:

                 

Net income

  $ 8.8      $ 18.6      $ 36.8      $ 29.7      $ 31.4      $ 20.5      $ 31.0      $ 30.1      $ 30.0   

Depreciation and amortization

    11.5        16.4        24.5        29.2        36.2        26.7        27.3        36.2        27.3   

Interest expense, net

    0.3                                                  1.3        1.0   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

EBITDA

  $ 20.6      $ 35.0      $ 61.3      $ 58.9      $ 67.6      $ 47.2      $ 58.3      $ 67.6      $ 58.3   

Long-term incentive and equity compensation expense

    0.1        0.1        0.5        0.7        2.7        2.0        0.9        2.7        0.9   

(Gain) loss on disposal of assets

    (0.3     0.2        (1.9            0.9        0.9               0.9          

Transaction costs

                                0.2        0.1               0.2          

Net income attributable to non-controlling partners

                  (1.4     (1.4     (0.8     (0.8            (0.8       

Interest of non-controlling partners in consolidated ITDA(a)

                  (0.8     (0.5     (0.2     (0.2            (0.2       
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Adjusted EBITDA

  $ 20.4      $ 35.3      $ 57.7      $ 57.7      $ 70.4      $ 49.2      $ 59.2      $ 70.4      $ 59.2   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Reconciliation of net cash provided by operating activities to EBITDA and Adjusted EBITDA:

                 

Net cash provided by operating activities

  $ 13.1      $ 34.3      $ 62.9      $ 59.5      $ 83.5      $ 56.8      $ 65.2       

Net changes in working capital balances

    6.9        0.9        (3.5     (0.6     (15.0     (8.7     (6.9    

Interest expense, net

    0.3                                                 

Gain (loss) on disposal of assets

    0.3        (0.2     1.9               (0.9     (0.9           
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

     

EBITDA

  $ 20.6      $ 35.0      $ 61.3      $ 58.9      $ 67.6      $ 47.2      $ 58.3       

Long-term incentive and equity compensation expense

    0.1        0.1        0.5        0.7        2.7        2.0        0.9       

(Gain) loss on disposal of assets

    (0.3     0.2        (1.9            0.9        0.9              

Transaction costs

                                0.2        0.1              

Interest of non-controlling partners in consolidated EBITDA

                  (2.2     (1.9     (1.0     (1.0           
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

     

Adjusted EBITDA

  $ 20.4      $ 35.3      $ 57.7      $ 57.7      $ 70.4      $ 49.2      $ 59.2       
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

     

 

(a)   Interest, tax, depreciation and amortization expense attributable to non-controlling partners.

 

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MANAGEMENT’S DISCUSSION AND ANALYSIS

OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

 

You should read the following discussion of the historical financial condition and results of operations in conjunction with our historical consolidated financial statements and accompanying notes and our unaudited pro forma condensed consolidated financial statements included elsewhere in this prospectus. In addition, this discussion includes forward-looking statements that are subject to risks and uncertainties that may result in actual results differing from statements we make. Please read “Forward-Looking Statements.” Factors that could cause actual results to differ include those risks and uncertainties that are discussed in “Risk Factors.

 

Overview

 

We are a fee-based, growth-oriented Delaware limited partnership formed by NRGY to own, operate, develop and acquire midstream energy assets. Our current asset base consists of natural gas and NGL storage and transportation assets located in the Northeast region of the United States. We own and operate four natural gas storage facilities located in New York and Pennsylvania that have an aggregate working gas storage capacity of 41.0 Bcf with high peak injection and withdrawal capabilities. We also own natural gas pipelines located in New York and Pennsylvania with 30 MMcf/d of intrastate transportation capacity and, upon completion of two pipeline projects that are currently under development, we will own 875 MMcf/d of interstate transportation capacity. In addition, we own and operate a 1.5 million barrel NGL storage facility located near Bath, New York. Our near-term strategy is to continue to develop a platform of interconnected natural gas assets that can be operated as an integrated Northeast storage and transportation hub.

 

Our business has expanded rapidly through internal growth initiatives and acquisitions since its inception in 2005. We have grown our natural gas storage capacity from 13.0 Bcf as of September 30, 2005 to 41.0 Bcf as of September 30, 2011, which does not include 38.4 Bcf of natural gas storage capacity owned by NRGY on the Texas Gulf Coast. We believe that our current asset base enables us to significantly expand our storage and transportation capacity through continued investment in attractive growth projects. We expect these growth projects will further increase connectivity among our natural gas facilities and with third-party pipelines, thereby resulting in increased demand for our services.

 

Our significant growth projects include:

 

   

construction of the MARC I pipeline, a fully contracted natural gas transmission pipeline with 550 MMcf/d of interstate transportation service, which we expect to complete and place into service in July 2012 with contracts extending to 2022;

 

   

completion of our North/South expansion project, which involves the installation of additional compression facilities that will enable us to provide approximately 325 MMcf/d of interstate transportation service on a fully contracted basis, which we expect to complete and place into service in late October 2011 with contracts extending to 2016;

 

   

development of a 2.1 million barrel NGL storage facility located near Watkins Glen, New York, which is approximately 95% contracted and which we expect to complete and place into service by June 2012 with a contract extending to 2016; and

 

   

expansion of our Seneca Lake natural gas storage facility by an additional 0.6 Bcf of working gas storage capacity, which we expect to complete and place into service by December 2012.

 

Through our current assets, growth projects and potential acquisitions from NRGY and third parties, we believe we are well-positioned to benefit from the anticipated long-term growth in demand for natural gas and NGL storage and transportation services in the United States.

 

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How We Generate Revenue

 

We generate revenue in our natural gas storage business almost exclusively through the provision of fee-based natural gas storage services to our customers. As of September 30, 2011, the aggregate storage capacity of our natural gas storage facilities was approximately 95% contracted under fixed reservation fee agreements. Our storage rates are regulated under FERC rate-making policies, which currently permit us to charge market-based rates for storage services at our Stagecoach, Thomas Corners and Seneca Lake facilities. Market-based rate authority for storage services allows us to negotiate rates with customers based on market demand. Our Steuben facility provides services at cost-based rates; however, we intend to file an application with the FERC by the end of calendar year 2011 to allow us to charge market-based rates at our Steuben facility.

 

We generate transportation revenue by providing fee-based transportation services to our customers. Our transportation services and rates have been authorized by the FERC or, if applicable, the New York State Public Service Commission, or NYPSC. The transportation services authorized under, or requested for authorization under, our FERC tariffs for the MARC I pipeline and for the North/South expansion project will be provided to our customers at negotiated rates subject to cost-of-service recourse rate options. Negotiated-rate authority for transportation services allows us to negotiate rates with customers based on market demand.

 

We provide NGL storage and related terminaling services at our Bath storage facility under market rates. We make cavern storage space available for a fixed monthly reservation fee that must be paid regardless of customer usage. We provide loading and unloading services and receive fees for such services.

 

Factors That Impact Our Business

 

A substantial majority of our revenues is derived from fixed reservation fees under multi-year contracts with a diverse portfolio of customers. We believe this contract structure and customer mix provides stability to our cash flow profile and substantially mitigates the risk to us of significant negative cash flow fluctuations caused by changing supply and demand conditions and other market factors. We also believe that the strategic location of our assets in a high demand region significantly increases our ability to maintain the high percentage of earnings from fixed fees under multi-year contracts. We believe the current infrastructure for storage and transportation capacity in our market will continue to be undersupplied.

 

We believe the key factors that impact our business are (i) the anticipated long-term supply and demand for natural gas and NGLs in the markets we serve, which determine the amount of volatility in natural gas and NGL prices and drive month-to-month differentials in the forward curve for natural gas prices; (ii) our ability to capitalize on internal growth projects; (iii) the needs of our customers and the competitiveness of our service offerings; and (iv) government regulation, including our ability to obtain the permits required to build new infrastructure. These factors, discussed in more detail below, play an important role in how we evaluate our operations and implement our long-term strategies.

 

Supply and Demand for Natural Gas and NGLs

 

To effectively manage our business, we monitor our market areas for both short- and long-term changes in natural gas and NGL supply and demand and the relative adequacy of existing and planned storage and transportation infrastructure to meet these changing needs. In general, any imbalance that exists between supply and demand, whether long-term, seasonal or intermittent for either natural gas or NGLs, should support demand for storage services. We expect that demand for our storage services will increase during periods of supply and demand imbalances.

 

In addition, any factors that contribute to more frequent and severe imbalances between supply and demand, whether caused by supply or demand fluctuations, should increase volatility, inter-month differentials in natural gas and NGL prices and the need for and value of storage services. Because our facilities, in most instances,

 

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connect supply (from local production or other pipelines) to storage and storage is connected to demand (either local industrial demand or other market-bound pipelines) through our transportation assets, any increase in either supply or demand should facilitate growth in our transportation business. Our storage and transportation services allow our customers to manage imbalances in supply and demand throughout the markets we serve. As changes in supply and demand dynamics take place, we attempt to adjust our service offerings in terms of price, duration, operating flexibility and other factors to meet the needs of our customers, in each case subject to any regulatory constraints or limitations (which, in the case of our natural gas storage and transportation services, are contained in FERC-approved tariffs).

 

Internal Growth Opportunities

 

Our current asset base enables us to significantly expand storage capacity and improve our facilities’ connectivity through continued investment in attractive growth projects. Our significant growth projects include (i) increasing transportation functionality and interconnectivity through our MARC I pipeline and North/South expansion project, which we also believe will facilitate greater interconnectivity between our natural gas storage assets in general, (ii) increasing NGL storage capacity by developing up to five million barrels of incremental NGL storage at our proposed Watkins Glen facility and (iii) adding 0.6 Bcf of natural gas storage capacity at our Seneca Lake facility. Consistent with our past practice, we began development of these projects after entering into binding agreements. Our capital budget supports ongoing growth initiatives that leverage the market positioning of our existing facilities and management’s experience in the storage and transportation business. We anticipate that these projects will allow us to better serve our customers’ storage and transportation needs, increase margins, enhance our ability to obtain contracts for the use of our assets and increase our interconnectivity to multiple pipelines, thereby reducing our dependence on any one or more third-party pipelines.

 

Customers

 

We store natural gas and NGLs and transport natural gas for a broad mix of customers, such as utilities (LDCs and electric utilities), marketers, producers, industrial users, pipelines and refiners. Utilities normally require a secure and reliable supply of natural gas over a sustained period of time to meet the needs of their customers. Frequently, utilities will enter into long-term firm storage and transportation contracts to ensure both a ready supply of natural gas and sufficient transportation capacity over the life of the contract. Marketers that generate income from buying and selling natural gas or NGLs use our services to capitalize on price differentials over time or between markets. Demand for our services from marketers typically increases with price volatility.

 

We continuously monitor the evolving needs of our customers, current and forecasted market conditions, and the competitiveness of our service offerings in order to maintain the proper balance between optimizing near-term earnings and cash flow and positioning our business for sustainable long-term growth.

 

Regulation

 

Government regulation, particularly regulation of natural gas storage and transportation assets, can have a significant impact on our business. For example, the permitting processes at all government levels, including the FERC, impact our ability to obtain the approvals and permits required to construct new infrastructure. These processes are increasingly impacted by political, environmental and other concerns that can significantly delay or increase the cost of obtaining the approvals and permits required to expand our operations. Other federal, state and local regulation can also impact our operations, cost structure and profitability, which could in turn impact our financial performance and our ability to make distributions to our common unitholders. As a result, we closely monitor regulatory developments affecting our business.

 

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Future Trends and Outlook

 

We expect our business to continue to be affected by several trends, including key trends described below. Our expectations are based on assumptions made by us and information currently available to us. If our underlying assumptions prove to be incorrect, actual results may vary materially from our expected results. Please read “Risk Factors.”

 

Growing Natural Gas Demand

 

Natural gas is a significant component of energy consumption in the United States. According to the U.S. Energy Information Administration, or EIA, natural gas consumption accounted for approximately 24% of all energy used in the United States in 2010, representing 24 Tcf of natural gas. The EIA estimates that over the next 27 years, total domestic energy consumption will increase by over 15%, with natural gas consumption directly benefiting from population growth, growth in cleaner-burning natural gas-fired electric generation and natural gas vehicles. We believe increasing demand for natural gas will drive the demand for additional natural gas storage and transportation infrastructure, particularly in high-demand markets like the Northeast.

 

Increasing Natural Gas Supply

 

We believe there will be ample supplies of natural gas for the foreseeable future from a combination of domestic production and pipeline imports. We also believe that forecast increases in domestic shale gas production, including local production from the Marcellus and Utica shale plays, will continue to drive demand for storage and transportation infrastructure as producers attempt to deliver shale gas and NGLs to demand markets.

 

Growth Opportunities

 

We expect to expand our storage and transportation capacity in the future. In addition, we will selectively pursue strategic acquisitions from NRGY or third parties that complement our existing asset base or provide attractive potential returns in new areas within our geographic footprint. However NRGY is entitled under the omnibus agreement to review and has the first option on any third-party acquisition opportunities and is under no obligation to make acquisition opportunities available to us. NRGY’s retained midstream business and expansion opportunities are of strategic interest to us and would complement our existing asset base by diversifying our cash flow sources. While NRGY is not obligated to sell these assets to or jointly develop them with us, NRGY’s significant ownership interest provides a strong incentive to support our growth. NRGY is also not restricted from competing with us and 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.

 

Our long-term strategy includes operating qualifying income producing midstream assets, including natural gas and NGL storage and transportation assets, throughout North America. We believe that we will be well positioned to acquire assets from third parties should such opportunities arise, and identifying and executing acquisitions will be a key part of our strategy.

 

Market Volatility

 

Our business can be positively or negatively affected by the widening or narrowing of seasonal spreads, extended periods of significant or little volatility and economic expansions or downturns. Volatility in natural gas prices is primarily caused by supply and demand imbalances. Historically, natural gas price volatility has been particularly pronounced in the Northeast region of the United States. Because the Northeast region is less proximate to natural gas supply, sharp increases in demand can cause larger increases in price volatility relative to markets that are closer to greater amounts of natural gas supply.

 

Barriers to Entry

 

Although competition within the midstream industry is robust, significant barriers to entry exist in the natural gas and NGL storage and transportation businesses. In particular, there is a scarcity of unexploited

 

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reservoirs located near pipeline infrastructure, natural gas and NGL supply sources and end-user markets that have the capacity necessary to store natural gas and NGLs economically. Operational challenges and high upfront capital costs associated with the development of natural gas and NGL storage and transportation assets also exist. They include obtaining title to land and permits to operate, constructing facilities for injecting, storing and withdrawing natural gas and NGLs and meeting high cushion gas requirements. Moreover, significant industry skills are required to identify, construct and operate successful natural gas and NGL infrastructure, and many of these skills are uncommon.

 

Supply of Storage Capacity

 

An important factor in determining the value of storage and therefore the rates we are able to charge for new contracts or contract renewals is whether a surplus or shortfall of storage capacity exists relative to the overall demand for storage services in a given market area. In general, in the markets like the Northeast where we believe storage is in short supply, storage values will be higher on a relative basis than in regions that are oversupplied with storage capacity. The extent to which markets are undersupplied or oversupplied will fluctuate in response to significant variations in natural gas and NGL supply and demand. We believe the current infrastructure for storage and transportation capacity in our market will continue to be undersupplied.

 

Increased Costs as a Result of Being a Public Entity

 

As a result of being a publicly-traded limited partnership, we will incur incremental administrative expenses that are not reflected in our historical financial statements. These costs include costs associated with annual and quarterly reports to common unitholders, tax return and Schedule K-1 preparation and distribution, independent auditor fees, Sarbanes-Oxley compliance, NYSE listing, investor relations activities, registrar and transfer agent fees, director and officer liability insurance costs and director compensation. We expect our incremental administrative expenses associated with being a publicly-traded limited partnership to total approximately $3.0 million per year.

 

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 deliverability sold;

 

   

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

 

   

our operating and administrative expenses; and

 

   

our 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.

 

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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 physical capacity or deliverability sold under firm storage contracts:

 

Storage Facility

   Percentage Contractually
Committed
    Weighted-Average
Maturity
(Year)
 

Stagecoach (Natural Gas)

     95     2015   

Thomas Corners (Natural Gas)

     100     2015   

Seneca Lake (Natural Gas)(1)

     59     2018   

Steuben (Natural Gas)

     100     2013   

Bath (NGL)(2)

     100     2016   

 

(1)   We did not acquire Seneca Lake until July 2011 and are currently in the process of leasing out the remaining storage capacity at the facility.
(2)   We have contracted 100% of the operationally available storage capacity at our Bath storage facility to Inergy Propane. Please read “Certain Relationships and Related Party Transactions—Agreements with Affiliates in Connection with the Transactions.”

 

Transportation Contracts

 

Our New York intrastate pipeline that we acquired in July 2011, together with our MARC I pipeline and North/South expansion project when completed, 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 100% contracted and committed.

 

Operating and Administrative Expenses

 

Operating and administrative expenses consist primarily of vehicle costs, including fuel, repair and maintenance costs, and wages. 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. Our timing of expenditures may fluctuate with planned maintenance activities that take place during off-peak periods. Changes in regulation may also impact our expenditures. Additionally, fluctuations in project development costs are impacted by the level of development activity during a period. Following this offering, we expect our operating and administrative expenses will increase substantially as a result of 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 expenses, transaction costs and interest of non-controlling partners. 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.

 

Results of Operations

 

Nine Months Ended June 30, 2011 Compared to Nine Months Ended June 30, 2010

 

The following table summarizes the consolidated statement of operations components for the nine months ended June 30, 2011 and 2010, respectively (in millions):

 

     Nine Months Ended
June 30,
     Change  
     2011      2010      In Dollars     Percentage  

Revenue

   $ 80.3       $ 69.1       $ 11.2        16.2

Cost of services sold

     11.9         9.7         2.2        22.7   
  

 

 

    

 

 

    

 

 

   

Gross profit

     68.4         59.4         9.0        15.2   

Operating and administrative expenses

     10.1         11.3         (1.2     (10.6

Depreciation and amortization

     27.3         26.7         0.6        2.2   

Loss on disposal of assets

             0.9         (0.9     *   
  

 

 

    

 

 

    

 

 

   

Operating income

     31.0         20.5         10.5        51.2   

Net income attributable to non-controlling partners

             0.8         (0.8     *   
  

 

 

    

 

 

    

 

 

   

Net income attributable to member/partners

   $     31.0       $     19.7       $     11.3        57.4
  

 

 

    

 

 

    

 

 

   

 

 

 

 

*   Not meaningful

 

Revenue. Revenues for the nine months ended June 30, 2011, were $80.3 million, an increase of $11.2 million, or 16.2%, from $69.1 million during the same nine-month period in 2010.

 

Revenues from firm storage were $67.3 million for the nine months ended June 30, 2011, an increase of $8.7 million, or 14.8%, from $58.6 million during the same nine-month period in 2010. Natural gas firm storage revenues increased $7.5 million primarily due to the commencement of Thomas Corners storage contracts in April 2010. NGL revenues increased $1.2 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 $9.5 million for the nine months ended June 30, 2011, an increase of $0.4 million, or 4.4%, from $9.1 million during the same nine-month period in 2010. This increase resulted primarily from a change in rates charged for transportation.

 

Revenues from hub services were $3.5 million for the nine months ended June 30, 2011, an increase of $2.1 million, or 150.0%, from $1.4 million during the same nine-month period in 2010. This increase resulted from an increase in interruptible services at our Stagecoach facility due to an increase in demand for interruptible wheeling service as a result of customer demand to move gas to/from our interconnecting pipes primarily due to natural gas development in Pennsylvania.

 

Cost of Services Sold. Cost of services sold for the nine months ended June 30, 2011, was $11.9 million, an increase of $2.2 million, or 22.7%, from $9.7 million during the same nine-month period in 2010.

 

Storage cost of services sold was $6.8 million for the nine months ended June 30, 2011, an increase of $2.2 million, or 47.8%, from $4.6 million during the same nine-month period in 2010. Natural gas storage cost increased $1.0 million and NGL storage cost increased $1.2 million. The increase in natural gas storage cost was primarily due to an increase in compression costs during the current period due to the rental of certain temporary compressors at our Stagecoach facility as a result of an operational loss of certain compression functionality during the nine months ended June 30, 2011. NGL storage cost of services sold increased $1.2 million due to a decrease in 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 cost of services sold was $5.1 million for the nine months ended June 30, 2011 and 2010. Transportation cost of services sold is primarily comprised of fixed costs for leasing transportation capacity on a non-affiliated interconnecting pipe.

 

Our storage cost of services sold consists primarily of direct costs to run the storage facilities, including electricity, contractor and fuel costs. Our transportation cost of services sold consists of our costs to procure firm transportation capacity on certain pipelines. These costs are offset by any fuel-in-kind collections made during the period. Other costs incurred with these services are included in operating and administrative expense and depreciation and amortization expense and consist primarily of depreciation, vehicle costs, including fuel, repair and maintenance costs, and wages. Depreciation expense for storage amounted to $24.9 million and $23.9 million for the nine months ended June 30, 2011 and 2010, respectively. Vehicle costs and wages amounted to $1.5 million and $1.2 million for the nine months ended June 30, 2011 and 2010, respectively. Because we include these costs in our operating and administrative expense and depreciation and amortization expense rather than in cost of services sold, our gross profit may not be comparable to other entities in our lines of business if they include these costs in cost of services sold.

 

Gross Profit. Gross profit for the nine months ended June 30, 2011, was $68.4 million, an increase of $9.0 million, or 15.2%, from $59.4 million during the same nine-month period in 2010.

 

Storage gross profit was $64.0 million for the nine months ended June 30, 2011, compared to $55.4 million during the same nine-month period in 2010, an increase of $8.6 million, or 15.5%. Natural gas storage gross profit increased $8.6 million primarily due to the commencement of Thomas Corners storage contracts in April 2010. NGL storage gross profit was consistent with the prior period primarily due to an increase in the storage rates charged to customers at our Bath storage facility, offset by a decrease in fuel-in-kind collections as a result of the change in the contractual arrangement. Storage gross profit consists of firm storage and hub services.

 

Transportation gross profit was $4.4 million for the nine months ended June 30, 2011, compared to $4.0 million during the same nine-month period in 2010, an increase of $0.4 million, or 10.0%.

 

Operating and Administrative Expenses. Operating and administrative expenses were $10.1 million for the nine months ended June 30, 2011, compared to $11.3 million during the same nine-month period in 2010. This $1.2 million, or 10.6%, decrease in operating expenses was comprised predominantly of a reduction in corporate allocation of overhead due primarily to a reduction from the prior year of the amount of long-term incentive and equity compensation.

 

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Depreciation and Amortization. Depreciation and amortization increased to $27.3 million for the nine months ended June 30, 2011, from $26.7 million during the same nine-month period in 2010. This $0.6 million, or 2.2%, increase resulted primarily from placing Thomas Corners into service in November 2009.

 

Loss on Disposal of Assets. Loss on disposal of assets was $0.9 million during the nine months ended June 30, 2010. The loss recognized during the 2010 period resulted from the abandonment of a development project. There was no such loss during the same nine-month period in 2011.

 

Net Income Attributable to Non-Controlling Partners. We acquired a majority interest (approximately 55%) in the operations of Steuben Gas 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, and in each of April 2010 and July 2010, we acquired an additional 10% interest in Steuben Gas. These acquisitions gave us 100% ownership of Steuben Gas.

 

Net Income Attributable to Member/Partners. Net income for the nine months ended June 30, 2011 was $31.0 million compared to net income of $19.7 million during the same nine-month period in 2010. The $11.3 million, or 57.4%, increase in net income was primarily attributable to higher gross profit discussed above.

 

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

 

     Nine Months Ended
June 30,
 
     2011      2010  

EBITDA:

     

Net income

   $ 31.0       $ 20.5   

Depreciation and amortization

     27.3         26.7   
  

 

 

    

 

 

 

EBITDA(1)

   $ 58.3       $ 47.2   
  

 

 

    

 

 

 

Long-term incentive and equity compensation expense

     0.9         2.0   

Loss on disposal of assets

             0.9   

Transaction costs

             0.1   

Net income attributable to non-controlling partners

             (0.8

Interest of non-controlling partners in consolidated ITDA(a)

             (0.2
  

 

 

    

 

 

 

Adjusted EBITDA(1)

   $     59.2       $     49.2   
  

 

 

    

 

 

 

 

(a)   Interest, tax, depreciation and amortization expense attributable to non-controlling partners.

 

     Nine Months Ended
June 30,
 
     2011     2010  

EBITDA:

    

Net cash provided by operating activities

   $ 65.2      $ 56.8   

Net changes in working capital balances

     (6.9     (8.7

Loss on disposal of assets

            (0.9
  

 

 

   

 

 

 

EBITDA(1)

   $ 58.3      $ 47.2   
  

 

 

   

 

 

 

Long-term incentive and equity compensation expense

     0.9        2.0   

Loss on disposal of assets

            0.9   

Transaction costs

            0.1   

Interest of non-controlling partners in consolidated EBITDA

            (1.0
  

 

 

   

 

 

 

Adjusted EBITDA(1)

   $     59.2      $     49.2   
  

 

 

   

 

 

 

 

(1)   For the definitions of EBITDA and Adjusted EBITDA and a reconciliation to their most directly comparable GAAP financial measures, please read “Summary—Non-GAAP Financial Measures.”

 

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Fiscal Year Ended September 30, 2010 Compared to Fiscal Year Ended September 30, 2009

 

The following table summarizes the consolidated income statement components for the fiscal years ended September 30, 2010 and 2009, respectively (in millions):

 

     Year Ended
September 30,
     Change  
     2010      2009      In Dollars     Percentage  

Revenue

   $ 94.7       $ 87.5       $ 7.2        8.2

Cost of services sold

     12.0         17.8         (5.8     (32.6
  

 

 

    

 

 

    

 

 

   

Gross profit

     82.7         69.7         13.0        18.7   

Operating and administrative expenses

     15.0         10.8         4.2        38.9   

Depreciation and amortization

     36.2         29.2         7.0        24.0   

Loss on disposal of assets

     0.9                 0.9        *   
  

 

 

    

 

 

    

 

 

   

Operating income

     30.6         29.7         0.9        3.0   

Other income

     0.8                 0.8        *   
  

 

 

    

 

 

    

 

 

   

Net income

     31.4         29.7         1.7        5.7   

Net income attributable to non-controlling partners

     0.8         1.4         (0.6     (42.9
  

 

 

    

 

 

    

 

 

   

Net income attributable to member/partners

   $     30.6       $     28.3       $     2.3        8.1
  

 

 

    

 

 

    

 

 

   

 

 

 

 

*   Not meaningful

 

Revenue. Revenues in fiscal 2010 were $94.7 million, an increase of $7.2 million, or 8.2%, from $87.5 million in fiscal 2009.

 

Revenues from firm storage were $81.0 million in fiscal 2010, an increase of $8.9 million, or 12.3%, from $72.1 million in fiscal 2009. Natural gas firm storage contributed $8.2 million of the increase, primarily resulting from the in-servicing of our Thomas Corners facility and the related firm storage contracts. NGL revenues increased $0.7 million in fiscal 2010, primarily attributable to an increase in storage contracts with a related party.

 

Revenues from transportation were $12.1 million in fiscal 2010, a decrease of $0.1 million, or 0.8%, from $12.2 million in fiscal 2009.

 

Revenues from hub services were $1.6 million in fiscal 2010, a decrease of $1.6 million, or 50.0%, from $3.2 million in fiscal 2009. This decrease resulted from a decline in demand for interruptible services in the period.

 

Cost of Services Sold. Cost of services sold for fiscal 2010 was $12.0 million, a decrease of $5.8 million, or 32.6%, from $17.8 million in fiscal 2009.

 

Storage cost of services sold was $5.2 million, a decrease of $5.8 million, or 52.7%, from $11.0 million in fiscal 2009. Natural gas firm storage contributed $4.1 million of the decrease primarily due to lower compression costs at our Stagecoach facility. NGL storage cost of services sold decreased $1.7 million in fiscal 2010, primarily attributable to an increase in fuel-in-kind collections. Our fuel-in-kind collections during the 2010 period exceeded our cost of services sold. The fluctuation in compression costs and fuel-in-kind collections was primarily due to choices our customers made that were beyond our control. Customer injection and withdrawal decisions in a given year can have an impact on compression costs and fuel-in-kind collections. If our natural gas storage reservoirs are optimized in a way that allows for offsetting physical injections and withdrawals, compression expenses decrease and fuel-in-kind collections increase.

 

Transportation cost of services sold was $6.8 million in fiscal 2010 and 2009. Transportation cost of services sold is primarily comprised of fixed costs for leasing transportation capacity on a nonaffiliated interconnecting pipe.

 

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Our storage cost of services sold consists primarily of direct costs to run the storage facilities, including power, contractor and fuel costs. Our transportation cost of services sold consists of our costs to procure firm transportation capacity on certain pipelines. These costs are offset by any fuel-in-kind collections made during the period. Other costs incurred in conjunction with these services are included in operating and administrative expense and depreciation and amortization expense and consist primarily of depreciation, vehicle costs, including fuel, repair and maintenance costs, and wages. Depreciation expense for storage amounted to $32.2 million and $26.1 million for fiscal 2010 and 2009, respectively. Vehicle costs and wages amounted to $1.7 million and $1.4 million for fiscal 2010 and 2009, respectively. Because we include these costs in our operating and administrative expense and depreciation and amortization expense rather than in cost of services sold, our gross profit may not be comparable to other entities in our lines of business if they include these costs in cost of services sold.

 

Gross Profit. Gross profit for fiscal 2010 was $82.7 million, an increase of $13.0 million, or 18.7%, from $69.7 million during fiscal 2009.

 

Storage gross profit was $77.4 million in fiscal 2010 compared to $64.3 million in fiscal 2009, an increase of $13.1 million, or 20.4%. Natural gas storage gross profit increased $10.7 million primarily due to our Thomas Corners facility being placed into service and lower compression costs at our Stagecoach facility. NGL gross profit increased $2.4 million primarily attributable to an increase in fuel-in-kind collections. Storage gross profit consists of firm storage and hub services.

 

Transportation gross profit was $5.3 million in fiscal 2010, a decrease of $0.1 million, or 1.9%, from $5.4 million in fiscal 2009.

 

Operating and Administrative Expenses. Operating and administrative expenses were $15.0 million in fiscal 2010 compared to $10.8 million in fiscal 2009. This $4.2 million, or 38.9%, increase in operating expenses was primarily attributable to an increase from the prior year in the amount of long-term incentive and equity compensation.

 

Depreciation and Amortization. Depreciation and amortization increased to $36.2 million in fiscal 2010 from $29.2 million in fiscal 2009. This $7.0 million, or 24.0%, increase resulted primarily from placing our Thomas Corners facility into service.

 

Loss on Disposal of Assets. Loss on disposal of assets increased to $0.9 million in fiscal 2010. There was no loss on disposal of assets in fiscal 2009. The loss recognized during fiscal 2010 resulted from the abandonment of a development project.

 

Net Income Attributable to Non-Controlling Partners. We acquired a majority interest (approximately 55%) in the operations of Steuben Gas 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 and in each of April 2010 and July 2010, we acquired an additional 10% interest in Steuben Gas. These acquisitions gave us 100% ownership of Steuben Gas.

 

Net Income Attributable to Member/Partners. Net income for fiscal 2010 was $30.6 million compared to net income for fiscal 2009 of $28.3 million. The $2.3 million, or 8.1%, increase in net income was primarily attributable to higher gross profit, partially offset by increased depreciation and amortization and operating and administrative expenses.

 

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EBITDA and Adjusted EBITDA. The following tables summarize EBITDA and Adjusted EBITDA for the fiscal years ended September 30, 2010 and 2009, respectively (in millions):

 

     Year Ended
September 30,
 
     2010     2009  

EBITDA:

    

Net income

   $ 31.4      $ 29.7   

Depreciation and amortization

     36.2        29.2   
  

 

 

   

 

 

 

EBITDA(1)

   $ 67.6      $ 58.9   
  

 

 

   

 

 

 

Long-term incentive and equity compensation expense

     2.7        0.7   

Loss on disposal of assets

     0.9          

Transaction costs

     0.2          

Net income attributable to non-controlling partners

     (0.8     (1.4

Interest of non-controlling partners in consolidated ITDA(a)

     (0.2     (0.5
  

 

 

   

 

 

 

Adjusted EBITDA(1)

   $     70.4      $     57.7   
  

 

 

   

 

 

 

 

(a)   Interest, tax, depreciation and amortization expense attributable to non-controlling partners.

 

     Year Ended
September 30,
 
     2010     2009  

EBITDA:

    

Net cash provided by operating activities

   $ 83.5      $ 59.5   

Net changes in working capital balances

     (15.0     (0.6

Loss on disposal of assets

     (0.9       
  

 

 

   

 

 

 

EBITDA(1)

   $ 67.6      $ 58.9   
  

 

 

   

 

 

 

Long-term incentive and equity compensation expense

     2.7        0.7   

Loss on disposal of assets

     0.9          

Transaction costs

     0.2          

Interest of non-controlling partners in consolidated EBITDA

     (1.0     (1.9
  

 

 

   

 

 

 

Adjusted EBITDA(1)

   $     70.4      $     57.7   
  

 

 

   

 

 

 

 

(1)   For the definitions of EBITDA and Adjusted EBITDA and a reconciliation to their most directly comparable GAAP financial measures, please read “Summary—Non-GAAP Financial Measures.”

 

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Fiscal Year Ended September 30, 2009 Compared to Fiscal Year Ended September 30, 2008

 

The following table summarizes the consolidated income statement components for the fiscal years ended September 30, 2009 and 2008, respectively (in millions):

 

     Year Ended
September 30,
     Change  
     2009      2008      In Dollars     Percentage  

Revenue

   $ 87.5       $ 82.7       $ 4.8        5.8

Cost of services sold

     17.8         12.4         5.4        43.5   
  

 

 

    

 

 

    

 

 

   

Gross profit

     69.7         70.3         (0.6     (0.9

Operating and administrative expenses

     10.8         11.7         (0.9     (7.7

Depreciation and amortization

     29.2         24.5         4.7        19.2   

Gain on disposal of assets

             1.9         (1.9     *   
  

 

 

    

 

 

    

 

 

   

Operating income

     29.7         36.0         (6.3     (17.5

Other income

             0.8         (0.8     *   
  

 

 

    

 

 

    

 

 

   

Net income

     29.7         36.8         (7.1     (19.3

Net income attributable to non-controlling partners

     1.4         1.4                  
  

 

 

    

 

 

    

 

 

   

Net income attributable to member/partners

   $ 28.3       $ 35.4       $ (7.1     (20.1 )% 
  

 

 

    

 

 

    

 

 

   

 

 

 

 

*   Not meaningful

 

Revenue. Revenues in fiscal 2009 were $87.5 million, an increase of $4.8 million, or 5.8%, from $82.7 million in fiscal 2008.

 

Revenues from firm storage were $72.1 million in fiscal 2009, an increase of $4.5 million, or 6.7%, from $67.6 million in fiscal 2008. Natural gas firm storage revenues increased $2.6 million primarily due to the commencement of operations on the Stagecoach north lateral connecting to the Millennium Pipeline in December 2008. NGL revenues increased $1.9 million primarily due to an increase in contractual rates at our Bath storage facility.

 

Revenues from transportation were $12.2 million in fiscal 2009, a decrease of $0.8 million, or 6.2%, from $13.0 million in fiscal 2008. This decrease was attributable to a both a decrease in rates and volumes.

 

Revenues from hub services were $3.2 million in fiscal 2009, an increase of $1.1 million, or 52.4%, from $2.1 million in fiscal 2008. This increase resulted from an increase in demand for interruptible services.

 

Cost of Services Sold. Cost of services sold for fiscal 2009 was $17.8 million, an increase of $5.4 million, or 43.5%, from $12.4 million in fiscal 2008.

 

Storage cost of services sold was $11.0 million, an increase of $8.0 million, or 266.7%, from $3.0 million in fiscal 2008. Natural gas storage cost of services increased $6.4 million primarily due an increase in compression cost at our Stagecoach facility. NGL cost of services increased $1.6 million primarily attributable to a decrease in fuel-in-kind collections and an increase in electricity costs. Fuel-in-kind collections during 2008 exceeded cost of services sold. The fluctuation in compression costs and fuel-in-kind collections was primarily due to choices our customers made that were beyond our control. Customer injection and withdrawal decisions in a given year can have an impact on compression costs and fuel-in-kind collections. If our natural gas storage reservoirs are optimized in a way that allows for offsetting physical injections and withdrawals, compression expenses decrease and fuel-in-kind collections increase.

 

Transportation cost of services sold was $6.8 million in fiscal 2009, a decrease of $2.6 million, or 27.7%, from $9.4 million in fiscal 2008. This decrease was related to a decline in both volumes and rates on our firm transportation secured on a major pipeline.

 

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Our storage cost of services sold consists primarily of direct costs to run the storage facilities, including electricity, contractor and fuel costs. Our transportation cost of services sold consists of our costs to procure firm transportation capacity on certain pipelines. These costs are offset by any fuel-in-kind collections made during the period. Other costs incurred in conjunction with these services are included in operating and administrative expense and depreciation and amortization expense and consist primarily of depreciation, vehicle costs, including fuel, repair and maintenance costs, and wages. Depreciation expense for storage amounted to $26.1 million and $21.1 million for fiscal 2009 and 2008, respectively. Vehicle costs and wages amounted to $1.4 million and $1.9 million for fiscal 2009 and 2008, respectively. Because we include these costs in our operating and administrative expense and depreciation and amortization expense rather than in cost of services sold, our gross profit may not be comparable to other entities in our lines of business if they include these costs in cost of services sold.

 

Gross Profit. Gross profit for fiscal 2009 was $69.7 million, a decrease of $0.6 million, or 0.9%, from $70.3 million during fiscal 2008.

 

Storage gross profit was $64.3 million in fiscal 2009 compared to $66.7 million in fiscal 2008, a decrease of $2.4 million, or 3.6%. Natural gas storage gross profit decreased $2.7 million primarily attributable to an increase in compression costs at our Stagecoach facility. NGL gross profit increased $0.3 million due to an increase in contractual rates offset by a decline in fuel-in-kind collections. Storage gross profit consists of firm storage and hub services.

 

Transportation gross profit was $5.4 million in fiscal 2009, an increase of $1.8 million, or 50.0%, from $3.6 million in fiscal 2008. This increase resulted from an increase in market demand for the transportation capacity we secured on a major pipeline.

 

Operating and Administrative Expenses. Operating and administrative expenses were $10.8 million in fiscal 2009 compared to $11.7 million in fiscal 2008. This $0.9 million, or 7.7%, decrease in operating expenses was due primarily to a decrease in long-term incentive and equity compensation.

 

Depreciation and Amortization. Depreciation and amortization increased to $29.2 million in fiscal 2009 from $24.5 million in fiscal 2008. This $4.7 million, or 19.2%, increase was primarily the result of placing into service an expansion project at our Stagecoach facility.

 

Gain on Disposal of Assets. Gain on disposal of assets decreased $1.9 million in fiscal 2009. The gain recognized in fiscal 2008 was due to the sale of base gas at our Stagecoach facility. No such gain was recognized in fiscal 2009.

 

Net Income Attributable to Non-controlling Partners. We acquired a majority interest in the operations of Steuben Gas when we acquired 100% of the membership interest in ASC in October 2007. ASC held a majority interest in the operations of Steuben Gas until July 2010.

 

Net Income Attributable to Member/Partners. Net income for fiscal 2009 was $28.3 million compared to net income for fiscal 2008 of $35.4 million. The $7.1 million, or 20.1%, decrease in net income is primarily attributable to higher depreciation and amortization partially offset by lower operating expenses in fiscal 2009.

 

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EBITDA and Adjusted EBITDA. The following tables summarize EBITDA and Adjusted EBITDA for the fiscal years ended September 30, 2009 and 2008, respectively (in millions):

 

     Year Ended
September 30,
 
     2009     2008  

EBITDA:

    

Net income

   $ 29.7      $ 36.8   

Depreciation and amortization

     29.2        24.5   
  

 

 

   

 

 

 

EBITDA(1)

   $ 58.9      $ 61.3   
  

 

 

   

 

 

 

Long-term incentive and equity compensation expense

     0.7        0.5   

(Gain) on disposal of assets

            (1.9

Net income attributable to non-controlling partners

     (1.4     (1.4

Interest of non-controlling partners in consolidated ITDA(a)

     (0.5     (0.8
  

 

 

   

 

 

 

Adjusted EBITDA(1)

   $ 57.7      $ 57.7   
  

 

 

   

 

 

 

 

(a)   Interest, tax, depreciation and amortization expense attributable to non-controlling partners.

 

     Year Ended
September 30,
 
     2009     2008  

EBITDA:

    

Net cash provided by operating activities

   $ 59.5      $ 62.9   

Net changes in working capital balances

     (0.6     (3.5

Gain on disposal of assets

            1.9   
  

 

 

   

 

 

 

EBITDA(1)

   $ 58.9      $ 61.3   
  

 

 

   

 

 

 

Long-term incentive and equity compensation expense

     0.7        0.5   

(Gain) on disposal of assets

            (1.9

Interest of non-controlling partners in consolidated EBITDA

     (1.9     (2.2
  

 

 

   

 

 

 

Adjusted EBITDA(1)

   $ 57.7      $ 57.7   
  

 

 

   

 

 

 

 

(1)   For the definitions of EBITDA and Adjusted EBITDA and a reconciliation to their most directly comparable GAAP financial measures, please read “Summary—Non-GAAP Financial Measures.”

 

Liquidity and Sources of Capital

 

Our operations, including capital expenditures and acquisitions, have historically been funded by NRGY. Our principal liquidity requirements are to finance current operations, fund capital expenditures, including acquisitions from time to time, and to service our debt. Subsequent to this offering, we expect our sources of liquidity from time to time to include cash generated from operations, borrowings under our revolving credit facility and issuances of debt and equity securities.

 

While we have historically received funding from our affiliates, we do not have any commitment with our general partner or other affiliates, including NRGY, to fund our cash flow deficits or provide other direct or indirect financial assistance to us following the closing of this offering. NRGY’s significant economic stake in us may, however, provide NRGY with a strong incentive to promote and support the successful execution of our growth plan and strategy, including by providing us with direct or indirect financial assistance. However, the indentures governing NRGY’s outstanding senior notes would substantially restrict the types, amounts and terms of any such assistance that NRGY might desire to provide us.

 

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In connection with this offering, we will assume approximately $         million of indebtedness from NRGY under a $         million revolving credit facility that will be assigned to us of which we will repay $         million using net proceeds of this offering. We believe we will be able to fund up to the first $         of internal growth projects or potential acquisitions primarily through borrowings under our revolving credit facility or through other sources described above.

 

Working capital, defined as the amount by which current assets exceed current liabilities, is an indication of our liquidity and potential need for short-term funding. Our working capital requirements are driven primarily by changes in accounts receivable and accounts payable. Our historical working capital balances are not necessarily indicative of the expected working capital balances going forward as they are not expected to be impacted by the historical treasury management arrangements with NRGY.

 

Historical Cash Flow Information

 

Nine Months Ended June 30, 2011 Compared to Nine Months Ended June 30, 2010

 

Net operating cash inflows were $65.2 million and $56.8 million for the nine-month periods ended June 30, 2011 and 2010, respectively. The $8.4 million increase in operating cash flows is primarily related to the commencement of Thomas Corners’ storage contracts in April 2010.

 

Net investing cash outflows were $64.1 million and $38.4 million for the nine-month periods ended June 30, 2011 and 2010, respectively. Net cash outflows were primarily impacted by a $25.7 million increase in purchases of property, plant and equipment.

 

Net financing cash inflows (outflows) were $8.3 million and $(20.0) million for the nine-month periods ended June 30, 2011 and 2010, respectively. The net change was primarily impacted by a net borrowing from NRGY in 2011 of $8.3 million compared to a net payment to NRGY of $17.4 million in 2010. As described above, NRGY historically funded our working capital and growth capital expansion initiatives. We historically paid NRGY all cash generated from operations.

 

Fiscal Year Ended September 30, 2010 Compared to Fiscal Year Ended September 30, 2009

 

Net operating cash inflows were $83.5 million and $59.5 million for the fiscal years ended September 30, 2010 and 2009, respectively. The $24.0 million increase in operating cash flows is primarily related to the in-servicing of our Thomas Corners facility in November 2009 and lower compression costs at our Stagecoach facility.

 

Net investing cash outflows were $49.8 million and $74.1 million for the fiscal years ended September 30, 2010 and 2009, respectively. Net cash outflows were primarily impacted by a $24.6 million decrease in purchases of property, plant and equipment.

 

Net financing cash inflows (outflows) were $(37.3) million and $15.3 million for the fiscal years ended September 30, 2010 and 2009, respectively. The net change was primarily impacted by a net payment to a related party in 2010 of $28.4 million compared to a net borrowing from a related party of $18.5 million in 2009. As described above, NRGY historically funded our working capital and growth capital expansion initiatives. We historically paid NRGY all cash generated from operations.

 

Fiscal Year Ended September 30, 2009 Compared to Fiscal Year Ended September 30, 2008

 

Net operating cash inflows were $59.5 million and $62.9 million for fiscal years ended September 30, 2009 and 2008, respectively. The $3.4 million decrease in operating cash flow was attributable to a $7.1 million decrease in net income and a $2.9 million decrease in operating assets and liabilities offset by a $6.6 million increase in non-cash charges to net income

 

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Net investing cash outflows were $74.1 million and $108.9 million for the fiscal years ended September 30, 2009 and 2008, respectively. Net cash outflows were primarily impacted by a $36.0 million decrease in cash outlays related to acquisitions and a $20.0 million decrease in purchases of property, plant and equipment, partially offset by a $21.6 million decrease in proceeds from the sale of assets.

 

Net financing cash inflows were $15.3 million and $48.9 million for the fiscal years ended September 30, 2009 and 2008, respectively. The net change was primarily impacted by a $34.8 million equity contribution made by NRGY in the fiscal year ended September 30, 2008.

 

Distributions to Our Common Unitholders and IDR Holders

 

Our partnership agreement requires us to distribute 100% of our available cash each quarter to the holders of our common units, until each common unit has received the initial quarterly distribution. Generally, our available cash is defined as our cash on hand at the end of the quarter less the establishment of cash reserves. We do not have a legal obligation to pay this distribution. Please read “Cash Distributions Policy and Restrictions on Distributions” and “Provisions of Our Partnership Agreement Relating to Cash Distributions.”

 

Upon completion of this offering, our general partner will establish an initial quarterly distribution of $        per common unit ($        per common unit on an annualized basis) to the extent we have sufficient cash after establishment of reserves and payment of fees and expenses, including payments to our general partner and its affiliates. For the first quarter that we are publicly traded, we will pay investors in this offering a prorated distribution covering the period from the completion of this offering through December 31, 2011, based on the actual length of that period. Our ability to pay the initial quarterly distribution is subject to various restrictions and other factors described in more detail under the caption “Cash Distribution Policy and Restrictions on Distributions.”

 

Our general partner will not be entitled to distributions on its non-economic general partner interest. NRGY currently holds incentive distribution rights that entitle it to receive 50.0% of the cash we distribute from operating surplus in excess of the initial quarterly distribution.

 

Capital Requirements

 

We are developing approximately $380 million in internal growth projects around our existing assets designed to enhance our profitability and increase our operating scale. Our growth plans currently include the MARC I pipeline, the North/South expansion project, the development of NGL storage at Watkins Glen, New York, and an expansion of our Seneca Lake facility. Please read “Business—Our Growth Projects.” Capital expenditures related to our MARC I pipeline, North/South expansion project and proposed NGL storage facility in Watkins Glen of approximately $27.2 million and $66.7 million were incurred for the fiscal year ended September 30, 2010 and the twelve months ended June 30, 2011, respectively. We expect to incur in the aggregate an additional $95.6 million related to these projects between June 30, 2011 and December 31, 2011. We expect to fund our capital expenditures with a combination of cash generated from operations, borrowings under our revolving credit facility and issuances of additional equity or debt.

 

Revolving Credit Facility

 

In connection with this offering, we will assume approximately $         million of indebtedness from NRGY under a $         million revolving credit facility, with an expected maturity date five years from the closing of this offering, that will be assigned to us of which we will repay $         million using net proceeds of this offering. We expect the revolving credit facility to be available to fund working capital and our internal growth projects, make acquisitions and for general partnership purposes. We expect to re-borrow $80 million under our revolving credit facility to fund a cash distribution to NRGY for reimbursement of capital expenditures associated with our assets. As a result, we expect to have approximately $         million of remaining capacity immediately after the closing of this offering, subject to compliance with any applicable covenants under such facility. We also expect to have an accordion feature that would allow us to increase the available borrowings under the facility by up to $         million, subject to the lenders agreeing to satisfy the increased commitment amounts under our new facility.

 

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We expect our revolving credit facility will restrict 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, our revolving credit facility will contain covenants requiring us to maintain certain financial ratios. We expect that borrowings under our revolving credit facility will be secured by liens on substantially all of our assets and guaranteed by our existing and future subsidiaries.

 

Potential Impact of Recent Economic and Financial Market Trends

 

Beginning in the second half of 2008, the United States and other industrialized countries experienced a significant economic downturn. Worldwide financial markets have continued to be extremely volatile. The outlook for a worldwide economic recovery in 2011 remains uncertain, and we will not be unaffected by challenging economic and capital markets conditions if market conditions deteriorate or the worldwide recovery does not continue or continues at a slower rate. In particular, while we believe that cash flow in excess of distributions as well as borrowings under our revolving credit facility will enable us to fund our planned expansion activities for the next several years, funding of additional expansion activities or acquisitions may require us to access additional capital resources, which we intend to fund with a balanced combination of equity and debt capital. Although we believe that equity and debt markets will be available to us on reasonable terms based on current market conditions, there can be no assurance that future market conditions will permit us to access capital to fund future acquisition and expansion activities.

 

Off-balance Sheet Arrangements

 

We do not have any off-balance sheet arrangements.

 

Contingencies

 

For a discussion of contingencies that may impact us, please read (i) Note 7 to our audited consolidated financial statements as of September 30, 2009 and 2010 and for the fiscal years ended September 30, 2008, 2009 and 2010 that are included elsewhere in this prospectus and (ii) Note 4 to our unaudited consolidated financial statements as of June 30, 2011 and for the nine months ended June 30, 2010 and 2011 that are included elsewhere in this prospectus.

 

Contractual Obligations

 

Our growth projects require us to enter into certain purchase commitments with certain vendors.

 

The following table summarizes our contractual obligations as of September 30, 2010 (in millions):

 

     Total      Less than
1 year
     1-3 years      4-5 years      After
5 years
 

Purchase commitments of identified growth projects(a)

     12.3         12.3                           
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total contractual obligations

   $ 12.3       $ 12.3       $       $       $   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(a)   Identified growth projects related to our MARC I pipeline, North/South expansion project and Watkins Glen NGL facility.

 

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Quantitative and Qualitative Disclosures About Market Risk

 

From time to time, we may use derivative instruments to (i) manage our exposure to interest rates or natural gas prices associated with future base gas purchases and (ii) economically hedge the intrinsic value of our natural gas storage facilities.

 

Commodity Price 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. NRGY has not historically engaged in material commodity hedging activities relating to the assets comprising our business. However, we may engage in commodity hedging activities in the future, particularly if we undertake growth projects or engage in acquisitions that expose us to direct commodity price risk.

 

Interest Rate Risk

 

Our operating and acquisition activities have historically been funded by NRGY. Interest has not historically been charged in the funding of these activities.

 

As described above, in connection with this offering, we expect to assume from NRGY a $         million revolving credit facility. We may or may not hedge portions of our borrowings under the revolving credit facility from time to time.

 

Recent Accounting Pronouncements

 

FASB Accounting Standards Codification Subtopic 810-10 (“Subtopic 810-10”), originally issued as SFAS No. 160, “Non-controlling Interests in Consolidated Financial Statements—an amendment of ARB No. 51”, was issued in December 2007 and requires that accounting and reporting for minority interests will be recharacterized as non-controlling interests and classified as a component of equity. Subtopic 810-10 also establishes reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the non-controlling owners. Subtopic 810-10 applies to all entities that prepare consolidated financial statements, except not-for-profit organizations, but will affect only those entities that have an outstanding non-controlling interest in one or more subsidiaries or that deconsolidate a subsidiary. We adopted Subtopic 810-10 on October 1, 2009. The adoption of Subtopic 810-10 did not have a material impact on our results of operations or financial position.

 

Critical Accounting Policies

 

Revenue Recognition. Revenue from storage and transportation contracts is recognized during the period in which the related services are provided.

 

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.

 

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We completed the valuation of each of our reporting units and determined no impairment existed as of September 30, 2010. 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.

 

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NATURAL GAS INDUSTRY

 

The midstream sector of the natural gas industry provides the link between the exploration and production of natural gas 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 currently focus on transportation and storage activities, for both natural gas and NGLs.

 

The natural gas pipeline grid transports natural gas from producing regions to customers, such as LDCs, electric generation facilities and industrial users. Interstate pipelines carry natural gas across state boundaries and are subject to FERC regulation on (i) the rates charged for their services, (ii) the terms and conditions of their services, and (iii) the location, construction and abandonment of their facilities. Intrastate pipelines transport natural gas within a particular state and are customarily not subject to FERC regulation.

 

Natural gas storage plays a vital role in maintaining the reliability of natural gas supplies needed to meet the demands of consumers. Storage facilities are utilized by pipelines to balance operations, by natural gas end users such as LDCs 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 months) and to withdraw natural gas during periods of high demand (typically colder winter months). The diagram below illustrates the position and function of natural gas storage and transportation within the natural gas market chain.

 

LOGO

 

Market Fundamentals

 

Natural Gas Demand

 

Natural gas is a significant component of energy consumption in the United States. According to the EIA, natural gas consumption accounted for approximately 24% of all energy used in the United States in 2010, representing 24 Tcf of natural gas. The EIA estimates that over the next 27 years, total domestic energy consumption will increase by over 15%, with natural gas consumption directly benefiting from population growth, growth in cleaner-burning natural gas-fired electric generation and natural gas vehicles.

 

Within the U.S. market, natural gas is primarily used as a fuel source for heating and cooking within the residential and commercial sectors (37%), electric generation (33%) and industrial markets (30%). Approximately 23% of the electricity generated in the United States is fueled by natural gas, while coal (45%), nuclear (20%) and other fuels (12%) comprise the remaining fuel sources. These market shares are reflected in the graphs below.

 

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LOGO

      LOGO  
     

 

Source: EIA, U.S. Natural Gas Consumption by End Use (June 2011) and Electric Power Annual 2009.

 

According to the EIA, as shown in the chart below, during the period from 2001 through 2010, natural gas consumption increased by 8.5% overall from an average of approximately 60.9 Bcf/d in 2001 to an average of approximately 66.1 Bcf/d in 2010. Although the change in consumption levels during this period was variable on a year-to-year basis, growth was highest in the seasonal and weather-sensitive electric power generation and commercial/residential sectors, where consumption grew by approximately 38.1% and 4.7%, respectively. The growth in these sectors was partially offset by an approximate 10.1% decline in natural gas consumption in the less seasonal industrial sector.

 

U.S. Annual & Average Daily Natural Gas Consumption

 

LOGO

 

Source: EIA, U.S. Natural Gas Consumption by End Use (June 2011).

 

Forecasts published by the EIA and other industry sources anticipate that long-term demand for natural gas will continue to grow, and that the historical trend of growth in natural gas demand from seasonal and weather-sensitive consumption sectors will continue. These forecasts are supported by various factors, including (i) expectations of continued growth in the U.S. gross domestic product, which has a significant influence on long-term growth in natural gas demand; (ii) an increased likelihood that regulatory and legislative initiatives regarding domestic carbon policy will drive greater demand for cleaner burning fuels like natural gas;

 

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(iii) increased acceptance of the view that natural gas is a clean and abundant domestic fuel source that can lead to greater energy independence for the United States by reducing its dependence on imported petroleum; (iv) the emergence of low-cost natural gas shale developments, which suggest ample supplies and which are expected to keep natural gas prices relatively low relative to crude oil prices, making the commodity attractive as a feedstock; and (v) continued growth in electricity generation from intermittent renewable energy sources, primarily wind and solar energy, for which natural-gas fired generation is a logical back-up power supply source. According to the EIA, natural gas consumption is expected to rise from 22.7 Tcf in 2009 to 26.5 Tcf in 2035.

 

Natural Gas Supply

 

Domestic natural gas consumption is today satisfied primarily by production from conventional onshore and offshore production in the lower 48 states, as supplemented by production from historically declining pipeline imports from Canada, imports of LNG from foreign sources, and some Alaska production. In order to maintain current levels of U.S. natural gas supply and to meet the projected increase in demand, new sources of domestic natural gas must continue to be developed to offset an established trend of depletion associated with mature, conventional production as well as the uncertainty of future LNG imports and infrastructure challenges associated with sourcing additional production from Alaska. Over the past several years, a fundamental shift in production has emerged with the contribution of natural gas from unconventional resources (defined by the EIA as natural gas produced from shale formations and coalbeds) increasing from 6% of total U.S. natural gas supply in 2000 to 16% in 2008. In fact, according to EIA data, during the three-year period from January 15, 2007 through December 15, 2010 domestic production of natural gas increased by an average of approximately 4% per annum, largely due to continued development of shale resources. The emergence of shale plays has resulted primarily from advances in horizontal drilling and hydraulic fracturing technologies, which have allowed producers to extract significant volumes of natural gas from these plays at cost-advantaged per unit economics versus most conventional plays.

 

The U.S. Geological Service, Mineral Management Service and EIA estimated that in 2010 the United States possessed over 2,600 Tcf of technically recoverable natural gas resources, an increase of approximately 30% from 2008 estimates of technically recoverable natural gas resources, which is primarily due to technological advancements. As the depletion of onshore conventional and offshore resources continues, natural gas from unconventional resource plays is forecast to fill the void and continue to gain market share from higher-cost sources of natural gas. Natural gas production from the major shale formations is forecast to provide the majority of the growth in unconventional natural gas supply, increasing to approximately 47% of total U.S. natural gas supply in 2035 as compared with 16% in 2009.

 

Natural Gas Production by Source, 1990-2035 (Tcf)

 

LOGO

 

Source: EIA, Annual Energy Outlook 2011 (April 2011).

 

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Market Imbalances

 

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.

 

Historical Natural Gas Supply and Demand

 

LOGO

 

Source: Derived from EIA, U.S. Natural Gas Summary (June 29, 2011).

 

Natural Gas Storage Industry

 

Natural gas is typically stored underground in depleted reservoirs, aquifers or salt caverns. Underground storage facilities contain what is known as base gas, or cushion gas, which is the volume of natural gas that is injected into the facility to maintain adequate pressure and deliverability rates, especially throughout the withdrawal season. In general, working gas is the volume of natural gas in a storage facility at a given point in time that exceeds the amount of base gas. Assuming adequate operating pressures, working gas is the amount of natural gas that can be extracted during the facility’s normal operation. References to the capacity of a storage facility typically refer to its working gas capacity.

 

Aquifers are underground rock formations that act as natural water reservoirs. Aquifers are typically found in regions without depleted oil and natural gas reservoirs. Based on publicly available information, we estimate that depleted reservoirs comprise approximately 85% of total working gas storage capacity in the United States. Depleted reservoir facilities are prevalent in the producing regions of the United States. Most salt cavern facilities have been developed in salt dome formations located along the Gulf Coast, with more limited development in bedded salt formations located in northeastern, midwestern and southwestern states. Our natural gas storage facilities are depleted reservoir or salt cavern storage facilities.

 

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The following charts provide an overview of the depleted reservoir and salt cavern storage facilities:

 

LOGO

 

Key Characteristics of Storage Facilities

 

   

Capacity. References to the capacity of a storage facility typically refer to its working gas capacity, the amount of natural gas that can be extracted during the facility’s normal operation. The ability to expand a facility to increase its storage capacity is also an important characteristic.

 

   

Injection and Withdrawal Capabilities. A distinguishing operational characteristic of any given storage facility is its peak injection and withdrawal rate, which dictates the number of times during a given year that a facility is capable of being “turned” or “cycled” (i.e., completely filled with injections of working gas and then completely emptied of working gas by withdrawals) and its connectivity to different pipelines and/or markets. Higher peak injection and withdrawal rates and access to multiple markets provide storage users with greater commercial and operational flexibility and, accordingly, command higher storage rates. Salt caverns are cavities or chambers formed in underground salt deposits, and natural gas can be freely injected into and withdrawn from such caverns with the aid of compression. Conversely, depleted reservoirs store natural gas within porous rock formations and the ability of natural gas to move into and out of the facility is limited by the permeability of the applicable formations, even with the aid of compression. As a result, salt caverns generally have significantly higher peak injection and withdrawal rates, and can be cycled more times per year, than depleted reservoirs and aquifers.

 

   

Connectivity to Pipelines and Markets. Storage facilities that are directly or indirectly connected to multiple transmission pipelines offer significant value to the storage capacity holder by providing flexible and timely access to consuming markets.

 

   

Cost to Develop. The primary categories of cost associated with the development of natural gas storage facilities are (i) real and personal property acquisition costs, (ii) equipment purchase costs, (iii) costs associated with construction, and (iv) the cost of acquiring base gas, which is required to maintain operating pressures and allow for working gas withdrawals. With respect to construction and other non-base gas costs, depleted reservoir facilities are usually the least expensive to develop as portions of existing pipeline and facility infrastructure related to prior production operations can often be used in connection with the development and operation of a depleted reservoir facility, reducing up-front infrastructure costs. In terms of base gas costs, which represent an additional up-front investment cost for a storage facility operator, according to a FERC report on underground natural gas storage, salt caverns typically require the lowest levels of base gas at approximately 20-30% of total natural gas capacity. By comparison, depleted reservoirs typically require approximately 50% base gas.

 

   

Geological Risks. A critical attribute of any underground natural gas storage facility is the integrity of the geological structure in which the natural gas is stored. The geology of depleted reservoirs is typically well understood and the risk of natural gas leaks is relatively low given their prior natural use for storing hydrocarbons. The risk of natural gas leaks from salt caverns is also relatively low given that the walls of a properly constructed salt cavern provide a non-porous seal that reduces the likelihood of natural gas leaks.

 

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Competition and Barriers to Entry

 

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 the storage 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.

 

Although competition within the storage industry is robust, there are significant barriers to entering the natural gas storage business. These barriers include, among others:

 

   

Costs and Execution Risk. The costs of developing and constructing an underground storage facility are significant and highly variable, depending on drilling costs, subsurface issues, raw water availability, brine disposal arrangements, compression requirements, costs of establishing interconnects and other factors. The creation of storage facilities also involves significant execution risk with respect to drilling and completing wells and related sub-surface activities.

 

   

Time Commitment. The length of time required to permit and develop a new project and place it into service can be long and unpredictable, generally ranging from two to four years or more, depending on the type of facility, location, permitting issues, subsurface issues and other factors.

 

   

Financing. The magnitude and uncertainty of capital costs, length of the permitting and development cycle and scheduling uncertainties associated with natural gas storage development can present significant project financing challenges.

 

   

Limited Number of Sites. Finding and developing new natural gas storage facilities, or acquiring existing facilities, is extremely competitive given that there are a limited number of sites that possess the requisite characteristics in terms of proximity to pipelines and load centers, operational flexibility, geological characteristics and overall risk/return profile.

 

   

Required Expertise. Specialized expertise is required to identify market areas that require or will support additional storage capacity. In addition, acquiring, developing and operating natural gas storage facilities involves identifying, assessing and managing significant geological and other risks that require specialized industry knowledge and experience, including in the areas of reservoir engineering and geology, cavern or reservoir development and construction, and natural gas compression, handling, treating and transportation. Individuals with significant relationships with customers and other participants across the natural gas supply chain are also invaluable in providing a commercial understanding of the natural gas market. Because there is significant market demand for this combination of skill sets and individuals with such skills sets are in short supply, finding and retaining management and operational personnel is highly competitive.

 

Value Drivers for Natural Gas Storage

 

The long-term demand for storage services in the United States is driven primarily by the long-term demand for natural gas and the overall lack of balance between the supply of and demand for natural gas on a seasonal, monthly, daily or other basis. In general, to the extent the overall demand for natural gas increases and such growth includes higher demand from seasonal or weather-sensitive end-users (such as natural gas-fired electric generators), demand for natural gas storage services should also grow. In addition, any factors that contribute to more frequent and severe imbalances between the supply of and demand for natural gas, whether caused by supply or demand fluctuations, should increase the need for and value of storage services.

 

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In terms of valuing storage demand, the principal value drivers include:

 

   

Location. The location of storage is a key value component for natural gas storage facilities. Storage assets that are closer in proximity to markets that generate more demand relative to local supplies are generally more valuable than are storage assets located in closer proximity to supply hubs. For purposes of tracking natural gas storage levels, the American Gas Association, or AGA, divides the contiguous United States into three regions: the Eastern Consuming region, the Producing region and the Western Consuming region. According to the EIA, during the period from January 1, 2005 to July 28, 2011, average daily natural gas consumption in the AGA Eastern Consuming region was approximately 12.9 Bcf/d compared to average daily production in that region of approximately 1.8 Bcf/d. This shortfall in supply can be more pronounced in the winter months during periods of peak demand. Additionally, storage assets that have more access to takeaway capacity, and therefore better market access, also tend to have higher value.

 

   

Volatility of Natural Gas Prices. In times when natural gas prices are more volatile, the value of storage capacity increases because storage capacity holders with the contractual ability to withdraw or inject natural gas, as applicable, are able to capture more value from their storage capacity. When near-term natural gas prices are volatile, storage capacity holders often have opportunities to inject and withdraw natural gas from storage in an effort to earn incremental margins above the seasonal spread as market opportunities permit. This is sometimes referred to as the option value of natural gas storage. In addition, increased volatility in demand can intensify the demand for storage for supply reliability. Natural gas storage facilities with higher injection and withdrawal capabilities are best able to capture value from natural gas market volatility.

 

   

Operating Flexibility. Each type of storage facility (depleted reservoir or salt cavern, for example) offers a different type of operational flexibility. The number of times that natural gas can be “turned,” or injected and withdrawn, in a single year is a significant component of storage asset value. Connectivity of a storage facility to multiple transportation pipelines with downstream access to demand markets is also a significant component of storage asset value.

 

   

Seasonal Spreads. This spread is the difference between the highest and lowest natural gas prices on the NYMEX 12-month forward curve, less the carrying costs of storage. Natural gas storage capacity allows the capacity holder to take advantage of the seasonal spread by injecting and storing natural gas when prices are low and then withdrawing the natural gas during periods of high demand when prices are higher. The gross margin available from buying and injecting natural gas in summer months for withdrawal in winter months can be locked in at the time of injection by entering into a forward sale for the natural gas.

 

   

Service Reliability. The ability to provide service that is in line with both contract terms and customer expectations is a value driver. Customers are generally less inclined to enter into or renew agreements with storage providers who frequently experience operational problems, or otherwise have difficulty providing storage services upon mutually-agreed terms and conditions.

 

NGL Industry Dynamics

 

Most natural gas produced at the wellhead contains NGLs. Natural gas produced in association with crude oil typically contains higher concentrations of NGLs than natural gas produced from natural gas wells. 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. Furthermore, processing plants produce NGLs which, on an energy equivalent basis, usually have a greater economic value as a raw material for petrochemicals, motor gasolines or commercial use than as a residual component of the natural gas stream. In order for the mixed NGLs to become marketable to end users, they are first fractionated into NGL products, sometimes put into storage and ultimately distributed to end users.

 

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We believe that current industry dynamics are resulting in increases in domestic drilling targeting NGLs, particularly in areas with unconventional reserves, creating the need for additional NGL infrastructure and services. Factors contributing to this include (i) a strong crude oil and NGL price environment relative to current natural gas prices, with the price of West Texas Intermediate crude oil at $79.20/bbl, Henry Hub spot prices for natural gas at $3.73/MMBtu and composite NGL prices at $1.42/gallon as of September 30, 2011; (ii) the continuation of oil and natural gas exploration and production innovation including geophysical interpretation, horizontal drilling and well completion techniques; (iii) a trend toward increased drilling in oil, condensate and NGL rich, or “liquids rich” reservoirs, especially resource plays; and (iv) increasing levels of supply of mixed NGLs coupled with strong demand from petrochemical complexes and exports which are leading to higher capacity utilization of NGL storage facilities. We believe these trends will continue to result in strong demand for the services provided by our NGL storage business.

 

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BUSINESS

 

Overview

 

We are a fee-based, growth-oriented Delaware limited partnership formed by NRGY to own, operate, develop and acquire midstream energy assets. Our current asset base consists of natural gas and NGL storage and transportation assets located in the Northeast region of the United States. We own and operate four natural gas storage facilities located in New York and Pennsylvania that have an aggregate working gas storage capacity of 41.0 Bcf with high peak injection and withdrawal capabilities. We also own natural gas pipelines located in New York and Pennsylvania with 30 MMcf/d of intrastate transportation capacity and, upon completion of two pipeline projects that are currently under development, we will own 875 MMcf/d of interstate transportation capacity. In addition, we own and operate a 1.5 million barrel NGL storage facility located near Bath, New York. Our near-term strategy is to continue to develop a platform of interconnected natural gas assets that can be operated as an integrated Northeast storage and transportation hub.

 

Our business has expanded rapidly through internal growth initiatives and acquisitions since its inception in 2005. We have grown our natural gas storage capacity from 13.0 Bcf as of September 30, 2005 to 41.0 Bcf as of September 30, 2011, which does not include 38.4 Bcf of natural gas storage capacity owned by NRGY on the Texas Gulf Coast. We believe that our current asset base enables us to significantly expand our storage and transportation capacity through continued investment in attractive growth projects. We expect these growth projects will further increase connectivity among our natural gas facilities and with third-party pipelines, thereby resulting in increased demand for our services.

 

Our significant growth projects include:

 

   

construction of the MARC I pipeline, a fully contracted natural gas transmission pipeline with 550 MMcf/d of interstate transportation service, which we expect to complete and place into service in July 2012 with contracts extending to 2022;

 

   

completion of our North/South expansion project, which involves the installation of additional compression facilities that will enable us to provide approximately 325 MMcf/d of interstate transportation service on a fully contracted basis, which we expect to complete and place into service in late October 2011 with contracts extending to 2016;

 

   

development of a 2.1 million barrel NGL storage facility located near Watkins Glen, New York, which is approximately 95% contracted and which we expect to complete and place into service by June 2012 with a contract extending to 2016; and

 

   

expansion of our Seneca Lake natural gas storage facility by an additional 0.6 Bcf of working gas storage capacity, which we expect to complete and place into service by December 2012.

 

Through our current assets, growth projects and potential acquisitions from NRGY and third parties, we believe we are well-positioned to benefit from the anticipated long-term growth in demand for natural gas and NGL storage and transportation services in the United States.

 

For the fiscal year ended September 30, 2010 and the nine months ended June 30, 2011, we generated pro forma net income of approximately $29.3 million and $30.0 million, respectively. For the fiscal year ended September 30, 2010 and the nine months ended June 30, 2011, we generated approximately $70.4 million and $59.2 million of pro forma Adjusted EBITDA, respectively. Please read “Summary—Non-GAAP Financial Measures” for our definition of Adjusted EBITDA and our reconciliation of Adjusted EBITDA to its most directly comparable financial measures calculated and presented in accordance with GAAP.

 

Our Assets

 

Our assets are strategically located close to or within demand-based market areas in the Northeast region of the United States, with access to multiple natural gas and NGL supply points, including Marcellus shale production volumes. We believe that our geographic location provides us with a competitive advantage for the services we offer.

 

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In determining which midstream assets we would continue to own in connection with this offering, we understand that NRGY identified assets that it believed would collectively generate stable cash flows and also have sufficient scale to enable us to grow through acquisitions and internal growth projects—a prerequisite for a company valued, in part, on its ability to pay and increase distributions over time. NRGY specifically considered the following, among other factors:

 

   

Stable cash flows. NRGY desired for us to own natural gas and NGL storage and transportation assets with established operating histories that will generate stable cash flows. Our high-quality storage assets have a track record of generating predominantly fee-based revenues. In addition, our four natural gas facilities regulated by the FERC have low maintenance costs. NRGY believed these characteristics of our assets would facilitate management’s ability to forecast cash flows with a greater degree of accuracy and enhance our ability to generate stable cash flows.

 

   

Geographic location. In order to support our near-term strategy of developing a midstream platform of interconnected natural gas assets that can be operated as an integrated Northeast storage and transportation hub, NRGY desired for us to own the assets and related growth projects that most favorably position us to improve connectivity to multiple sources of supply and best serve the attractive Northeast demand market. Our assets are strategically located near prolific shale plays, including the Marcellus shale, and high-demand metropolitan markets in the Northeast. The interrelated nature and close geographic location of our assets position us well to develop future growth projects that will further move us toward owning and operating an integrated storage and transportation hub.

 

We believe that NRGY’s decision to retain certain midstream businesses was based primarily on its belief that those assets have not yet been fully developed or optimized. For example, the Tres Palacios natural gas storage facility, which commenced operation in 2008 and was acquired by NRGY in 2010, is a relatively new storage facility with which management has a limited operating history. Moreover, a majority of NRGY’s retained midstream assets (including Tres Palacios) are geographically located outside of the Northeast demand market.

 

Natural Gas Storage

 

We own and operate four natural gas storage facilities regulated by the FERC, which have low maintenance costs, long useful lives and comparatively high injection and withdrawal (or “cycling”) capabilities. The facilities also require low amounts of cushion gas, meaning that a relatively small amount of gas is required to remain inside our facilities in order to maintain a minimum facility pressure supporting the working gas. Our natural gas storage facilities include:

 

   

Stagecoach, a high performance, multi-cycle natural gas storage facility located approximately 150 miles northwest of New York City in Tioga County, New York and Bradford County, Pennsylvania. Stagecoach generates fee-based revenues under a market-based rate structure and is currently 95% committed primarily with investment-grade customers under term contracts that have a weighted average maturity extending to 2015. Stagecoach is the closest natural gas storage facility to the northeastern United States demand market and is an integral part of the Northeast gas storage and transportation system. Stagecoach’s 24-mile, 30-inch diameter south pipeline lateral connects the facility to TGP’s 300 Line, and its 10-mile, 20-inch diameter north pipeline lateral connects the facility to the Millennium Pipeline. The Stagecoach laterals diversify our supply sources and provide wheeling and other transportation opportunities to shippers.

 

   

Thomas Corners, a high performance, multi-cycle natural gas storage facility located in Steuben County, New York. Thomas Corners generates fee-based revenues under a market-based rate structure and is fully contracted with primarily investment-grade customers under long-term agreements that have a weighted average maturity extending to 2015. An 8-mile, 12-inch diameter pipeline lateral connects the facility to TGP’s 400 Line, and a 7.5-mile, 8-inch diameter pipeline lateral connects the facility to the Millennium Pipeline. We intend to request FERC authorization for ASC to acquire, own and operate Steuben, which will effectively facilitate Thomas Corners’ interconnection to Dominion through Steuben’s existing laterals.

 

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Seneca Lake, a high performance, multi-cycle natural gas storage facility located in Schuyler County, New York. Seneca Lake generates fee-based revenues under a market-based rate structure. The capacity at Seneca Lake is contracted with investment-grade customers under long-term agreements that have a weighted average maturity extending to 2018. Seneca Lake is connected to Dominion’s system via the 20-mile, 16-inch diameter Seneca West pipeline lateral, and crosses both the Millennium Pipeline and the Empire Pipeline. We intend to interconnect Seneca Lake with the Millennium Pipeline under our existing blanket FERC authority by December 2011. We expect this additional interconnect to increase the market demand for storage service at Seneca Lake.

 

   

Steuben, a single-turn natural gas storage facility located in Steuben County, New York. Steuben generates fee-based revenues under a cost-of-service rate structure and is fully contracted with primarily investment-grade customers with term contracts having a weighted average maturity extending to 2013. A 12.5 mile, 12-inch diameter pipeline lateral connects the facility to Dominion, and a 6-inch diameter pipeline measuring less than one mile connects the Steuben facility and our Thomas Corners facility.

 

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

 

Facility Name/ Location

  Facility Type   Percentage
Contractually
Committed
    Working
Gas
Storage
Capacity
(Bcf)
    Maximum
Injection
Rate
(MMcf/d)
    Maximum
Withdrawal
Rate
(MMcf/d)
     Pipeline
Connections

Stagecoach

Tioga County, New York;
Bradford County, Pennsylvania

  High
Performance,
Multi-Cycle,
Depleted
Reservoir
    95     26.3        250        500       TGP’s 300
Line;
Millennium
Pipeline
(1)

Thomas Corners

Steuben County, New York

  High
Performance,
Multi-Cycle,
Depleted
Reservoir
    100 %(2)      7.0        70        140       TGP’s 400
Line;
Millennium
Pipeline;
Dominion
(3)

Seneca Lake

Schuyler County, New York

  High
Performance,
Multi-Cycle,
Salt Cavern
    59 %(4)      1.5        72.5        145       Dominion(5)

Steuben

Steuben County, New York

  Single-Turn,
Depleted
Reservoir
    100     6.2        30        60       TGP’s 400
Line;
Millennium
Pipeline;
Dominion
(6)
     

 

 

   

 

 

   

 

 

    

Total

        41.0        422.5        845      
     

 

 

   

 

 

   

 

 

    

 

(1)   We have requested FERC authorization to interconnect Stagecoach’s south lateral to Transco’s Leidy Line as part of our MARC I pipeline project.
(2)   Thomas Corners has 7.0 Bcf of certificated capacity and currently has 5.7 Bcf of operational capacity available, all of which has been sold under firm storage contracts. Therefore, 100% of Thomas Corners’ operationally available capacity is committed. Please read “—Contracts.”
(3)   Thomas Corners is indirectly connected to Dominion through our Steuben facility. Please read “—Regulation—Natural Gas Storage and Transportation Regulation—Pending Authorization (FERC).”
(4)   We did not acquire Seneca Lake until July 2011 and are currently in the process of leasing out the remaining storage capacity at the facility.
(5)   In addition to our Dominion interconnect, we intend to interconnect Seneca Lake to the Millennium Pipeline under our existing blanket FERC authority.
(6)   Steuben is indirectly connected to TGP and the Millennium Pipeline through our Thomas Corners facility. Please read “—Regulation—Natural Gas Storage and Transportation Regulation—Pending Authorization (FERC).”

 

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Natural Gas Transportation

 

Interstate Transportation. We are authorized under our FERC tariffs to provide certain interstate natural gas transportation services. In connection with our MARC I pipeline and North/South expansion project, we have contracted to provide 875 MMcf/d of interstate transportation services upon the completion of these two FERC-regulated pipeline projects. Please read “—Our Growth Projects—Natural Gas Transportation” for a more detailed description of these projects.

 

Intrastate Transportation. We own and operate a 37.5-mile, 12-inch diameter intrastate pipeline, which we acquired in July 2011, that is located in New York and runs within approximately three miles of our Stagecoach north lateral’s point of interconnection with the Millennium Pipeline. The pipeline, formerly known as the Seneca Lake east lateral pipeline, is subject to regulation by the NYPSC.

 

NGL Storage

 

We own and operate a 1.5 million barrel NGL storage facility located near Bath, New York. The Bath storage facility is located approximately 210 miles northwest of New York City and 60 miles from our Stagecoach facility. It is supported by both rail and truck terminal facilities capable of loading and unloading 23 railcars per day and 17 truck transports per day. Although the Bath storage facility has proven cavern storage capacity of 1.7 million barrels, we currently have only 1.5 million barrels of cavern capacity available for propane and butane storage. We have contracted 100% of the facility’s operationally available storage capacity to an affiliate, Inergy Propane, under a five-year contract.

 

Our Growth Projects

 

Natural Gas Transportation

 

Our proposed MARC I pipeline is a 39-mile, 30-inch diameter bi-directional natural gas pipeline that will connect the Stagecoach south lateral and TGP’s 300 Line in Bradford County, Pennsylvania, with Transco’s Leidy Line in Lycoming County, Pennsylvania. The project involves the installation of a 16,360 horsepower gas-fired compression facility in the vicinity of the Transco interconnect, a 15,000 horsepower electric-powered compression facility at the proposed interconnect between the Stagecoach south lateral and TGP’s 300 Line, and related metering, flow control and appurtenant facilities. We have entered into binding agreements with shippers to provide approximately 550 MMcf/d of firm interstate transportation service on the MARC I pipeline after its completion. We requested FERC authorization for the project in August 2010 and currently expect to receive approval in October 2011. We expect to begin construction shortly following our receipt of FERC authorization, and we expect to complete and place into service the pipeline in July 2012. As of June 30, 2011, we have incurred capital expenditures of approximately $33.6 million, or 14%, of the total expected project cost.

 

Our North/South expansion project entails the installation of additional compression facilities to increase throughput capacity on Stagecoach’s existing north and south laterals, which will enable our contracted shippers to wheel gas bi-directionally, from the Millennium Pipeline to TGP, or from points in between, on a firm basis. We are installing a 13,400 horsepower electric-powered centrifugal compressor near the interconnect between Stagecoach’s north lateral and the Millennium Pipeline in Tioga, New York, and a 15,300 horsepower electric-powered compressor near the interconnect between Stagecoach’s south lateral and TGP in Bradford County, Pennsylvania. We have entered into binding agreements with shippers to provide up to 325 MMcf/d of firm wheeling capacity between receipt and delivery points at the existing interconnects with the Millennium Pipeline and TGP.

 

We received FERC authorization for the North/South expansion project in January 2011 and commenced construction in February 2011. We previously anticipated completing and placing the project into service in early October, but the recent flooding in the Northeast has resulted in delays in our construction schedule. We have

 

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substantially completed construction and anticipate placing the project into service in late October 2011. As of June 30, 2011, we have incurred capital expenditures of approximately $29.1 million, or 39%, of the total expected project cost. We expect to incur substantially all remaining construction costs, or approximately $45.3 million, prior to or immediately after placing the project into service.

 

On September 29, 2011, we announced a non-binding “open season” relating to the North/South II expansion project. Through the open season, we are seeking to gauge shipper interest in transporting additional natural gas volumes bi-directionally on a firm basis through our existing Stagecoach laterals from the Millennium Pipeline to TGP’s 300 Line, and all points in between. Prospective shippers can also participate in the extension of our existing Stagecoach laterals by electing to transport volumes bi-directionally from TGP’s 300 Line, and intermediate points including the Millennium Pipeline, to a new interconnect with Dominion in Tompkins County, New York, where our Inergy East pipeline interconnects with Dominion. The project may include the establishment of additional compression, the expansion of existing measurement facilities, and the installation of approximately three miles of pipe connecting the Millennium Pipeline and the Stagecoach North lateral to the Inergy East pipeline. The anticipated in-service date for the North/South II expansion project is expected to be September 1, 2013 based on assumed volume commitments and resulting facilities. We can provide no assurance that we will receive sufficient shipper interest to support the project, that we will move forward with the project even if we receive sufficient shipper interest, or that we will receive the federal, state and local approvals (including FERC approval) to construct and place into service the project.

 

NGL Storage

 

The Watkins Glen brine field is located in Schuyler County, New York along the west shore of Seneca Lake in south central New York. The land comprising the brine field is owned by our affiliate, US Salt, a wholly owned subsidiary of NRGY. US Salt and its predecessors have developed numerous salt caverns on their property since the late 1800s, mainly by solution mining brine for US Salt’s salt production plant in Watkins Glen, New York. The salt caverns created from the solution-mining process can be efficiently converted into usable natural gas and NGL storage capacity.

 

We are developing a 2.1 million barrel NGL storage facility located near Watkins Glen, New York. US Salt will convey to us the land associated with the Watkins Glen facility prior to the closing of this offering. The facility will utilize existing salt caverns solution mined by US Salt. Propane and butane will be stored in these caverns seasonally, and during storage operations, displaced brine will be stored in a 14-acre lined brine pond with a capacity of 2.2 million barrels. The storage facility will be supported by both rail and truck terminal facilities capable of loading and unloading 32 railcars per day and 45 truck transports per day. The Watkins Glen facility will also connect with TEPPCO LPG’s interstate pipeline and, upon receipt of regulatory approvals, we believe it can be expanded by up to five million barrels of capacity. In connection with this project, we entered into a binding storage contract with an anchor customer. As of June 30, 2011, we have incurred capital expenditures of approximately $35.0 million, or 57%, of the total expected project cost.

 

On August 17, 2011, the New York State Department of Environmental Conservation, or NYSDEC, determined that the Draft Supplemental Environmental Impact Statement (DSEIS) we submitted for the Watkins Glen facility was complete. A public hearing on the project was held on September 27, 2011. On October 5, 2011, the NYSDEC announced that a second public hearing on the project would be held on November 3, 2011. We believe the NYSDEC’s decision to require a second public hearing could delay the regulatory approval process and our construction schedule by four-to-six weeks. Accordingly, we now anticipate receiving NYSDEC approval in early 2012, commencing construction immediately following our receipt of NYSDEC approval, and placing the facility into service on June 1, 2012. We plan to operate the Bath and Watkins Glen facilities as one NGL storage complex.

 

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Natural Gas Storage

 

We plan to convert three existing wells (known as Gallery 2) located at the Seneca Lake storage facility into natural gas storage, thus expanding Seneca Lake’s authorized working gas storage capacity to approximately 2.0 Bcf. Since our acquisition of Seneca Lake in July 2011, the NYSDEC has begun to review our application requesting approval to expand Seneca Lake’s authorized storage capacity by 0.6 Bcf, with a maximum daily storage withdrawal of 50,000 Mcf. As part of this project, we will also interconnect Gallery 2 with Seneca Lake’s existing compression station. We will require FERC authorization to expand the Seneca Lake facility, and we expect to begin construction upon receipt of the NYSDEC and FERC authorizations required for the expansion project. We expect to complete the expansion and place the additional capacity into service by December 2012.

 

We also plan to jointly develop with NRGY a natural gas storage facility of up to approximately 10.0 Bcf by 2014, subject to market conditions. NRGY has identified existing salt caverns located on US Salt’s property for this project and has informed us that it intends to convert these solution-mined salt caverns into natural gas storage by 2014, at a estimated cost of approximately $120 million. Multiple regulatory approvals, including NYSDEC and FERC approvals, will be required to develop and place into service this storage capacity. Assuming this project is completed, we expect to evaluate acquiring it over time. We have not entered into any agreements with NRGY or its affiliates that obligate us or NRGY (or its affiliates) to develop this project.

 

Our Operations

 

Natural Gas Storage Services

 

We generate revenue in our natural gas storage business almost exclusively through the provision of fee-based natural gas storage services to our customers. Our storage rates are regulated under FERC rate-making policies, which currently permit our Stagecoach, Thomas Corners and Seneca Lake facilities to charge market-based rates for our storage services. Market-based rate authority for storage services allows us to negotiate rates with customers based on market demand. Our Steuben facility provides services at cost-based rates; however, we intend to request FERC authorization by the end of calendar year 2011 to allow Steuben to provide storage services at market-based rates. As of September 30, 2011, the aggregate storage capacity of our natural gas storage facilities was approximately 95% contracted under fixed reservation fee agreements. For the fiscal years ended September 30, 2008, 2009 and 2010 and the nine months ended June 30, 2011, approximately 78%, 78%, 79% and 80%, respectively, of our total revenue was derived from fee-based storage activities, including firm storage services and hub services.

 

Firm Storage Services. Firm storage services include storage services pursuant to which customers receive an assured, or “firm,” right to store natural gas in our facilities over a defined period, typically three to five years. 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 determined based on the number of cycles a customer can fill and empty its contracted storage capacity. Under our firm storage contracts, 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 natural 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 shippers to priority service and provides additional nominating and balancing flexibility. For the fiscal years ended September 30, 2008, 2009 and 2010 and the nine months ended June 30, 2011, approximately 75%, 74%, 77% and 76%, respectively, of our total revenue was derived from firm storage services.

 

Hub Services. Hub services include:

 

   

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;

 

   

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 seasonal basis;

 

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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

 

   

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.

 

For the fiscal years ended September 30, 2008, 2009 and 2010 and the nine months ended June 30, 2011, approximately 3%, 4%, 2% and 4%, respectively, of our total revenue was derived from hub services.

 

We believe that the high percentage of our revenues derived from fixed reservation fees under multi-year contracts with a diverse portfolio of customers stabilizes our cash flow profile and substantially mitigates the risk to us of significant negative cash flow fluctuations caused by changing supply and demand conditions and other market factors. For additional information about our contracts, please read “—Contracts.”

 

Natural Gas Transportation Services

 

We generate transportation revenue by providing fee-based transportation services to our customers. Our transportation services and rates have been authorized by the FERC or, if applicable, the NYPSC. The transportation services authorized under, or requested for authorization under, our FERC tariffs for the MARC I pipeline and for the North/South expansion project will be provided to our customers at negotiated rates subject to cost-of-service recourse rate options. Negotiated-rate authority for transportation services allows us to negotiate rates with customers based on market demand.

 

Interstate Transportation Services. Our interstate transportation services include firm wheeling services and firm and interruptible transportation services provided under our FERC tariffs. We have requested FERC authorization to provide firm and interruptible transportation services to shippers at negotiated rates on the 39-mile MARC I pipeline. We have entered into binding agreements with three shippers pursuant to which each shipper has agreed to enter into a firm transportation service agreement with us. Upon completion of the MARC I pipeline, we expect to provide approximately 550 MMcf/d of firm interstate transportation service on the pipeline to these shippers for an initial 10-year period under CNYOG’s FERC tariff. Our North/South expansion project is currently under development and entails the installation of additional compression facilities to increase throughput capacity on Stagecoach’s existing north and south laterals, which will enable CNYOG to permit contracted shippers to wheel gas bi-directionally, from the Millennium Pipeline to TGP, or from points in between, on a firm basis. As part of the North/South expansion project, we entered into binding agreements with five shippers pursuant to which each shipper has agreed to enter into a firm wheeling agreement with us. Upon completion of the project, we expect to provide 325 MMcf/d of firm wheeling service at negotiated rates on Stagecoach’s north and south laterals to these shippers for an initial five-year period under CNYOG’s FERC tariff. Please read “—Our Growth Projects—Natural Gas Transportation.”

 

We also generate interstate transportation revenue by releasing interstate pipeline transportation capacity to certain Stagecoach customers. At the time we acquired Stagecoach, we reserved 490 MMcf/day of pipeline transportation capacity on TGP’s interstate natural gas pipeline for a 10-year period to aid storage customers’ ability to transfer gas to and from the Stagecoach facility. We have notified TGP that, effective January 2012, our reserved transportation capacity on TGP’s system will be reduced to 90 MMcf/day. Our capacity reservation will expire on March 31, 2018, provided that our capacity reservation will automatically roll over for incremental five-year periods under TGP’s tariff unless we give advance notice to TGP of our desire not to exercise our roll over rights. Based on TGP’s recent rate case filings, commencing January 1, 2012, we expect our capacity reservation costs to equal our revenues generated by these capacity releases.

 

For the fiscal years ended September 30, 2008, 2009 and 2010 and the nine months ended June 30, 2011, approximately 16%, 14%, 13% and 12%, respectively, of our total revenue was derived from interstate transportation services.

 

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Intrastate Transportation Services. We provide intrastate transportation service to New York State Electric & Gas Corporation, or NYSEG, under a firm transportation service agreement approved by the NYPSC. Under this agreement, we make 30 MMcf/d of transportation capacity available to NYSEG on our 37-mile intrastate natural gas pipeline for the purpose of transporting natural gas from our interconnect with Dominion’s system to certain NYSEG city gates within its service territory. The initial term of the contract is 10 years, and NYSEG has the right to extend the term for incremental five-year periods during the life of the pipeline. We acquired our intrastate pipeline in July 2011.

 

The integrated and interconnected nature of our natural gas facilities enables us to offer customers a combination of services tailored to meet their specific needs. The table below indicates the types of storage and transportation services that we propose to provide to customers under our FERC tariffs, as of September 30, 2011:

 

           Facility
(FERC-Certificated Operator)
 

Type of Service

   Category  of
Service(1)
   Stagecoach
(CNYOG)
    Thomas  Corners
(ASC)
     Seneca Lake
(ASC)
     Steuben
(Steuben  Gas)
 

Firm Storage Service

   Firm S/S    ü        ü         ü         ü     

Interruptible Storage Service

   Hub    ü        ü         ü         ü     

No-Notice Storage Service

   Firm S/S      ü         ü        

Firm Parking Service

   Hub      ü         ü        

Interruptible Parking Service

   Hub      ü         ü        

Firm Loan Service

   Hub      ü         ü        

Interruptible Loan Service

   Hub      ü         ü        

Firm Wheeling Service

   Transport    ü (2 )          

Interruptible Wheeling Service

   Hub    ü        ü         ü        

Firm Transportation Service

   Transport    ü (3 )          

Interruptible Transportation Service

   Transport    ü (3 )          

Interruptible Hourly Balancing Service

   Hub      ü         ü        

 

(1)   In the table above, “Firm S/S” refers to firm storage services, “Hub” refers to hub services and “Transport” refers to transportation services.
(2)   Assumes the North/South expansion project is placed into service.
(3)   Assumes the MARC I pipeline is authorized by the FERC and placed into service.

 

NGL Storage Operations

 

We provide NGL storage and related terminaling services at our Bath storage facility under market rates. We make cavern storage space available for a fixed monthly reservation fee that must be paid regardless of customer usage. We provide loading and unloading services and receive fees for such services. We currently have 1.5 million barrels of propane and butane storage capacity in operation at the Bath storage facility. All of this storage capacity is leased to our affiliate, Inergy Propane, under a five-year contract with customary terms and conditions. Please read “Certain Relationships and Related Party Transactions—Other Transactions with Related Persons.”

 

For the fiscal years ended September 30, 2008, 2009 and 2010 and the nine months ended June 30, 2011, approximately 6%, 8%, 8% and 8%, respectively, of our total revenue was derived from NGL storage services.

 

We are also developing a 2.1 million barrel NGL storage facility located near Watkins Glen, New York, which we believe can be expanded to five million barrels of capacity upon receipt of regulatory approvals. Please read “—Our Growth Projects—NGL Storage” for a more detailed description of this project.

 

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Our Business Strategies

 

Our primary business strategy is to increase the cash distributions that we pay to our common unitholders by capitalizing on the anticipated long-term growth in the production of and demand for natural gas by owning, reliably operating and expanding interconnected natural gas and NGL storage and transportation assets in and around major North American production and demand centers. In executing this strategy, we intend to increase the scale and improve the functionality of our facilities to best serve our current and future customers’ needs, thereby increasing our cash flow and profitability over time. Our plan for executing this strategy includes the following key components:

 

Expand our existing Northeast facilities through internal growth projects to create an integrated storage and transportation hub.

 

Our current asset base enables us to significantly expand storage capacity and improve our facilities’ connectivity through continued investment in attractive growth projects. Our growth projects include (i) increasing transportation functionality and interconnectivity through our MARC I pipeline and North/South expansion project, which we also believe will facilitate greater interconnectivity between our natural gas storage assets in general, (ii) increasing NGL storage capacity by up to five million barrels of incremental NGL storage at our proposed Watkins Glen facility and (iii) adding 0.6 Bcf of natural gas storage capacity at our Seneca Lake facility. Our capital budget supports ongoing growth initiatives that leverage the market positioning of our existing facilities and management’s experience in the Northeast storage and transportation business. We intend to use our assets and NRGY’s assets to lower the cost, accelerate the timing and increase the commercial value of our new build activities. For example, the planned improved functionality at Stagecoach, combined with our proposed MARC I pipeline, will allow customers to efficiently move gas on a firm basis through an integrated system of north and south pipelines, and to take advantage of opportunities created through interconnectivity between Marcellus shale producing fields and multiple long-haul, third-party pipelines in the area. Additionally, we have identified smaller-scale capital projects at our facilities that we expect will provide incremental growth, enhance the functionality of our asset base and improve our ability to obtain contracts for the use of our assets. These projects include connecting our Thomas Corners facility to Dominion’s Woodhull Pipeline and connecting our Seneca Lake facility to the Millennium Pipeline.

 

Provide an unparalleled level of commitment and service to our customers through the ownership and development of critical energy infrastructure.

 

We intend to maximize the profitability and utilization of our current facilities by continually enhancing our storage and transportation services and increasing our facilities’ connectivity in response to market demand. We intend to serve as an integrated and fully functional Northeast storage and transportation hub, providing our customers with a single source for all of their storage and transportation needs and delivering our services reliably and efficiently through effective asset operation. We believe that our diversity of product offerings combined with our commitment to superior customer service will cultivate valuable and stable customer relationships over the long term.

 

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Pursue potential acquisitions from NRGY and third parties.

 

In addition to our ongoing investment in existing facilities, we will continually evaluate opportunities to acquire assets or businesses that are strategic to our long-term growth plan. We frequently monitor the marketplace to identify and pursue complementary acquisitions, with a particular focus on assets that would strengthen our franchise position in the Northeast or facilitate our entry into attractive new geographic or product markets. In addition, our strategy includes assessing acquisitions from NRGY. However, NRGY is entitled under the omnibus agreement to review and has the first option on any third-party acquisition opportunities, is under no obligation to make acquisition opportunities available to us, is not restricted from competing with us and 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. Although NRGY is under no obligation to make acquisition opportunities available to us, NRGY has a significant economic stake in us and a strong incentive to support our growth. NRGY currently owns geographically-diverse midstream assets that are operationally similar to our existing asset base, including:

 

   

the Tres Palacios natural gas storage facility located in Texas, which has 38.4 Bcf of existing storage capacity with potential expansion to approximately 48.0 Bcf upon the development of a fourth storage cavern. The facility is strategically located in close proximity to the Eagle Ford shale and the Houston and San Antonio markets. NRGY also recently secured the right to store NGLs at the facility and in other caverns located on the Markham salt dome;

 

   

US Salt, a solution-mining and salt production business located in close proximity to our natural gas and NGL storage facilities. US Salt produces and sells over 300,000 tons of salt each year and owns salt caverns that can be developed into natural gas and NGL storage capacity. NRGY has identified for potential development certain salt caverns having up to approximately 10.0 Bcf of natural gas storage capacity by 2014; and

 

   

a West Coast NGL business located near Bakersfield, California, which includes a 24 million gallon NGL storage facility, a 25.0 MMcf/d natural gas processing plant, a 12,000 barrels per day NGL fractionation plant and an 8,000 barrels per day butane isomerization plant.

 

In evaluating the acquisition of other businesses or assets, whether from NRGY or unaffiliated third parties, we will use our knowledge of the midstream industry, our network of customers and our existing asset base to gauge the attractiveness of the acquisition to our long-term growth and to determine whether (and how) to efficiently finance acquisitions. Upon integration of any acquired assets or businesses, we intend to use our extensive industry knowledge to maximize synergies with our existing assets and to operate the acquired assets or businesses more efficiently and competitively, thereby increasing our revenue and cash flow.

 

Maintain stable cash flows supported by long-term, fee-based contracts.

 

We will seek to minimize our direct commodity price exposure and maintain stable cash flows by generating substantially all of our revenues pursuant to multi-year, firm storage and transportation contracts with strong, creditworthy customers. As of September 30, 2011, the aggregate storage capacity of our natural gas storage facilities was approximately 95% contracted under fixed reservation fee agreements. As of September 30, 2011, approximately 100% of our pipeline transportation capacity was committed under agreements with a weighted average remaining life of approximately 5 years. We plan to maintain our focus on providing storage and transportation services on a long-term, fixed-fee basis as we grow our business.

 

Maintain a conservative and flexible capital structure and target investment grade credit metrics in order to lower our overall cost of capital.

 

We intend to maintain a balanced capital structure which, when combined with our stable fee-based cash flows, will afford us efficient access to the capital markets at a competitive cost of capital. We plan to maintain debt-to-capitalization, debt-to-EBITDA and other key credit metrics that are consistent with investment grade businesses in our industry, with the goal of ultimately obtaining investment grade credit ratings. In connection with this offering, we expect to assume from NRGY a $         million revolving credit facility that will be used to fund

 

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near-term growth and provide liquidity. We intend to finance growth projects and acquisitions in the markets with a balanced combination of debt and equity in conjunction with our target capital structure and our approach to managing our balance sheet to ensure the long-term stability of our business. We believe that this conservative approach to financial management is in the best interests of our common unitholders as we expect that it will provide us with a lower cost of capital and a more competitive operating position than more highly levered peers.

 

Our Competitive Strengths

 

We believe we are well positioned to execute our business strategies successfully because of the following competitive strengths:

 

Strategically located assets proximate to prolific shale plays (including the Marcellus shale) and high demand metropolitan markets in the Northeast.

 

Our assets are strategically located in and around the Marcellus shale and within 200 miles of the New York metropolitan market. We believe that our pipeline connectivity to major U.S. and Canadian natural gas supply sources provides us with a distinct competitive advantage. The strategic location of our assets and lack of a viable storage substitute in the region drives the high utilization of our facilities. We believe that the anticipated future increase in East Coast natural gas demand and the significant near-term gas production growth expected from the neighboring Marcellus and Utica shale plays makes regional natural gas storage and transportation services in the Northeast an increasingly attractive business.

 

Inventory of internal growth projects in the attractive Northeast market.

 

We are developing approximately $380 million in internal growth projects around our existing Northeast natural gas and NGL assets designed to enhance our profitability and increase our operating scale. Approximately $315 million of this investment forecast is budgeted for our MARC I pipeline and North/South expansion project, which we believe will improve the supply and transportation capabilities of our Northeast natural gas business and will add significant fee-based interstate transportation revenues to our business. We plan to complete and place into service the North/South expansion project and MARC I pipeline in late October 2011 and July 2012, respectively. Approximately $65 million of this investment forecast is budgeted for our Watkins Glen NGL storage development project, which will expand our NGL storage capabilities in the Northeast. We expect to complete and place into service the proposed 2.1 million barrel NGL storage facility by June 2012. Capital expenditures related to our MARC I pipeline, North/South expansion project and proposed NGL storage facility in Watkins Glen of approximately $27.2 million and $66.7 million were incurred for the fiscal year ended September 30, 2010 and the twelve months ended June 30, 2011, respectively. We expect to incur in the aggregate an additional $95.6 million related to these projects between June 30, 2011 and December 31, 2011.

 

We currently have 41.0 Bcf of in-service Northeast natural gas storage capacity. We plan to expand this capacity by 0.6 Bcf at our Seneca Lake facility by December 2012. We estimate the total capital cost of this expansion project to be approximately $3 million. In addition, NRGY has identified salt caverns on US Salt’s property for potential development into up to approximately 10.0 Bcf of natural gas storage capacity by 2014, subject to market conditions. NRGY estimates the total capital cost of this storage development project to be approximately $120 million. We expect to jointly develop this project with NRGY and to evaluate acquiring it over time. However, NRGY has no obligation to jointly develop this project with us.

 

We anticipate that these projects will allow us to better serve our customers’ storage and transportation needs, increase margins and enhance our ability to obtain contracts for the use of our assets. We believe these projects will be accretive to our common unitholders and increase the scale and stability of our business.

 

Affiliation with NRGY, a leading propane and midstream master limited partnership.

 

NRGY owns and operates a growing, geographically diverse retail and wholesale propane supply, marketing and distribution business and is the fourth largest national propane retailer based on retail gallons sold. By virtue

 

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of NRGY’s ownership of our general partner, all of our incentive distribution rights and approximately         % of our common units upon the closing of this offering, NRGY has a vested interest in our success. NRGY intends for us to operate and develop midstream storage and transportation assets in the United States, and it will be incentivized to support our growth and development in ways that enhance the value of our business. In addition to the potential to benefit from NRGY’s asset acquisition and integration expertise as well as its deep industry knowledge, NRGY also retains and operates a geographically diverse set of midstream assets, including the Tres Palacios natural gas storage facility located in Texas, the US Salt solution-mining and salt production business located in New York, and a West Coast NGL business located near Bakersfield, California. NRGY has also identified salt caverns on US Salt’s property for potential development into up to approximately 10.0 Bcf of natural gas storage capacity by 2014, subject to market conditions. NRGY’s retained midstream business and expansion opportunities are of strategic interest to us and would complement our existing asset base by diversifying our cash flow sources. While no obligation exists to sell these assets to us or to jointly develop them with us, NRGY’s significant ownership interest provides a strong incentive to support our growth.

 

High quality assets with multiple sources of supply and connectivity to service growing demand markets.

 

Our storage assets include high quality depleted natural gas reservoirs and salt cavern storage facilities. Our infrastructure is generally newly constructed and has high injection and withdrawal capabilities, which facilitate our ability to deliver natural gas in a timely and reliable manner on behalf of our customers. Our assets are connected to diverse sources of supply, including production from Canada, the Rocky Mountains, the Gulf Coast and the Marcellus shale. We also have connectivity to key long-haul natural gas pipelines that deliver natural gas to East Coast demand markets, including the Millennium Pipeline, TGP, National Fuel Gas Supply Corporation’s pipeline, the Empire Pipeline, Transco’s Leidy Line and Dominion’s Woodhull Pipeline. The combination of high quality storage assets, ample supply sources and efficient and widespread deliverability make our Northeast storage and transportation platform valuable to our customers.

 

Stable, fee-based cash flows with long-term contracts and high quality customer base.

 

Our operations consist predominantly of fee-based services that generate stable cash flows. As of August 31, 2011, approximately 95% of our revenue was obtained from fixed reservation fees under long-term agreements with strong, creditworthy customers, such as large East Coast utilities and major natural gas marketing firms. Assuming completion of our natural gas transportation projects in 2012, approximately 100% of our firm storage and transportation revenue is expected to be contracted under long-term contracts with strong, creditworthy customers. Additionally, we do not take title to the natural gas and NGL that we store and transport for our customers and, as a result, our business is generally not exposed to commodity price fluctuations or other related risks. We believe that the resulting stable cash flow profile enhances the predictability of our performance and facilitates our access to the capital markets.

 

Significant barriers to entry.

 

Competitors who seek to add substantial capacity in the markets in which we currently operate may face significant geographical, marketing, financial, regulatory and logistical difficulties. In particular, there is a scarcity of unexploited reservoirs located near pipeline infrastructure, natural gas and NGL supply sources and end-user markets that have the capacity necessary to store natural gas and NGLs economically. Operational challenges and high upfront capital costs associated with the development of natural gas and NGL storage and transportation assets also exist. They include obtaining title to land and permits to operate, constructing facilities for injecting, storing and withdrawing natural gas and NGLs and meeting high cushion gas requirements. Moreover, significant industry skills are required to identify, construct and operate successful natural gas and NGL infrastructure, and many of these skills are uncommon.

 

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Experienced management team.

 

Our management team has significant expertise owning, developing and operating storage and transportation assets, as well as significant relationships with participants across the natural gas supply chain, and has a proven track record of successfully building, enhancing, acquiring, integrating and managing midstream storage and transportation assets in a reliable and cost-effective manner. Our senior management team includes the most senior officers of NRGY, a group with an average of 20 years of experience in all phases of the propane and midstream industries. We intend to leverage this experience to continue to grow and manage our business in order to increase cash distributions to our common unitholders over time.

 

Inergy, L.P.

 

NRGY and its predecessor have been active participants in the energy industry since the mid-1990s. NRGY has a long history of successfully expanding its energy businesses through complimentary acquisitions and, to a lesser extent, internal growth projects. Since its predecessor’s inception in November 1996 through July 31, 2011, NRGY has acquired 90 businesses. Since NRGY’s initial public offering in 2001, NRGY has grown its asset base from approximately $150 million to over $3.3 billion and increased the annualized distribution on its limited partner units by over 100%, from $1.20 per unit (adjusted for unit splits) as of NRGY’s initial public offering to $2.82 per unit for the distribution paid on August 12, 2011.

 

We believe NRGY’s significant presence in the energy sector, its successful track record of growth and its significant investment in, and sponsorship and support of, our business will enhance our ability to increase cash distributions. Through our relationship with NRGY, we will have access to a significant pool of management talent and strong commercial relationships throughout the energy industry. In addition, upon completion of this offering, NRGY will continue to have a significant economic stake in us through its ownership of approximately         % of our outstanding common units and an indirect interest in 100% of our incentive distribution rights. This retained economic stake will provide NRGY with a strong continued incentive to promote and support the successful execution of our growth plan and strategy. Although we expect to have the opportunity to make additional acquisitions directly from NRGY in the future, NRGY is under no obligation to make acquisition opportunities available to us. Accordingly, we are unable to predict which, if any, acquisition opportunities NRGY may make available to us or whether we will elect to pursue any such opportunity. While our relationship with NRGY and its subsidiaries may provide significant benefits, it may also become a source of potential conflicts. For example, NRGY is not restricted from competing with us and 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. Please read “Conflicts of Interest and Fiduciary Duties” and “Certain Relationships and Related Party Transactions—Agreements with Affiliates in Connection with the Transactions—Omnibus Agreement.”

 

In connection with the closing of this offering, we will enter into an omnibus agreement with NRGY and certain of its affiliates, pursuant to which we will agree upon certain aspects of our relationship with them, including the provision by NRGY to us of certain administrative services and employees, our agreement to reimburse NRGY for the cost of such services and employees, certain indemnification obligations, the use by us of the name “Inergy” and related marks, NRGY’s right to review and first option with respect to business opportunities, and other matters. In addition, we have entered into or will enter into various other agreements with NRGY that will effect the transactions relating to our formation and this offering, including the vesting of assets in, and the assumption of liabilities by, us and our subsidiaries and the application of the net proceeds of this offering. We believe the terms of these agreements are or will be no less favorable to either party than those that could have been negotiated with an unaffiliated party; however, these agreements have been or will be negotiated among affiliated parties. Please read “Certain Relationships and Related Party Transactions.”

 

Customers

 

We provide natural gas storage and transportation services predominantly to creditworthy utilities (LDCs and electric utilities), marketers, producers, industrial users, pipelines and refiners. In addition to our customers in the Northeastern markets, we have access to customers in the Mid-Atlantic, Midwest and Southeastern regions of the United States through our interconnections with major pipelines, including TGP and Transco.

 

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We provide storage services to an affiliate pursuant to which it utilizes all of the storage capacity at our underground NGL storage facility located near Bath, New York. Please read “Certain Relationships and Related Party Transactions.”

 

For the fiscal years ended September 30, 2010 and 2009, ConEdison accounted for approximately 28% and 29%, respectively, of our total revenue. For the fiscal year ended September 30, 2008, ConEdison, NJR Energy Services and its affiliates and TGP accounted for approximately 19%, 15% and 12%, respectively, of our total revenue. Other than as described above, no other customer accounted for 10% or more of our total revenue for the fiscal years ended September 30, 2010, 2009 or 2008.

 

Contracts

 

The terms and conditions of the agreements under which we provide interstate storage and transportation services to customers are governed by our FERC-authorized tariffs. The general terms and conditions of our FERC gas 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. The terms and conditions vary between the FERC-authorized gas tariffs of CNYOG, ASC and Steuben Gas.

 

The table below provides additional information on contracts relating to our natural gas storage facilities:

 

Facility

(FERC-Certificated Operator)

   % of Operationally Available
Capacity Subscribed under
Firm Contracts
    % of Physical Deliverability
Subscribed under Firm
Contracts
    Weighted Average
Maturity Date

Stagecoach (CNYOG)

     82     95   December 2015

Thomas Corners (ASC)

     100     100   March 2015

Seneca Lake (ASC)

     59     59   August 2018

Steuben (Steuben Gas)

     100     100   March 2013

 

Capacity, injection and withdrawal characteristics are metrics used to define a reservoir and monitor customer commitments. The percentage of capacity subscribed indicates the percent of available capacity that has been contracted for firm storage service, and the percentage of deliverability subscribed indicates the percent of contracted capacity that can be delivered to firm storage customers. For an underground depleted reservoir storage facility, injection and withdrawal capability generally varies inversely with a reservoir’s physical inventory at any given point in time, and by adjusting the reservoir’s inventory levels a storage operator can modify injection and withdrawal rates. Certificated capacity (the maximum amount of storage capacity authorized) can be higher than operationally available capacity when a storage operator has reduced physical inventory levels to increase injection and/or withdrawal rates. Although this reduction will result in a lower amount of operationally available storage capacity, it normally enables a firm storage customer to cycle capacity more frequently and thus increases the value of the storage for both the storage operator and the customer.

 

We provide intrastate transportation service to NYSEG under a firm transportation service agreement approved by the NYPSC. Under this agreement, we make 30 MMcf/d of transportation capacity available to NYSEG on our 37-mile intrastate natural gas pipeline for the purpose of transporting natural gas from our interconnect with Dominion’s system to certain NYSEG city gates within its service territory. The initial term of the contract is 10 years, and NYSEG has the right to extend the term for incremental five-year periods during the life of the pipeline. We did not generate any revenue from intrastate transportation services during the fiscal year ended September 30, 2010, as we did not acquire the pipeline until July 2011.

 

Competition

 

The principal elements of competition among storage and transportation assets are rates, terms of service, types of service, supply and market access, and flexibility and reliability of service. An increase in competition in our markets could arise from new ventures or expanded operations from existing competitors.

 

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Our principal competitors in our natural gas storage market include other independent storage providers and major natural gas pipelines, such as Dominion Resources, Inc., NiSource Inc. and El Paso Corporation. 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.

 

Regulation

 

Our operations are subject to extensive laws and regulations. We are subject to regulatory oversight by numerous federal, state, and local regulatory agencies, many of which are authorized by statute to issue, and have issued, rules and regulations binding on the natural gas storage and pipeline industry, related businesses and individual participants. The failure to comply with such laws and regulations can result in substantial penalties. The regulatory burden on our operations increases our cost of doing business and, consequently, affects our profitability. Except for certain exemptions that apply to smaller companies, however, we do not believe that we are affected by these laws and regulations in a significantly different manner than are our competitors.

 

Following is a discussion of certain laws and regulations affecting us. However, our common unitholders should not rely on such discussion as an exhaustive review of all regulatory considerations affecting our operations.

 

Our natural gas storage and transportation assets are subject to several kinds of regulation. Our historical and projected operating costs reflect the recurring costs resulting from compliance with these regulations, and we do not anticipate material expenditures in excess of these amounts in the absence of future acquisitions or changes in regulation, or discovery of existing but unknown compliance issues. The following is a summary of the kinds of regulation that may impact our operations.

 

Natural Gas Storage and Transportation Regulation

 

Interstate Regulation. Our subsidiaries that own natural gas storage and transportation pipeline facilities, including CNYOG, ASC and Steuben Gas, are classified as “natural-gas companies” under the NGA and are therefore subject to regulation by the FERC. The NGA requires that tariff rates and terms and conditions of service for gas storage and transportation pipeline facilities must be just and reasonable and non-discriminatory. The FERC has authority to regulate rates and charges for natural gas transported and stored in U.S. interstate commerce or sold by a natural gas company in interstate commerce for resale. The FERC also has authority over the construction and operation of natural gas storage and pipeline transportation facilities used in the transportation, storage and sale of natural gas in interstate commerce, including the extension, enlargement or abandonment of such facilities. The FERC’s authority extends to, among other things, terms and conditions of service, maintenance of accounts and records, depreciation and amortization policies, acquisition and disposition of facilities, initiation and discontinuation of services, imposition of creditworthiness and credit support requirements applicable to customers and relationships among pipelines and storage companies and certain affiliates.

 

The rates and terms and conditions of our natural gas storage and transportation services are found in the FERC-approved tariffs of CNYOG, as owner of the Stagecoach facility and, when completed, the MARC I pipeline; Steuben Gas, as owner of the Steuben facility; and ASC, as 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 facilities, respectively. CNYOG is also authorized

 

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to charge negotiated rates for transportation services. Market-based and negotiated rate authorization allows us to negotiate rates with individual customers based on market demand, which we then make public. Steuben Gas is authorized to charge and collect cost-of-service rates at the Steuben facility.

 

Standards of Conduct for Transmission Providers. In October 2008, the FERC issued new standards of conduct regulations for transmission providers that conduct transmission transactions with an affiliate engaging in marketing functions. After a series of rehearing orders issued between October 2009 and April 2011, the new regulations are now final. CNYOG, ASC and Steuben Gas currently are not subject to FERC’s standards of conduct regulations because they do not conduct any such affiliate transactions.

 

Natural Gas Price Transparency. In April 2007, the FERC issued a notice of proposed rulemaking, or NOPR, regarding price transparency provisions of the NGA and the Energy Policy Act of 2005, or the EPAct 2005. In the notice, the FERC proposed to revise its regulations to, among other things, require that buyers and sellers of more than a de minimis volume of natural gas report annual numbers and volumes of relevant transactions to the FERC. In December 2007, the FERC issued Order No. 704 implementing the annual reporting provisions of the NOPR with minimal changes to the original proposal. The order became effective in February 2008. The FERC issued two orders on rehearing in 2008, and following a technical conference in March 2010, the FERC issued an order clarifying the reporting requirements in June 2010. CNYOG, ASC and Steuben Gas are subject to these annual reporting requirements.

 

Energy Policy Act of 2005. Under the EPAct 2005 and related regulations, it is unlawful in connection with the purchase or sale of natural gas or transportation services subject to FERC jurisdiction to use or employ any device, scheme or artifice to defraud; to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or to engage in any act or practice that operates as a fraud or deceit upon any person. EPAct 2005 also gives the FERC authority to impose civil penalties for violations of the NGA up to $1,000,000 per day per violation for violations occurring after August 8, 2005. The anti-manipulation rule and enhanced civil penalty authority reflect an expansion of FERC’s NGA enforcement authority.

 

Other Proposed Regulation. Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, the FERC, state commissions and the courts. The natural gas industry historically has been heavily regulated. Accordingly, we cannot provide assurances that the less stringent and pro-competition regulatory approach recently pursued by the FERC and Congress will continue.

 

Pending Authorization (FERC). In Docket CP10-194-000, CNYOG filed an application with the FERC on April 27, 2010, requesting authorization for the North/South expansion project. The FERC issued an order granting the requested authorization on January 20, 2011. The order contains a number of conditions that must be satisfied before we can place the additional compressor units into service and provide the transportation services authorized under the FERC order. Although recent flooding in the Northeast has delayed our construction schedule, we have substantially completed construction and expect to place the project into service in late October 2011. We will not be authorized to commence providing transportation services using the Stagecoach north and south laterals until we demonstrate to the FERC that we have satisfied the conditions set forth in the authorizing order.

 

In Docket CP10-480-000, CNYOG filed an application with the FERC on August 6, 2010, requesting authorization for the MARC I pipeline. On May 27, 2011, the FERC issued an Environmental Assessment, or EA, for the project, in which the FERC Staff has proposed a “finding of no significant impact” and recommends the adoption of twenty-two mitigation measures. We filed initial comments to the EA on July 11, 2011, and have subsequently filed responses to comments filed by several interveners. Several interveners generally opposed to the development of natural gas infrastructure in the Northeast have argued that, among other things, the environmental impact of the MARC I pipeline must be more fully evaluated in an Environmental Impact Statement, or EIS, before the FERC can issue a certificate authorizing the project. The preparation of an EIS could delay our FERC proceeding by an additional six-to-nine months. We do not expect the FERC to require an

 

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EIS, and we expect the FERC to issue an order granting the requested authorization in October 2011. We cannot, however, provide any assurances that the FERC will not require the preparation of an EIS or grant our requested authorization when anticipated, if at all.

 

The rate design for the transportation services associated with the North/South expansion project and MARC I pipeline differs from the market-based rate design for our gas storage services. We are authorized to charge negotiated rates subject to initial cost-based recourse rates options when providing the firm wheeling services associated with the North/South expansion project, and we have requested FERC approval to use the same rate design when providing transportation services using the MARC I pipeline. Negotiated rates could, in theory, involve rates above or below the recourse rate; a prerequisite for having the right to agree to negotiated rates is that negotiated rate customers must have the option to take service under the pipeline’s recourse rates. Each negotiated rate is designed to fix the customer’s rate for the term of the firm wheeling or transportation agreement.

 

In addition, we plan to file an application with the FERC by the end of calendar year 2011 requesting authority for Steuben to charge market-based rates for its storage services. Steuben is authorized to charge cost-based rates under its existing FERC gas tariff. In particular, we intend to request FERC approval to merge Steuben Gas into ASC and, as a result thereof, charge market-based rates for Steuben storage services under ASC’s tariff. If our request is granted, we will have the ability to charge market-based rates for storage service provided by our Thomas Corners, Seneca Lake and Steuben facilities under one tariff (ASC’s tariff), which will move us closer toward becoming an integrated natural gas storage and transportation hub in the Northeast. The ownership and operation of Steuben and Thomas Corners by ASC under its tariff will effectively enable Thomas Corners to be directly connected to Dominion and enable Steuben to be directly connected to TGP and the Millennium Pipeline (i.e., there will be no functional distinction between Thomas Corner’s and Steuben’s interconnections once both facilities provide storage services under ASC’s tariff). We also believe that having the ability to operate all three of these storage facilities under the same tariff will improve interconnectivity and increase the attractiveness of the services we offer to our customers. We have not yet requested authorization for ASC to own and operate Steuben directly and to provide storage services from Steuben and Thomas Corners at market-based rates under ASC’s tariff.

 

Intrastate Regulation. On March 31, 2010, our wholly owned subsidiary, Inergy Pipeline East, LLC, or Inergy East, filed an application with the NYPSC for authorization to acquire from NYSEG a 37.5-mile intrastate natural gas transmission pipeline (formerly known as the Seneca Lake east lateral pipeline) running from Dominion’s interstate system to the city gate at Binghamton, New York. As part of the application, Inergy East requested that it be subject to lightened regulation under NYPSC regulations and policies following the acquisition. The NYPSC approved Inergy East’s acquisition of the intrastate pipeline and request for lightened regulation on March 4, 2011, as modified by an order dated June 17, 2011. Under lightened regulation, Inergy East is exempt from most NYPSC regulation applicable to the provision of retail service and, instead, must comply with 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) requirements regulated by the NYPSC.

 

Pipeline Safety

 

We own and operate pipeline header systems connecting our natural gas storage facilities to various interstate pipelines. We also own an intrastate pipeline and are developing an interstate natural gas pipeline. Our pipelines are subject to regulation by the Pipeline and Hazardous Materials Safety Administration, or PHMSA, pursuant to the Natural Gas Pipeline Safety Act of 1968, or NGPSA. The NGPSA regulates safety requirements in the design, installation, testing, construction, operation and maintenance of 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

 

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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 in our performance of customary pipeline management activities, we may incur significant additional expenses if anomalous pipeline conditions are discovered or more stringent pipeline safety requirements are implemented. For example, on August 25, 2011, PHMSA published an advanced notice of proposed rulemaking on August 25, 2011 in which the agency is seeking public comment on a number of changes to its natural gas transmission pipeline regulations contained in 49 C.F.R. Part 192 including: (i) modifying the definition of high consequence areas; (ii) strengthening integrity management requirements as they apply to existing regulated operators and could be applied to currently exempt operators should the exemptions be removed; (iii) strengthening or expanding various non-integrity pipeline management standards relating to such matters as valve spacing, automatic or remotely-controlled valves, corrosion protection, and gathering lines; and (iv) adding new regulations to govern the safety of underground natural gas storage facilities including underground storage caverns and injection/withdrawal wells piping that are not currently regulated under the Part 192 regulations. PHMSA is specifically requesting comment on the need to develop standards governing the safety of underground natural gas storage facilities. Public comments on these matters must be submitted to PHMSA by December 2, 2011. We believe that our operations are in substantial compliance with all existing federal, state, and local pipeline safety laws and regulations and that our compliance with such laws and regulations will not have a material adverse effect on our business, financial position, or results of operations but we can provide no assurance that the adoption of new laws and regulations such as those proposed by PHMSA on August 25, 2011 will not result in significant added costs that could have such a material adverse effect in the future.

 

Environmental and Occupational Safety and Health Regulation

 

General

 

Our natural gas storage and transportation operations and assets are subject to extensive and frequently-changing 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. Compliance with these laws and regulations may require the acquisition of permits to conduct regulated activities; restrict the type, quantities and concentration of pollutants that may be emitted or discharged into or onto to the land, air and water; restrict the handling and disposal of solid and hazardous wastes; apply specific health and safety criteria addressing worker protection; and require remedial measures to mitigate pollution from former and ongoing operations. As with the industry generally, compliance with existing and anticipated environmental laws and regulations increases our overall cost of business, including our capital costs to construct, maintain, operate and upgrade equipment and facilities. While these laws and regulations affect our maintenance capital expenditures and net income, we believe they do not affect our competitive position, as the operations of our competitors are similarly affected.

 

We believe our facilities are in substantial compliance with applicable environmental laws and regulations. However, these laws and regulations are subject to frequent change, and continued or future compliance with such laws and regulations, or changes in the interpretation of such laws and regulations, may require us to incur significant expenditures. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, and the issuance of injunctions that may limit or prohibit some or all of our operations. Additionally, a discharge of NGLs into the environment could, to the extent the event is not insured, subject us to substantial expenses, including costs to respond to such incident in compliance with applicable laws and regulations and to resolve claims made by third parties for claims for personal injury and property damage. These impacts could directly and indirectly affect our business and have an adverse impact on our financial condition, results of operations and cash flows.

 

Hazardous Substances and Wastes

 

To a large extent, the environmental laws and regulations affecting our operations relate to the release of hazardous substances or solid wastes into soils, groundwater, and surface water, and include measures to control

 

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pollution of the environment. These laws and regulations generally govern the generation, storage, treatment, transportation, and disposal of solid and hazardous waste. They also require corrective action, including investigation and remediation, at a facility where such waste may have been released or disposed. For instance, the federal Comprehensive Environmental Response, Compensation, and Liability Act, or CERCLA, which is also known as Superfund, and comparable state laws, impose liability, without regard to fault or to the legality of the original conduct, on certain classes of persons that contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of the site where the release occurred and companies that disposed of, or arranged for the disposal of, the hazardous substances found at the site. Under CERCLA, these persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. In the course of our ordinary operations, we generate wastes that may be characterized as hazardous substances.

 

We also generate solid wastes, including hazardous wastes, which are subject to the requirements of the federal Resource Conservation and Recovery Act, or RCRA, and comparable state statutes. From time to time, the EPA considers the adoption of stricter disposal standards for non-hazardous wastes, including crude oil and refined products wastes. We are not currently required to comply with a substantial portion of the RCRA requirements because our operations generate minimal quantities of hazardous wastes. However, it is possible that additional wastes, which could include wastes currently generated during operations, will in the future be designated as “hazardous wastes.” Hazardous wastes are subject to more rigorous and costly disposal requirements than are non-hazardous wastes. Any changes in the regulations could increase our maintenance capital expenditures and operating expenses.

 

We currently own and lease properties where hydrocarbons are being or have been handled for many years. Although we have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other waste have been spilled or released on or under the properties owned or leased by us or on or under other locations where these wastes have been taken for disposal or recycling. In addition, certain of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes was not under our control. These properties and wastes disposed thereon may be subject to CERCLA, RCRA, and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater), or to perform remedial operations to prevent future contamination.

 

Air Emissions

 

Our operations are subject to the federal Clean Air Act and comparable state laws and implementing regulations governing emissions of air pollutants from various industrial sources and also imposing monitoring and reporting requirements. Such laws and regulations may require that we obtain pre-approval for the construction and or modification of certain projects or facilities expected to produce new air emission pollutants or result in the increase of existing air emission pollutants, obtain and comply with air permits containing various emissions and operational limitations, and use specific emission control technologies to limit emissions, in which event our operating costs would be expected to increase. Also, we could be required to incur capital expenditures in the future in order to comply with any newly developed or more stringent emission limitations. We do not anticipate that future compliance with such requirements would be any more burdensome to us than to any other similarly situated storage companies.

 

Climate Change

 

In response to findings that emissions of carbon dioxide, methane, and other GHGs present an endangerment to public health and the environment because emissions of such gases are contributing to the

 

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warming of the earth’s atmosphere and other climate changes, the EPA has adopted regulations under existing provisions of the federal Clean Air Act that require a reduction in emissions of GHGs from motor vehicles and also may trigger construction and operating permit review for GHG emissions from certain stationary sources, effective January 2, 2011. While we are not required to maintain any Title V operating permits for our stationary sources, our construction activities do remain subject to regulation under the federal Prevention of Significant Deterioration permit program. The EPA has also adopted rules requiring the reporting of GHG emissions from specified large GHG emission sources in the United States on an annual basis, beginning in 2011 for 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, Congress has from time to time considered 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. The adoption of any legislation or regulations that requires reporting of GHGs or otherwise limits emissions of GHGs from our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations or could adversely affect demand for oil and natural gas that is produced, which could decrease demand for our storage services. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events; if any such effects were to occur, they could have an adverse effect on our operations.

 

Water

 

The Clean Water Act, or CWA, and analogous state laws impose strict control of the discharge of pollutants, including spills and leaks of oil and other substances, into state waters and waters of the United States. The CWA prohibits the discharge of pollutants into regulated waters, except in accordance with the terms of a permit issued by the EPA or analogous state agency. The CWA also regulates the discharge of storm water runoff from certain industrial facilities. Accordingly, some states require industrial facilities to obtain and maintain storm water discharge permits, which require monitoring and sampling of storm water runoff from such facilities.

 

As part of our operations, we inject brine into our underground storage facilities. Such operations are subject to the Safe Drinking Water Act, or SDWA, and analogous state laws, which regulate drinking water quality in the United States, including above ground and underground sources designated for actual or potential drinking water use. In particular, to protect underground sources of drinking water, the Underground Injection Control, or UIC, Program of the SDWA regulates the construction, operation, maintenance, monitoring, testing, and closure of underground injection wells. The UIC Program also requires that all underground injection wells be authorized, either under the general rules of the UIC Program or through specific permits. In most jurisdictions, states have primary enforcement authority over the implementation of the UIC Program, including the issuance of permits. The EPA implements the UIC Program in New York.

 

Endangered Species Act

 

The Endangered Species Act restricts activities that may affect endangered species or their habitats. We believe that we are in compliance with the Endangered Species Act. However, the discovery of previously unidentified endangered species could cause us to incur additional costs or become subject to operating restrictions or bans in the affected area.

 

Occupational Safety and Health

 

We are subject to the requirements of the Occupational Safety and Health Act, or OSHA, and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state, and local government authorities and citizens. We believe that our operations are in substantial compliance with applicable OSHA requirements, including general industry standards, record keeping requirements, and monitoring of occupational exposure to regulated substances.

 

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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.

 

Title to Properties and Rights-of-Way

 

Our real property falls into two categories: (1) parcels that we own in fee and (2) parcels in which our interest derives from leases, easements, rights-of-way, permits or licenses from landowners or governmental authorities permitting the use of such land for our operations. Portions of the land on which our facilities are located are owned by us in fee title, and we believe that we have satisfactory title to these lands. The remainder of the land on which our major facilities are located are held by us pursuant to leases between us, as lessee, and the fee owner of the lands, as lessors. We believe that we have satisfactory leasehold estates to such lands. We have no knowledge of any material challenge to the underlying fee title of any material lease, easement, right-of-way, permit or license held by us or to our title to any material lease, easement, right-of-way, permit or license, and we believe that we have satisfactory title to all of our material leases, easements, rights-of-way, permits and licenses.

 

Certain of our natural gas assets located in New York are subject to lease-leaseback agreements entered into with local taxing authorities as part of payment-in-lieu-of-taxes, or PILOT, programs. Under our tax-abatement programs, we make annual PILOT payments to local tax authorities rather than pay annual real property taxes based on assessed values. The amount of our annual PILOT payments increases each year during the life of the programs, which typically run 10-20 years in duration. Our Stagecoach and Thomas Corners facilities and the north compression facilities installed for our North/South expansion project are subject to PILOT programs.

 

We also receive state tax benefits under New York’s Empire State Development program. In general, we receive a tax credit on CNYOG’s state income tax return for our facilities located in Owego, New York, which are located within a designated Empire Zone. We received a benefit of approximately $3.7 million under this program for calendar year 2010. Beginning with calendar year 2012, our Empire Zone benefits will be phased out over the next four years.

 

Insurance

 

We share insurance coverage with NRGY, for which we will reimburse NRGY’s general partner pursuant to the terms of the omnibus agreement. To the extent NRGY experiences covered losses under the insurance policies, the limit of our coverage for potential losses may be decreased. Our insurance program includes general liability insurance, auto liability insurance, worker’s compensation insurance, and property insurance in amounts which management believes are reasonable and appropriate.

 

Employees

 

We do not have any employees. We will rely on an omnibus agreement with NRGY and certain of its affiliates to provide us with employees needed to carry out our operations.

 

Legal Proceedings

 

We are not a party to any legal proceeding other than legal proceedings arising in the ordinary course of our business. We are also a party to various administrative and regulatory proceedings that have arisen in the ordinary course of our business. Please read “—Regulation—Natural Gas Storage and Transportation Regulation.”

 

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MANAGEMENT

 

Management of Inergy Midstream, L.P.

 

Our general partner will manage our operations and activities on our behalf through its directors and officers, the latter of whom will be employed by NRGY. 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 will oversee our operations. Common unitholders will not be entitled to elect the directors of our general partner, which will all be appointed by the board of directors of NRGY, or directly or indirectly participate in our management or operations. In addition, Holdings GP, the indirect owner of NRGY’s general partner, is required to purchase our general partner under certain circumstances. Please read “Security Ownership of Certain Beneficial Owners and Management.”

 

Our general partner will, however, be accountable to us and our common unitholders as a fiduciary. Fiduciary duties owed to common unitholders by our general partner are prescribed by law and our partnership agreement, which contains various provisions modifying and restricting the fiduciary duties that might otherwise be owed by our general partner. For more information on the fiduciary duties of our general partner, please read “Conflicts of Interest and Fiduciary Duties—Fiduciary Duties.”

 

Upon the completion of this offering, we expect that our general partner will have at least two directors, at least one of whom will be independent as defined under the independence standards established by the NYSE and the Exchange Act. The NYSE does not require a listed publicly traded partnership, such as ours, to have a majority of independent directors on the board of directors of our general partner or to establish a compensation committee or a nominating committee. We are, however, required to have an audit committee of at least three members, and all its members are required to meet the independence and experience standards established by the NYSE and the Exchange Act, subject to certain transitional relief during the one-year period following the completion of this offering.

 

In evaluating director candidates, NRGY will assess whether a candidate possesses the integrity, judgment, knowledge, experience, skill and expertise that are likely to enhance the board’s ability to manage and direct our affairs and business, including, when applicable, to enhance the ability of committees of the board of directors of our general partner to fulfill their duties.

 

The officers of our general partner will be employed by NRGY and will manage the day-to-day affairs of our business. Certain of our officers may devote the majority of their time to our business, while other officers will have responsibilities for both us and NRGY and will devote less than a majority of their time to our business. William R. Moler has historically devoted a majority of his time to Inergy Midstream, LLC. We expect that Mr. Moler will initially devote approximately 75% of his time to our operations. We will also utilize certain employees of NRGY to operate our business and provide us with administrative services.

 

Neither our general partner nor NRGY will 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 will reimburse our general partner and its affiliates, including NRGY, for all expenses they incur and payments they make on our behalf, which we expect to be approximately $5 million for the twelve months ending December 31, 2012. We will enter into an omnibus agreement with NRGY and certain of its affiliates, pursuant to which we will agree upon certain aspects of our relationship with them, including the provision by NRGY to us of certain administrative services and employees, our agreement to reimburse NRGY for the cost of such services and employees, certain indemnification obligations, the use by us of the name “Inergy” and related marks, NRGY’s right to review and first option with respect to business opportunities, and other matters. 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. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us. Please read “Certain Relationships and Related Party Transactions—Agreements with Affiliates in Connection with the Transactions—Omnibus Agreement.” Additionally, the omnibus agreement will not increase or decrease our general partner’s fiduciary duties to us under our partnership agreement. For more information on the fiduciary duties of our general partner, please read “Conflicts of Interest and Fiduciary Duties—Fiduciary Duties.”

 

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Executive Officers and Directors of Our General Partner

 

The following table shows information for the individuals that will serve as executive officers and directors of our general partner upon the completion of this offering. Our directors will hold office until their successors have been elected or qualified or until the earlier of their death, resignation, removal or disqualification. Executive officers will serve at the discretion of the board of directors of our general partner. There are no family relationships among any of the individuals listed below.

 

Name

   Age     

Position with Our General Partner

John J. Sherman(1)(2)

     56       President, Chief Executive Officer and Director

R. Brooks Sherman, Jr.(1)

     45       Executive Vice President and Chief Financial Officer

William R. Moler(1)

     45       Senior Vice President and Chief Operating Officer

 

(1)   Executive officer of NRGY’s general partner.
(2)   Director of NRGY’s general partner.

 

John J. Sherman—President, Chief Executive Officer and Chairman of the Board. Mr. Sherman will serve as our President, Chief Executive Officer and Chairman of the board of directors of our general partner. Mr. Sherman has served as President, Chief Executive Officer and a director of NRGY since March 2001, and of NRGY’s predecessor from 1997 until July 2001. Prior to joining NRGY’s predecessor, Mr. Sherman 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, which is one of the country’s largest retail propane marketers. He also served as President, Chief Executive Officer and director of Inergy Holdings GP, LLC and 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 Chief Executive Officer of NRGY 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 will bring substantial experience and leadership skills to the board of directors of our general partner.

 

R. Brooks Sherman, Jr.—Executive Vice President and Chief Financial Officer. Mr. Brooks Sherman, Jr. (no relation to Mr. John Sherman) will serve as our Executive Vice President and Chief Financial Officer. Mr. Brooks Sherman has served as Executive Vice President of NRGY since September 2007, Senior Vice President of NRGY since September 2002 and Chief Financial Officer of NRGY since March 2001. Mr. Sherman previously served as Vice President of NRGY from March 2001 until September 2002. Mr. Sherman joined NRGY’s predecessor in December 2000 as Vice President and Chief Financial Officer. From 1999 until joining NRGY’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.

 

William R. Moler—Senior Vice President and Chief Operating Officer. Mr. Moler will serve as our Senior Vice President and Chief Operating Officer. Mr. Moler has served as President and Chief Operating Officer—Natural Gas Midstream Operations of NRGY since May 2011, Senior Vice President—Natural Gas Midstream Operations of NRGY since September 2007, Vice President of Midstream Operations of NRGY since 2005 and Director of Midstream Operations of NRGY since 2004. Prior to joining NRGY, Mr. Moler was with Westport Resources Corporation where he served as both General Manager of Marketing and Transportation Services and General Manager of Westport Field Services, LLC. Prior to Westport, Mr. Moler served in various leadership positions at Kinder Morgan, Inc.

 

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Director Independence

 

In accordance with the rules of the NYSE, NRGY must appoint at least one independent director to the board of directors of our general partner prior to the listing of our common units on the NYSE, one additional independent member within three months of that listing, and one additional independent member within 12 months of that listing. NRGY may not have appointed all three independent directors to the board of directors of our general partner by the date our common units first trade on the NYSE.

 

Board Leadership Structure and Role in Risk Oversight

 

Our Chief Executive Officer May Serve as Chairman of the Board. We expect that the board of directors of our general partner will have no policy with respect to the separation of the offices of chairman of the board of directors and chief executive officer; rather, that relationship will be defined and governed by the limited liability company agreement of our general partner, which will permit the coincidence of the offices. Directors of the board of directors of our general partner will be designated or elected by its sole member, NRGY. Accordingly, unlike holders of common stock in a corporation, our common unitholders will have only limited voting rights on matters affecting our business or governance, subject in all cases to any specific unitholder rights contained in our partnership agreement.

 

The management of enterprise-level risk may be defined as the process of identification, management and monitoring of events that present opportunities and risks with respect to creation of value for our common unitholders. We expect that the board of directors of our general partner will delegate to management the primary responsibility for enterprise-level risk management, while the board will retain responsibility for oversight of management in that regard. We expect that management will offer an enterprise-level risk assessment to the board of directors of our general partner at least once every year.

 

Committees of the Board of Directors

 

The board of directors of our general partner will have an audit committee, a conflicts committee and a compensation committee.

 

Audit Committee

 

We are required to have an audit committee of at least three members, and all its members are required to meet the independence and experience standards established by the NYSE and the Exchange Act, subject to certain transitional relief during the one-year period following the completion of this offering as described above. The audit committee of the board of directors of our general partner will assist the board in its oversight of the integrity of our consolidated financial statements and our compliance with legal and regulatory requirements and partnership policies and controls. The audit committee will have the sole authority to (1) retain and terminate our independent registered public accounting firm, (2) approve all auditing services and related fees and the terms thereof performed by our independent registered public accounting firm and (3) pre-approve any non-audit services and tax services to be rendered by our independent registered public accounting firm. The audit committee will also be responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm will be given unrestricted access to the audit committee and our management, as necessary.

 

Conflicts Committee

 

We expect that at least two independent members of the board of directors of our general partner will serve on a conflicts committee to review specific matters that the board believes may involve conflicts of interest (including certain transactions with NRGY). The conflicts committee will determine if the resolution of the conflict of interest is fair and reasonable to us. The members of the conflicts committee may not be officers or

 

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employees of our general partner or directors, officers or employees of its affiliates, including NRGY, and must meet the independence and experience standards established by the NYSE and 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 to be fair and reasonable to us, 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

 

The compensation committee will be responsible for the future administration of our long-term incentive plan and for compensation of our general partner’s non-employee directors.

 

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EXECUTIVE COMPENSATION

 

Compensation Discussion and Analysis

 

Introduction

 

All of our executive officers and other personnel necessary for the management of our business will be employed and compensated by NRGY, subject to reimbursement by us. Our general partner was recently formed; therefore, we incurred no cost or liability with respect to compensation of our executive officers, and our general partner has not accrued any liabilities for management incentive or retirement benefits for our executive officers, for the fiscal year ended September 30, 2010 or for any prior periods.

 

Responsibility and authority for cash compensation-related decisions for our executive officers will reside with the compensation committee of NRGY’s general partner. Our executive officers will manage our business as part of the service provided by NRGY under the omnibus agreement, and the cash compensation for all of our executive officers will be indirectly paid by us through reimbursements to NRGY. The compensation committee of the board of directors of our general partner will be responsible for the future administration of our long-term incentive plan and for compensation of our general partner’s non-employee directors.

 

Certain of our officers may devote the majority of their time to our business, while other officers will have responsibilities for both us and NRGY and will devote less than a majority of their time to our business. William R. Moler has historically devoted a majority of his time to Inergy Midstream, LLC. We expect that Mr. Moler will initially devote approximately 75% of his time to our operations. Because the officers of our general partner will be employees of NRGY, cash compensation will be paid by NRGY and reimbursed by us. The officers of our general partner, as well as the employees of NRGY who provide services to us, may participate in employee benefit plans and arrangements sponsored by NRGY, including plans that may be established in the future. Each of the individuals that we expect to serve as an officer of our general partner is party to an employment agreement with NRGY. Our general partner is not expected to enter into any new employment agreements with any of our officers.

 

Historical Compensation

 

Because our general partner was recently formed and has not accrued any compensation obligations, we are not presenting historical compensation information.

 

Messrs. John J. Sherman, R. Brooks Sherman, Jr. and William R. Moler are executive officers of NRGY’s general partner as described in “Management,” and information relating to their compensation is set forth in NRGY’s annual report on Form 10-K under the heading “Executive Compensation.”

 

Compensation Philosophy and Objectives

 

We will not directly employ any of the persons responsible for managing our business. NRGM GP, LLC, our general partner, will manage our operations and activities, and its board of directors and executive officers will make decisions on our behalf. All of our executive officers will also serve as executive officers of Inergy GP, LLC, the general partner of NRGY. These “shared” officers will receive no additional salary, benefits or other cash compensation for their service to us. However, from time to time they may receive awards of equity in us pursuant to our long-term incentive plan.

 

A full discussion of the compensation programs for NRGY’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 NRGY’s annual report on Form 10-K under the heading “Executive Compensation.”

 

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Long-Term Incentive Plan

 

In connection with this offering, the board of directors of our general partner will adopt a long-term incentive plan for employees, consultants and directors who perform services for us. We expect that the long-term incentive plan will provide for awards of restricted units, unit options, phantom units, unit payments, unit appreciation rights, other equity-based awards, distribution equivalent rights and performance awards. Our long-term incentive plan will limit the number of units that may be delivered pursuant to awards to 10% of the common units then outstanding. Common units withheld to satisfy exercise prices or tax withholding obligations are available for delivery pursuant to other awards. Our long-term incentive plan will be administered by the compensation committee of the board of directors of our general partner, which we refer to as the plan administrator.

 

The plan administrator may terminate or amend our long-term incentive plan at any time with respect to any of our common units for which a grant has not yet been made. The plan administrator also has the right to alter or amend our long-term incentive plan or any part of the plan from time to time, including increasing the number of common units that may be granted, subject to common unitholder approval as required by the exchange upon which our common units are listed at that time. However, no change in any outstanding grant may be made that would materially reduce the benefits of the participant without the consent of the participant. The plan will expire on the tenth anniversary of its approval, when common units are no longer available under the plan for grants or upon its termination by the plan administrator, whichever occurs first.

 

Upon the exercise of a unit option or a unit appreciation right (to the extent the award is settled in common units), or the vesting of a phantom unit (to the extent the award is settled in common units), we may acquire common units on the open market or from any other person or we may directly issue common units or use any combination of the foregoing, in the plan administrator’s discretion. If we issue new common units upon the exercise of a unit option or unit appreciation right, or the vesting of a phantom unit, the total number of common units outstanding will increase.

 

In connection with the closing of this offering, the board of directors of our general partner may grant awards to our key employees and our outside directors pursuant to our long-term incentive plan; however, the board has not yet made any determination as to the number of awards, the type of awards or when the awards would be granted. Certain of our key employees hold grants under NRGY’s long-term incentive plan.

 

Director Compensation

 

The officers or employees of our general partner or of NRGY who also serve as directors of our general partner will not receive additional compensation for their service as a director of our general partner. Directors of our general partner who are not officers or employees of our general partner or of NRGY will receive compensation as set by our general partner’s board of directors. 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.

 

Each director will be indemnified for his actions associated with being a director to the fullest extent permitted under Delaware law.

 

Compensation Committee Interlocks and Insider Participation

 

Our general partner’s board of directors intends to establish a compensation committee, but has yet to do so.

 

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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

 

The following table sets forth the beneficial ownership of our common units that, upon the completion of this offering and the related transactions and assuming that the underwriters do not exercise their option to purchase up to          additional common units, will be owned by:

 

   

each person or group of persons known by us to be a beneficial owner of 5% or more of the then outstanding common units;

 

   

each director of our general partner;

 

   

each executive officer of our general partner; and

 

   

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

 

Name and Address of Beneficial Owner(1)

   Common Units To Be
Beneficially Owned(2)
    Percentage of Common
Units To Be Beneficially Owned
 

Inergy, L.P.

                  (3)          

John J. Sherman(4)

    

R. Brooks Sherman, Jr.

    

William R. Moler

    

All directors and executive officers of our general partner as a group (3 persons)

    

 

*   Less than 1%.
(1)   The address for each person listed above is Two Brush Creek Boulevard, Suite 200, Kansas City, Missouri 64112.
(2)   As of the date of this prospectus, there are no arrangements for any listed beneficial owner to acquire within 60 days common units from options, warrants, rights, conversion privileges or similar obligations.
(3)   Of this amount,          common units will be issued to NRGY at the closing of this offering and up to          common units will be issued to NRGY within 30 days of this offering, assuming the underwriters do not exercise their option to purchase up to an additional          common units. Please read “Summary—The Offering—Common units outstanding after this offering.”
(4)   Mr. Sherman also owns a 14.4% limited partner interest in, and is the chief executive officer and a director of, NRGY. NRGY will have the right to appoint all of the directors of our general partner. Mr. Sherman, who currently is the only voting member of the general partner of Inergy Holdings, L.P., has the authority to appoint all of the directors of NRGY’s general partner.

 

NRGM GP, LLC Change of Control Event

 

In connection with this offering, in the event of a change of control of NRGY, NRGY and Holdings GP, the indirect owner of NRGY’s general partner, expect to enter into an agreement under which Holdings GP will be required to purchase from NRGY, and NRGY 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 NRGY 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 incentive distribution rights. Under the agreement, Holdings GP is also required to purchase MGP GP, LLC in the event that (i) a change of control of NRGY occurs at a time when NRGY is entitled to receive less than 50% of all cash distributed with respect to our limited partner interests and incentive distribution rights or (ii) through dilution or a distribution to the NRGY common unitholders of NRGY’s interests in us, NRGY is entitled to receive less than 25% of all cash distributed with respect to our limited partner interests and incentive distribution rights. Any such transaction must comply with the restrictions in any law, regulation or agreement then in effect and must not require NRGY to have to register as an investment company under the Investment Company Act of 1940.

 

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

 

After this offering, assuming that the underwriters do not exercise their option to purchase additional common units, NRGY will own, directly or indirectly, approximately     % of our common units and all of the incentive distribution rights and will own and control our general partner, which will maintain a non-economic general partner interest in us. NRGY will also appoint all of the directors of our general partner.

 

Distributions and Payments to Our General Partner and Its Affiliates

 

The following table summarizes the distributions and payments to be made by us to our general partner and its affiliates in connection with the formation, ongoing operation and any liquidation of Inergy Midstream, L.P. These distributions and payments were determined by and among affiliated entities.

 

Formation Stage

 

The aggregate consideration received by our general partner and its affiliates for the contribution of their interests

 

         common units;

 

   

a non-economic general partner interest;

 

   

our incentive distribution rights;

 

   

our assumption of approximately $         million of indebtedness from NRGY under a $         million revolving credit facility that will be assigned to us of which we will repay $         million using net proceeds from this offering.

 

   

we expect to re-borrow $80 million under our revolving credit facility to fund a cash distribution to NRGY for reimbursement of capital expenditures associated with our assets; and

 

   

the extinguishment of all indebtedness that we owe to a subsidiary of NRGY, which will be treated as a capital contribution by NRGY to us and which was approximately $121.5 million as of August 31, 2011.

 

Operational Stage

 

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          common units. Our general partner will not receive cash distributions on its non-economic general partner interest. If distributions exceed the initial quarterly distribution of $         per unit, NRGY will be entitled to 50.0% of our cash distributions above the initial quarterly distribution level in respect of its incentive distribution rights.

 

  Assuming we have sufficient available cash to pay the full initial quarterly distribution on all of our outstanding common units for four quarters, NRGY would receive an annual distribution of approximately $         million on its common units.

 

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  If NRGY elects to reset the initial quarterly distribution, it will be entitled to receive newly issued common units. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions—NRGY’s Right to Reset Incentive Distribution Level.”

 

Payments to our general partner and its affiliates

Neither our general partner nor NRGY will 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 will reimburse our general partner and its affiliates, including NRGY, for all expenses they incur and payments they make on our behalf, which we expect to be approximately $5 million for the twelve months ending December 31, 2012. We will enter into an omnibus agreement with NRGY and certain of its affiliates, pursuant to which we will agree upon certain aspects of our relationship with them, including the provision by NRGY to us of certain administrative services and employees, our agreement to reimburse NRGY for the cost of such services and employees, certain indemnification obligations, the use by us of the name “Inergy” and related marks, NRGY’s right to review and first option with respect to business opportunities, and other matters. 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. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us. Please read “—Agreements with Affiliates in Connection with the Transactions—Omnibus Agreement.”

 

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. Please read “The Partnership Agreement—Withdrawal or Removal of Our General Partner.”

 

Liquidation Stage

 

Liquidation

Upon our liquidation, our partners will be entitled to receive liquidating distributions according to their particular capital account balances.

 

Agreements with Affiliates in Connection with the Transactions

 

We have entered into or will enter into various documents and agreements with NRGY that will effect the transactions relating to our formation and this offering, including the vesting of assets in, and the assumption of liabilities by, us and our subsidiaries. We believe the terms of these agreements are or will be no less favorable to either party than those that could have been negotiated with an unaffiliated party; however, these agreements have been or will be negotiated among affiliated parties. All of the transaction expenses incurred in connection with our formation transactions will be paid from the proceeds of this offering.

 

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Omnibus Agreement

 

In connection with the closing of this offering, we will enter into an omnibus agreement with our general partner and NRGY that will address certain aspects of our relationship with them, including:

 

   

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

 

   

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

 

   

certain indemnification obligations;

 

   

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

 

   

NRGY’s right to review and first option with respect to business opportunities.

 

With respect to the provision by NRGY of certain administrative services and such management and operating services as may be necessary to manage and operate our business, the omnibus agreement will address certain aspects of our relationship with NRGY, which we expect will include:

 

   

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

 

   

our agreement to reimburse NRGY for all expenses it incurs as a result of us becoming a publicly traded partnership, including (but not limited to) expenses associated with annual and quarterly reporting, tax returns and Schedule K-1 preparation and distribution expenses, Sarbanes-Oxley compliance expenses, expenses associated with listing on the NYSE, independent auditor fees, legal fees, investor relation expenses and registrar and transfer fees; and

 

   

our agreement to reimburse NRGY for all expenses that NRGY incurs or payments NRGY 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. We expect, however, that these services will be provided at cost.

 

Pursuant to the omnibus agreement, NRGY will have the right to review and has the first option on any business opportunities that are presented to us. Although NRGY is under no obligation to make business opportunities available to us, NRGY has, and will have upon completion of this offering, a significant economic stake in us and a strong incentive to support our growth.

 

Contribution Agreement

 

Immediately prior to the closing of this offering, we will enter into a contribution, conveyance and assignment agreement, which we refer to as the contribution agreement, with NRGY and our general partner under which, among other things, we will transfer or distribute to NRGY or one of its subsidiaries certain assets that will not be part of our initial assets, including 100% of the membership interests in Tres Palacios Gas Storage LLC and US Salt.

 

In addition, Inergy Propane, a wholly owned subsidiary of NRGY, will assign to us a third-party storage contract under which the unaffiliated third party has contracted for two million barrels of future storage services at our Watkins Glen facility under development. Prior to this offering, Inergy Propane had marketed this future storage capacity and entered into this third-party contract on our behalf. The approximate value of this contract over the five-year term is $35.0 million.

 

We will also grant NRGY the right to receive the net proceeds from any exercise of the underwriters’ option to purchase additional common units as well as the right to receive any common units subject to such option which are not purchased by the underwriters upon the expiration of the option period.

 

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Tax Sharing Agreement

 

In connection with the closing of this offering, we will enter into a tax sharing agreement with NRGY pursuant to which we will reimburse NRGY for our share of state and local income and other taxes borne by NRGY as a result of our income being included in a combined or consolidated tax return filed by NRGY with respect to taxable periods including or beginning on the closing date of this offering. The amount of any such 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 NRGY. NRGY 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 NRGY for the tax we would have owed had the attributes not been available or used for our benefit, even though NRGY had no cash expense for that period.

 

NRGM GP, LLC Change of Control Event

 

In connection with this offering, in the event of a change of control of NRGY, NRGY and Holdings GP, the indirect owner of NRGY’s general partner, expect to enter into an agreement under which Holdings GP will be required to purchase from NRGY, and NRGY 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 NRGY 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 incentive distribution rights. Under the agreement, Holdings GP is also required to purchase MGP GP, LLC in the event that (i) a change of control of NRGY occurs at a time when NRGY is entitled to receive less than 50% of all cash distributed with respect to our limited partner interests and incentive distribution rights or (ii) through dilution or a distribution to the NRGY common unitholders of NRGY’s interests in us, NRGY is entitled to receive less than 25% of all cash distributed with respect to our limited partner interests and incentive distribution rights. Any such transaction must comply with the restrictions in any law, regulation or agreement then in effect and must not require NRGY to have to register as an investment company under the Investment Company Act of 1940.

 

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 Propane, under a five-year contract entered into in March 2011. The annual storage fee will be $13.1 million. The terms and conditions of the storage contract are consistent with the terms and conditions of the storage leases that Inergy Propane has entered into with third parties. We received total revenues from Inergy Propane of $0.1 million and $0.5 million for the fiscal years ended September 30, 2009 and 2010, respectively, and $2.2 million for the nine months ended June 30, 2011.

 

As of August 31, 2011, we had approximately $121.5 million of indebtedness outstanding to Inergy Propane, which is subject to interest during the period of construction of our expansion projects. For the fiscal year ended September 30, 2010, the largest aggregate amount of principal outstanding and the amount of principal paid on indebtedness outstanding to Inergy Propane were $133.6 million and $90.8 million, respectively. This intercompany indebtedness was incurred to support our capital expansion and working capital needs. In connection with the completion of this offering, we expect that all of our outstanding indebtedness with NRGY or its subsidiaries will be extinguished and treated as a capital contribution and part of NRGY’s investment in us. Please read “Summary—Formation Transactions and Partnership Structure” and “Use of Proceeds.”

 

For information regarding our historical related party transactions, please read (i) Notes 2 and 8 to our audited consolidated financial statements as of September 30, 2009 and 2010 and for the fiscal years ended September 30, 2008, 2009 and 2010 that are included elsewhere in this prospectus and (ii) Notes 2 and 5 to our unaudited consolidated financial statements as of June 30, 2011 and for the nine months ended June 30, 2010 and 2011 that are included elsewhere in this prospectus.

 

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Procedures for Review, Approval and Ratification of Transactions with Related Persons

 

We expect that the board of directors of our general partner will adopt policies for the review, approval and ratification of transactions with related persons. We anticipate the board will adopt a written code of business conduct and ethics, under which a director would be expected to bring to the attention of the chief executive officer or the board any conflict or potential conflict of interest that may arise between the director or any affiliate of the director, on the one hand, and us or our general partner, on the other hand. The resolution of any such conflict or potential conflict should, at the discretion of the board in light of the circumstances, be determined by a majority of the disinterested directors.

 

If a conflict or potential conflict of interest arises between our general partner or its affiliates, on the one hand, and us and our limited partners, on the other hand, 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 our partnership agreement.

 

Upon our adoption of our code of business conduct and ethics, we would expect that any executive officer of our general partner will be required to avoid conflicts of interest unless approved by the board.

 

In the case of any sale of equity by us in which an owner or affiliate of an owner of our general partner participates, we anticipate that our practice will be to obtain approval of the board for the transaction. We anticipate that the board will typically delegate authority to set the specific terms to a pricing committee, consisting of the chief executive officer and one independent director. Actions by the pricing committee will require unanimous approval. Please read “Conflicts of Interest and Fiduciary Duties—Conflicts of Interest” for additional information regarding the relevant provisions of our partnership agreement.

 

The code of business conduct and ethics described above will be adopted in connection with the closing of this offering, and as a result the transactions described above were not reviewed according to such procedures.

 

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CONFLICTS OF INTEREST AND FIDUCIARY DUTIES

 

Conflicts of Interest

 

Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its affiliates, including NRGY, on the one hand, and our partnership and our limited partners, on the other hand. The directors and officers of our general partner have fiduciary duties to manage our general partner in a manner beneficial to its owner. At the same time, our general partner has a fiduciary duty to manage our partnership in a manner beneficial to us and our common unitholders.

 

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, our general partner will resolve that conflict. Our partnership agreement contains provisions that modify and limit our general partner’s fiduciary duties to our common unitholders. Our partnership agreement also restricts the remedies available to our common unitholders for actions taken by our general partner that, without those limitations, might constitute breaches of its fiduciary duty.

 

Our general partner will not be in breach of its obligations under our partnership agreement or its fiduciary duties to us or our limited partners if a transaction with an affiliate or the resolution of a conflict of interest is:

 

   

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

 

   

approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner and any of its affiliates.

 

Conflicts of interest could arise in the situations described below, among others.

 

NRGY 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 NRGY, are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us. NRGY 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, NRGY is entitled under the omnibus agreement to review and has the first option on any third-party acquisition opportunities 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, NRGY may compete with us for investment opportunities, and NRGY may own an interest in entities that compete with us.

 

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 NRGY. 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.

 

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Neither our partnership agreement nor any other agreement requires NRGY to pursue a business strategy that favors us or utilizes our assets or dictates what markets to pursue or grow. Directors of the general partner of NRGY have a fiduciary duty to make these decisions in the best interests of the owners of NRGY, which may be contrary to our interests.

 

Because one or more of the directors of our general partner may be directors and/or officers of NRGY’s general partner, such directors have fiduciary duties to NRGY that may cause them to pursue business strategies that disproportionately benefit NRGY or which otherwise are not in our best interests.

 

Certain of our officers may devote the majority of their time to our business, while other officers will have responsibilities for both us and NRGY and will devote less than a majority of their time to our business.

 

All of the executive officers of our general partner are also executive officers of NRGY’s general partner. Certain of our officers may devote the majority of their time to our business, while other officers will have responsibilities for both us and NRGY and will devote less than a majority of their time to our business. We will also utilize certain employees of NRGY to operate our business and provide us with administrative services for which we will reimburse NRGY under the omnibus agreement for expenses of operational personnel who perform services for our benefit and for allocated administrative expenses. Please read “Certain Relationships and Related Party Transactions—Agreements with Affiliates in Connection with the Transactions—Omnibus Agreement.” NRGY will also conduct businesses and activities of its own in which we will have no economic interest. If these separate activities are significantly greater than our activities, there could be material competition for the time and effort of the executive officers of our general partner.

 

Our general partner and its affiliates are allowed to take into account the interests of parties other than us in resolving conflicts of interest.

 

Our partnership agreement contains provisions that reduce the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law. 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. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited partners. Examples include our general partner’s limited call right, its voting rights with respect to any units it owns, its registration rights, and its determination whether or not to consent to any merger or consolidation of the partnership.

 

Our partnership agreement limits the liability of and reduces fiduciary duties owed by our general partner and also restricts the remedies available to our common unitholders for actions that, without the limitations, might 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 fiduciary duty under state fiduciary duty law. For example, our partnership agreement provides that:

 

   

whenever our general partner makes a determination or takes, or declines to take, any other action in its capacity as our general partner, our general partner is required to make such determination, or take or decline to take such other action, in good faith, meaning that it believed that the decision was in the best interests of our partnership, and will not be subject to any other or different standard imposed by our partnership agreement, Delaware law or any other law, rule or regulation, or at equity; and

 

   

our general partner will 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.

 

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Except in limited circumstances, our general partner has the power and authority to conduct our business without common unitholder approval.

 

Under our partnership agreement, our general partner has full power and authority to do all things, other than those items that require common unitholder approval or with respect to which our general partner has sought conflicts committee approval, on such terms as it determines to be necessary or appropriate to conduct our business, including, but not limited to, the following:

 

   

the making of any expenditures, the lending or borrowing of money, the assumption or guarantee of or other contracting for, indebtedness and other liabilities, the issuance of evidences of indebtedness, including indebtedness that is convertible into our securities, and the incurring of any other obligations;

 

   

the purchase, sale or other acquisition or disposition of our securities, or the issuance of additional options, rights, warrants and appreciation rights relating to our securities;

 

   

the acquisition, disposition, mortgage, pledge, encumbrance, hypothecation or exchange of any or all of our assets;

 

   

the negotiation, execution and performance of any contracts, conveyances or other instruments;

 

   

the distribution of our cash;

 

   

the selection and dismissal of employees and agents, outside attorneys, accountants, consultants and contractors and the determination of their compensation and other terms of employment or hiring;

 

   

the maintenance of insurance for our benefit and the benefit of our partners;

 

   

the formation of, or acquisition of an interest in, the contribution of property to, and the making of loans to, any limited or general partnership, joint venture, corporation, limited liability company or other entity;

 

   

the control of any matters affecting our rights and obligations, including the bringing and defending of actions at law or in equity, otherwise engaging in the conduct of litigation, arbitration or mediation and the incurring of legal expenses and the settlement of claims and litigation;

 

   

the indemnification of any person against liabilities and contingencies to the extent permitted by law;

 

   

the making of tax, regulatory and other filings, or the rendering of periodic or other reports to governmental or other agencies having jurisdiction over our business or assets; and

 

   

the entering into of agreements with any of its affiliates to render services to us or to itself in the discharge of its duties as our general partner.

 

Our partnership agreement provides that our general partner must act in good faith when making decisions on our behalf, and our partnership agreement further provides that in order for a determination to be made in good faith, our general partner must believe that the determination is in our best interests. Please read “The Partnership Agreement—Limited Voting Rights” for information regarding matters that require common unitholder approval.

 

Our general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings, issuances of additional partnership securities and the creation, reduction or increase of reserves, each of which can affect the amount of cash that is distributed to our common unitholders.

 

The amount of cash that is available for distribution to our common unitholders is affected by decisions of our general partner regarding such matters as:

 

   

amount and timing of asset purchases and sales;

 

   

capital expenditures;

 

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borrowings;

 

   

issuances of additional partnership securities; and

 

   

the creation, reduction or increase of reserves in any quarter.

 

Our general partner determines the amount and timing of any capital expenditure and whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions—Capital Expenditures” for a discussion on when a capital expenditure constitutes a maintenance capital expenditure or an expansion capital expenditure. This determination can affect the amount of cash that is distributed to our common unitholders and to NRGY in respect of its incentive distribution rights.

 

In addition, our general partner may use an amount, initially equal to $         million, which would not otherwise constitute available cash from operating surplus, in order to permit the payment of cash distributions on NRGY’s incentive distribution rights. All of these actions may affect the amount of cash distributed to our common unitholders and NRGY in respect of its incentive distribution rights. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions.”

 

In addition, borrowings by us and our affiliates do not constitute a breach of any duty owed by our general partner to our common unitholders, including borrowings that have the purpose or effect of enabling NRGY or its affiliates to receive distributions on any units held by them or the incentive distribution rights. For example, in the event we have not generated sufficient cash from our operations to pay the initial quarterly distribution on our common units, our partnership agreement permits us to borrow funds, which would enable us to make this distribution on all of our outstanding common units. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions.”

 

Our partnership agreement provides that we and our subsidiaries may borrow funds from our general partner and its affiliates. However, our partnership agreement does not permit our general partner and its affiliates to borrow funds from us or our subsidiaries.

 

Our general partner determines which costs incurred by it and its affiliates are reimbursable by us.

 

We will reimburse our general partner and its affiliates for the costs incurred in managing and operating us, including costs incurred in rendering corporate staff and support services to us. 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. Our partnership agreement provides that our general partner will determine in good faith such other expenses that are allocable to us. The fully allocated basis charged by our general partner does not include a profit component. Please read “Certain Relationships and Related Party Transactions.”

 

Our partnership agreement allows our general partner to determine, in good faith, any amounts to pay itself or its affiliates for any services rendered to us. Our general partner may also enter into additional contractual arrangements with any of its affiliates on our behalf. We have entered into or will enter into various documents and agreements with NRGY that will effect the transactions relating to our formation and this offering, including the vesting of assets in, and the assumption of liabilities by, us and our subsidiaries. We believe the terms of these agreements are or will be no less favorable to either party than those that could have been negotiated with an unaffiliated party; however, these agreements have been or will be negotiated among affiliated parties. Similarly, agreements, contracts or arrangements between us and our general partner and its affiliates that are entered into following the closing of this offering will be negotiated among affiliated parties, although our general partner may determine that the conflicts committee of the board of directors of our general partner should make a determination on our behalf with respect to such arrangements.

 

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Our general partner will determine, in good faith, the terms of any such transactions entered into after the closing of this offering.

 

Our general partner and its affiliates will have no obligation to permit us to use any of its or its affiliates’ facilities or assets, except as may be provided in contracts entered into specifically for such use. There is no obligation of our general partner or its affiliates to enter into any contracts of this kind.

 

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

 

Our general partner intends to limit its liability under contractual arrangements so that counterparties to such arrangements have recourse only against our assets, and not against our general partner or its assets. 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 fiduciary duties, even if we could have obtained more favorable terms without the limitation on liability.

 

Our general partner may exercise its right to call and purchase all of the common units not owned by it and its affiliates if our general partner and its affiliates own more than     % of the outstanding common units.

 

Our general partner may exercise its right to call and purchase common units, as provided in our partnership agreement, or may assign this right to one of its affiliates or to us. Our general partner is not bound by fiduciary duty restrictions in determining whether to exercise this right. As a result, a common unitholder may be required to sell its common units at an undesirable time or price. Please read “The Partnership Agreement—Limited Call Right.”

 

Our general partner controls the enforcement of its and its affiliates’ obligations to us.

 

Any agreements between us, on the one hand, and our general partner and its affiliates, on the other hand, will not grant to the common unitholders, separate and apart from us, the right to enforce the obligations of our general partner and its affiliates in our favor.

 

Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

 

Attorneys, independent accountants and others who perform services for us are selected by our general partner or the conflicts committee and may perform services for our general partner and its affiliates. We may retain separate counsel for ourselves or the common unitholders in the event of a conflict of interest between our general partner and its affiliates, on the one hand, and us or the common unitholders, on the other hand, depending on the nature of the conflict. We do not intend to do so in most cases.

 

NRGY may elect to cause us to issue common units to it in connection with a resetting of the initial quarterly distribution related to its incentive distribution rights, 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.

 

NRGY has the right to reset, at a higher level, the initial quarterly distribution based on our cash distributions at the time of the exercise of the reset election. Following a reset election by NRGY, the initial quarterly distribution will be adjusted to equal the reset initial quarterly distribution.

 

If NRGY elects to reset the initial quarterly distribution, it will be entitled to receive a number of newly issued common units. The number of common units to be issued to NRGY 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 NRGY on its incentive distribution rights in such prior quarter. It is possible that NRGY could exercise this reset election at a time when it is experiencing, or expects to experience, declines in the cash

 

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distributions it receives related to its incentive distribution rights and may, therefore, desire to be issued common units rather than retain the right to receive incentive distributions based on the initial 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 NRGY in connection with resetting the initial quarterly distribution. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions—NRGY’s Right to Reset Incentive Distribution Level.”

 

Fiduciary Duties

 

Our general partner is accountable to us and our common unitholders as a fiduciary. Fiduciary duties owed to common unitholders by our general partner are prescribed by law and our partnership agreement. The Delaware Act provides that Delaware limited partnerships may, in their partnership agreements, modify, restrict or expand the fiduciary duties otherwise owed by a general partner to limited partners and the partnership.

 

Our partnership agreement contains various provisions modifying and restricting the fiduciary duties that might otherwise be owed by our general partner. We have adopted these restrictions to allow our general partner or its affiliates to engage in transactions with us that would otherwise be prohibited by state-law fiduciary duty standards and to take into account the interests of other parties in addition to our interests when resolving conflicts of interest. We believe this is appropriate and necessary because our general partner’s board of directors will have fiduciary duties to manage our general partner in a manner that is beneficial to its owners, as well as to our common unitholders. Without these modifications, our general partner’s ability to make decisions involving conflicts of interest would be restricted. The modifications to the fiduciary standards enable our general partner to take into consideration all parties involved in the proposed action, so long as the resolution is fair and reasonable to us. These modifications also enable our general partner to attract and retain experienced and capable directors. These modifications are detrimental to our common unitholders because they restrict the remedies available to our common unitholders for actions that, without those limitations, might constitute breaches of fiduciary duty, as described below, and permit our general partner to take into account the interests of third parties in addition to our interests when resolving conflicts of interest. The following is a summary of the material restrictions of the fiduciary duties owed by our general partner to our limited partners:

 

State law fiduciary duty standards

Fiduciary duties are generally considered to include an obligation to act in good faith and with due care and loyalty. The duty of care, in the absence of a provision in a partnership agreement providing otherwise, would generally require a general partner to act for the partnership in the same manner as a prudent person would act on his own behalf. The duty of loyalty, in the absence of a provision in a partnership agreement providing otherwise, would generally require that any action taken or transaction engaged in be entirely fair to the partnership.

 

Partnership agreement modified standards

Our partnership agreement contains provisions that waive or consent to conduct by our general partner and its affiliates that might otherwise raise issues about compliance with fiduciary duties or applicable law. For example, our partnership agreement provides that when our general partner is acting in its capacity as our general partner, as opposed to in its individual capacity, it must act in good faith and will not be subject to any other standard under applicable law. In addition, when our general partner is acting in its individual capacity, as opposed to in its capacity as our general partner, it may act without any fiduciary obligation to us or the common unitholders whatsoever. These standards reduce the obligations to which our general partner would otherwise be held.

 

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Rights and remedies of common unitholders

The Delaware Act generally provides that a limited partner may institute legal action on behalf of the partnership to recover damages from a third party where a general partner has refused to institute the action or where an effort to cause a general partner to do so is not likely to succeed. These actions include actions against a general partner for breach of its fiduciary duties or of our partnership agreement. In addition, the statutory or case law of some jurisdictions may permit a limited partner to institute legal action on behalf of itself and all other similarly situated limited partners to recover damages from a general partner for violations of its fiduciary duties to the limited partners.

 

Partnership agreement modified standard

In addition to the other more specific provisions limiting the obligations of our general partner, our partnership agreement further provides that our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners for errors of judgment or for any acts or omissions unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that our general partner or its officers and directors acted in bad faith or engaged in fraud or willful misconduct.

 

By purchasing our common units, each common unitholder automatically agrees to be bound by the provisions in our partnership agreement, including the provisions discussed above. This is in accordance with the policy of the Delaware Act favoring the principle of freedom of contract and the enforceability of partnership agreements. The failure of a limited partner to sign a partnership agreement does not render the partnership agreement unenforceable against that person.

 

Indemnification

 

Under our partnership agreement, we must indemnify our general partner and its officers, directors, managers and certain other specified persons, to the fullest extent permitted by law, against liabilities, costs and expenses incurred by our general partner or these other persons. We must provide this indemnification unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that these persons acted in bad faith or engaged in fraud or willful misconduct. We must also provide this indemnification for criminal proceedings unless our general partner or these other persons acted with knowledge that their conduct was unlawful. Thus, our general partner could be indemnified for its negligent acts if it meets the requirements set forth above. To the extent these provisions purport to include indemnification for liabilities arising under the Securities Act of 1933, as amended, or the Securities Act, in the opinion of the SEC, such indemnification is contrary to public policy and, therefore, unenforceable. Please read “The Partnership Agreement—Indemnification.”

 

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DESCRIPTION OF THE COMMON UNITS

 

The Common Units

 

The common units represent limited partner interests in us. The holders of common units are entitled to participate in partnership distributions and exercise the rights or privileges available to limited partners under our partnership agreement. For a description of the relative rights and preferences of holders of common units in and to partnership distributions, please read this section and “Cash Distribution Policy and Restrictions on Distributions.” For a description of other rights and privileges of limited partners under our partnership agreement, including voting rights, please read “The Partnership Agreement.”

 

Transfer Agent and Registrar

 

Duties

 

American Stock Transfer & Trust Company, LLC will serve as the registrar and transfer agent for the common units. We will pay all fees charged by the transfer agent for transfers of common units except the following, which must be paid by our common unitholders:

 

   

surety bond premiums to replace lost or stolen certificates, taxes and other governmental charges;

 

   

special charges for services requested by a holder of a common unit; and

 

   

other similar fees or charges.

 

There will be no charge to our common unitholders for disbursements of our cash distributions. We will indemnify each of the transfer agent, its agents and their respective stockholders, directors, officers and employees against all claims and losses that may arise out of acts performed or omitted for its activities in that capacity, except for any liability due to any gross negligence or intentional misconduct of the indemnified person or entity.

 

Resignation or Removal

 

The transfer agent may resign, by notice to us, or be removed by us. The resignation or removal of the transfer agent will become effective upon our appointment of a successor transfer agent and registrar and its acceptance of the appointment. If no successor is appointed, our general partner may act as the transfer agent and registrar until a successor is appointed.

 

Transfer of Common Units

 

Upon the transfer of a common unit in accordance with our partnership agreement, the transferee of the common unit will be admitted as a limited partner with respect to the common units transferred when such transfer and admission are reflected in our books and records. Each transferee:

 

   

represents that the transferee has the capacity, power and authority to become bound by our partnership agreement;

 

   

automatically becomes bound by the terms and conditions of, and is deemed to have executed, our partnership agreement; and

 

   

gives the consents, waivers and approvals contained in our partnership agreement, such as the approval of all transactions and agreements that we are entering into in connection with our formation and this offering.

 

In addition to other rights acquired upon transfer, the transferor gives the transferee the right to become a substituted limited partner in our partnership for the transferred common units. A transferee will become a substituted limited partner of our partnership for the transferred common units automatically upon the

 

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recording of the transfer on our books and records. Our general partner will cause any transfers to be recorded on our books and records no less frequently than quarterly.

 

Until a common unit has been transferred on our books, we and the transfer agent may treat the record holder of the common unit as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations.

 

We may, at our discretion, treat the nominee holder of a common unit as the absolute owner. In that case, the beneficial holder’s rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.

 

Common units are securities, and any transfers of common units are subject to the laws governing the transfer of securities.

 

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THE PARTNERSHIP AGREEMENT

 

The following is a summary of the material provisions of our partnership agreement. The form of our partnership agreement is included in this prospectus as Appendix A. We will provide prospective investors with a copy of our partnership agreement upon request at no charge.

 

We summarize the following provisions of our partnership agreement elsewhere in this prospectus:

 

   

with regard to distributions of available cash, please read “Provisions of Our Partnership Agreement Relating to Cash Distributions”;

 

   

with regard to the fiduciary duties of our general partner, please read “Conflicts of Interest and Fiduciary Duties”;

 

   

with regard to the transfer of common units, please read “Description of the Common Units—Transfer of Common Units”; and

 

   

with regard to allocations of taxable income and taxable loss, please read “Material U.S. Federal Income Tax Consequences.”

 

Organization and Duration

 

Prior to the closing of this offering, Inergy Midstream, LLC will convert from a Delaware limited liability company to a Delaware limited partnership and change its name to Inergy Midstream, L.P. Inergy Midstream, L.P. will have a perpetual existence unless terminated pursuant to the terms of its partnership agreement.

 

Purpose

 

Our purpose under our partnership agreement is to engage in any business activity that is approved by our general partner and that lawfully may be conducted by a limited partnership organized under Delaware law. However, our general partner may not cause us to engage in any business activity that it determines would cause us to be treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes.

 

Although our general partner has the ability to cause us and our subsidiaries to engage in activities other than the business of the operation, development and acquisition of natural gas and NGL storage and transportation assets and related assets, our general partner may decline to do so free of any fiduciary duty or obligation whatsoever to us or our limited partners, including any duty to act in good faith or in the best interests of us or our limited partners. Our general partner is generally authorized to perform all acts it determines to be necessary or appropriate to carry out our purposes and to conduct our business.

 

Cash Distributions

 

Our partnership agreement specifies the manner in which we will make cash distributions to holders of our common units and other partnership securities as well as to IDR holders in respect of the incentive distribution rights. For a description of these cash distribution provisions, please read “Provisions of Our Partnership Agreement Relating to Cash Distributions.”

 

Capital Contributions

 

Common unitholders are not obligated to make additional capital contributions, except as described below under “—Limited Liability.”

 

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Limited Voting Rights

 

The following is a summary of the unitholder vote required for each of the matters specified below. Matters that require the approval of a “unit majority” require the approval of a majority of the common units.

 

In voting their common units, our general partner and its affiliates will have no fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us or the limited partners. The incentive distribution rights may be entitled to vote in certain circumstances.

 

Issuance of additional units

No approval right. Please read “—Issuance of Additional Interests.”

 

Amendment of the partnership agreement

Certain amendments may be made by our general partner without the approval of the common unitholders. Other amendments generally require the approval of a unit majority. Please read “—Amendment of the Partnership Agreement.”

 

Merger of our partnership or the sale of all or substantially all of our assets

Unit majority in certain circumstances. Please read “—Merger, Consolidation, Conversion, Sale or Other Disposition of Assets.”

 

Dissolution of our partnership

Unit majority. Please read “—Dissolution.”

 

Continuation of our business upon dissolution

Unit majority. Please read “—Dissolution.”

 

Withdrawal of our general partner

No approval right. Please read “—Withdrawal or Removal of Our General Partner.”

 

Removal of our general partner

Not less than 66 2/3% of the outstanding common units, including common units held by our general partner and its affiliates. Please read “—Withdrawal or Removal of Our General Partner.”

 

Transfer of our general partner interest

No approval right. Please read “—Transfer of General Partner Interest.”

 

Transfer of incentive distribution rights

No approval right. Please read “—Transfer of Incentive Distribution Rights.”

 

Transfer of ownership interests in our general partner

No approval right. Please read “—Transfer of Ownership Interests in the General Partner.”

 

If any person or group other than our general partner and its affiliates acquires beneficial ownership of 20% or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply to any person or group that acquires the units from our general partner or its affiliates and any transferees of that person or group approved by our general partner or to any person or group who acquires the units with the specific prior approval of our general partner.

 

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Applicable Law; Forum, Venue and Jurisdiction

 

Our partnership agreement is governed by Delaware law. Our partnership agreement requires that any claims, suits, actions or proceedings:

 

   

arising out of or relating in any way to the partnership agreement (including any claims, suits, actions or proceedings to interpret, apply or enforce the provisions of our partnership agreement or the duties, obligations or liabilities among limited partners or of limited partners to us, or the rights or powers of, or restrictions on, the limited partners or us);

 

   

brought in a derivative manner on our behalf;

 

   

asserting a claim of breach of a fiduciary duty owed by any director, officer or other employee of us or our general partner, or owed by our general partner, to us or the limited partners;

 

   

asserting a claim arising pursuant to any provision of the Delaware Act; or

 

   

asserting a claim governed by the internal affairs doctrine;

 

shall be exclusively brought in the Court of Chancery of the State of Delaware, regardless of whether such claims, suits, actions or proceedings sound in contract, tort, fraud or otherwise, are based on common law, statutory, equitable, legal or other grounds, or are derivative or direct claims. By purchasing a common unit, a limited partner is irrevocably consenting to these limitations and provisions regarding claims, suits, actions or proceedings and submitting to the exclusive jurisdiction of the Court of Chancery of the State of Delaware in connection with any such claims, suits, actions or proceedings.

 

Limited Liability

 

Assuming that a limited partner does not participate in the control of our business within the meaning of the Delaware Act and that it otherwise acts in conformity with the provisions of our partnership agreement, such limited partner’s liability under the Delaware Act will be limited, subject to possible exceptions, to the amount of capital such limited partner is obligated to contribute to us for its common units plus its share of any undistributed profits and assets. If it were determined, however, that the right, or exercise of the right, by our limited partners as a group:

 

   

to remove or replace our general partner;

 

   

to approve some amendments to our partnership agreement; or

 

   

to take other action under our partnership agreement;

 

constituted “participation in the control” of our business for the purposes of the Delaware Act, then our limited partners could 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. While this does not mean that a limited partner could not seek legal recourse, we know of no precedent for this type of a claim in Delaware case law.

 

Under the Delaware Act, a limited partnership may not make a distribution to a partner if, after the distribution, all liabilities of the limited partnership, other than liabilities to partners on account of their partnership interests and liabilities for which the recourse of creditors is limited to specific property of the partnership, would exceed the fair value of the assets of the limited partnership. For the purpose of determining the fair value of the assets of a limited partnership, the Delaware Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited partnership only to the extent that the fair value of that property exceeds the nonrecourse liability. The Delaware

 

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Act provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of the Delaware Act shall be liable to the limited partnership for the amount of the distribution for three years.

 

Following the completion of this offering, we expect that our subsidiaries will conduct business in New York and Pennsylvania, and we may have subsidiaries that conduct business in other states or countries in the future. Maintenance of our limited liability as owner of our operating subsidiaries may require compliance with legal requirements in the jurisdictions in which the operating subsidiaries conduct business, including qualifying our subsidiaries to do business there.

 

Limitations on the liability of members or limited partners for the obligations of a limited liability company or limited partnership have not been clearly established in many jurisdictions. If, by virtue of our ownership interest in our subsidiaries or otherwise, it were determined that we were conducting business in any jurisdiction without compliance with the applicable limited liability company or limited partnership statute, or that the right or exercise of the right by our limited partners as a group to remove or replace our general partner, to approve some amendments to our partnership agreement, or to take other action under our partnership agreement constituted “participation in the control” of our business for purposes of the statutes of any relevant jurisdiction, then our limited partners could be held personally liable for our obligations under the law of that jurisdiction to the same extent as our general partner under the circumstances. We will operate in a manner that our general partner considers reasonable and necessary or appropriate to preserve the limited liability of our limited partners.

 

Issuance of Additional Interests

 

Our partnership agreement authorizes us to issue an unlimited number of additional partnership interests for the consideration and on the terms and conditions determined by our general partner without the approval of the common unitholders.

 

It is possible that we will fund acquisitions through the issuance of additional common units or other partnership interests. Holders of any additional common units we issue will be entitled to share equally with the then-existing common unitholders in our distributions of available cash. In addition, the issuance of additional common units or other partnership interests may dilute the value of the interests of the then-existing common unitholders in our net assets.

 

In accordance with Delaware law and the provisions of our partnership agreement, we may also issue additional partnership interests that, as determined by our general partner, may have special voting rights to which the common units are not entitled. In addition, our partnership agreement does not prohibit our subsidiaries from issuing equity interests, which may effectively rank senior to the common units.

 

If we issue additional partnership interests (other than the issuance of common units upon exercise by the underwriters of their option to purchase additional common units, the issuance of common units to NRGY upon expiration of the option to purchase additional common units, the issuance of partnership interests issued in connection with a reset of the initial quarterly distribution or the issuance of partnership interests upon conversion of outstanding partnership securities), our general partner will have the right, which it may from time to time assign in whole or in part to any of its affiliates, to purchase common units or other partnership interests whenever, and on the same terms that, we issue partnership interests to persons other than our general partner and its affiliates, to the extent necessary to maintain the aggregate percentage interest of the general partner and its affiliates, including such interest represented by common units, that existed immediately prior to each issuance.

 

The common unitholders will not have preemptive rights under our partnership agreement to acquire additional common units or other partnership interests.

 

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Amendment of the Partnership Agreement

 

General

 

Amendments to our partnership agreement may be proposed only by or with the consent of our general partner. However, our general partner will have no duty or obligation to propose any amendment and may decline to do so free of any fiduciary duty or obligation whatsoever to us or our limited partners, including any duty to act in good faith or in the best interests of us or our limited partners. In order to adopt a proposed amendment, other than the amendments discussed below, our general partner is required to seek written approval of the holders of the number of units required to approve the amendment or to call a meeting of our limited partners to consider and vote upon the proposed amendment. Except as described below, an amendment must be approved by a unit majority.

 

Prohibited Amendments

 

No amendment may be made that would:

 

   

enlarge the obligations of any limited partner without its consent, unless approved by at least a majority of the type or class of limited partner interests so affected; or

 

   

enlarge the obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable by us to our general partner or any of its affiliates without the consent of our general partner, which consent may be given or withheld in its sole discretion.

 

The provision of our partnership agreement preventing the amendments having the effects described in the clauses above can be amended upon the approval of the holders of at least 90% of the outstanding common units (including common units owned by our general partner and its affiliates). Upon completion of this offering, an affiliate of our general partner will own approximately     % of our outstanding common units.

 

No Unitholder Approval

 

Our general partner may generally make amendments to our partnership agreement without the approval of any limited partner to reflect:

 

   

a change in our name, the location of our principal place of business, our registered agent or our registered office;

 

   

the admission, substitution, withdrawal or removal of partners in accordance with our partnership agreement;

 

   

a change that our general partner determines to be necessary or appropriate to qualify or continue our qualification as a limited partnership or other entity in which the limited partners have limited liability under the laws of any state or to ensure that neither we nor any of our subsidiaries will be treated as an association taxable as a corporation or otherwise taxed as an entity for U.S. federal income tax purposes (to the extent not already so treated or taxed);

 

   

an amendment that is necessary, in the opinion of our counsel, to prevent us or our general partner or its directors, officers, agents or trustees from in any manner being subjected to the provisions of the Investment Company Act of 1940, the Investment Advisers Act of 1940 or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974, or ERISA, whether or not substantially similar to plan asset regulations currently applied or proposed;

 

   

an amendment that our general partner determines to be necessary or appropriate in connection with the creation, authorization or issuance of additional partnership interests or the right to acquire partnership interests;

 

   

any amendment expressly permitted in our partnership agreement to be made by our general partner acting alone;

 

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an amendment effected, necessitated or contemplated by a merger agreement that has been approved under the terms of our partnership agreement;

 

   

any amendment that our general partner determines to be necessary or appropriate to reflect and account for the formation by us of, or our investment in, any corporation, partnership, joint venture, limited liability company or other entity, as otherwise permitted by our partnership agreement;

 

   

a change in our fiscal year or taxable year and related changes;

 

   

conversions into, mergers with or conveyances to another limited liability entity that is newly formed and has no assets, liabilities or operations at the time of the conversion, merger or conveyance other than those it receives by way of the conversion, merger or conveyance; or

 

   

any other amendments substantially similar to any of the matters described in the clauses above.

 

In addition, our general partner may make amendments to our partnership agreement, without the approval of any limited partner, if our general partner determines that those amendments:

 

   

do not adversely affect the limited partners (or any particular class of limited partners) in any material respect;

 

   

are necessary or appropriate to satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute;

 

   

are necessary or appropriate to facilitate the trading of limited partner interests or to comply with any rule, regulation, guideline or requirement of any securities exchange on which the limited partner interests are or will be listed for trading;

 

   

are necessary or appropriate for any action taken by our general partner relating to splits or combinations of units under the provisions of our partnership agreement; or

 

   

are required to effect the intent expressed in this prospectus or the intent of the provisions of our partnership agreement or are otherwise contemplated by our partnership agreement.

 

Opinion of Counsel and Unitholder Approval

 

For amendments of the type not requiring unitholder approval, our general partner will not be required to obtain an opinion of counsel that an amendment will neither result in a loss of limited liability to the limited partners nor result in our being treated as a taxable entity for federal income tax purposes in connection with any of the amendments. No other amendments to our partnership agreement will become effective without the approval of holders of at least 90% of the outstanding units, voting as a single class, unless we first obtain an opinion of counsel to the effect that the amendment will not affect the limited liability under applicable law of any of our limited partners.

 

In addition to the above restrictions, any amendment that our general partner determines adversely affects in any material respect one or more particular classes of limited partners will require the approval of at least a majority of the class or classes so affected, but no vote will be required by any class or classes of limited partners that our general partner determines are not adversely affected in any material respect. Any amendment that would have a material adverse effect on the rights or preferences of any type or class of outstanding units in relation to other classes of units will require the approval of at least a majority of the type or class of units so affected. Any amendment that reduces the voting percentage required to take any action other than to remove the general partner or call a meeting of unitholders is required to be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than the voting requirement sought to be reduced. Any amendment that would increase the percentage of units required to remove the general partner or call a meeting of unitholders must be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than the percentage sought to be increased.

 

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Merger, Consolidation, Conversion, Sale or Other Disposition of Assets

 

A merger, consolidation or conversion of us requires the prior consent of our general partner. However, our general partner will have no duty or obligation to consent to any merger, consolidation or conversion and may decline to do so free of any fiduciary duty or obligation whatsoever to us or our limited partners, including any duty to act in good faith or in the best interest of us or our limited partners.

 

In addition, our partnership agreement generally prohibits our general partner, without the prior approval of the holders of a unit majority, from causing us to sell, exchange or otherwise dispose of all or substantially all of our assets in a single transaction or a series of related transactions, including by way of merger, consolidation or other combination. Our general partner may, however, mortgage, pledge, hypothecate or grant a security interest in all or substantially all of our assets without the approval of a unit majority. Our general partner may also sell all or substantially all of our assets under a foreclosure or other realization upon those encumbrances without that approval. Finally, our general partner may consummate any merger, consolidation or conversion without the prior approval of our unitholders if we are the surviving entity in the transaction, our general partner has received an opinion of counsel regarding limited liability and tax matters, the transaction would not result in a material amendment to the partnership agreement (other than an amendment that the general partner could adopt without the consent of other partners), each of our units will be an identical unit of our partnership following the transaction and the partnership securities to be issued do not exceed 20% of our outstanding partnership interests (other than incentive distribution rights) immediately prior to the transaction.

 

If the conditions specified in our partnership agreement are satisfied, our general partner may convert us or any of our subsidiaries into a new limited liability entity or merge us or any of our subsidiaries into, or convey all of our assets to, a newly formed entity, if the sole purpose of that conversion, merger or conveyance is to effect a mere change in our legal form into another limited liability entity, we have received an opinion of counsel regarding limited liability and tax matters and the governing instruments of the new entity provide our limited partners and our general partner with the same rights and obligations as contained in our partnership agreement. Our unitholders are not entitled to dissenters’ rights of appraisal under our partnership agreement or applicable Delaware law in the event of a merger, consolidation or conversion, a sale of substantially all of our assets or any other similar transaction or event.

 

Dissolution

 

We will continue as a limited partnership until dissolved under our partnership agreement. We will dissolve upon:

 

   

the election of our general partner to dissolve us, if approved by the holders of units representing a unit majority;

 

   

there being no limited partners, unless we are continued without dissolution in accordance with applicable Delaware law;

 

   

the entry of a decree of judicial dissolution of our partnership pursuant to the provisions of the Delaware Act; or

 

   

the withdrawal or removal of our general partner or any other event that results in its ceasing to be our general partner other than by reason of a transfer of its general partner interest in accordance with our partnership agreement or its withdrawal or removal following the approval and admission of a successor.

 

Upon a dissolution under the last clause above, the holders of a unit majority may also elect, within specific time limitations, to continue our business on the same terms and conditions described in our partnership agreement by appointing as a successor general partner an entity approved by the holders of a unit majority, subject to our receipt of an opinion of counsel to the effect that:

 

   

the action would not result in the loss of limited liability under Delaware law of any limited partner; and

 

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neither our partnership nor any of our subsidiaries would be treated as an association taxable as a corporation or otherwise be taxable as an entity for U.S. federal income tax purposes upon the exercise of that right to continue (to the extent not already so treated or taxed).

 

Liquidation and Distribution of Proceeds

 

Upon our dissolution, unless our business is continued, the liquidator authorized to wind up our affairs will, acting with all of the powers of our general partner that are necessary or appropriate, liquidate our assets and apply the proceeds of the liquidation as described in “Provisions of Our Partnership Agreement Relating to Cash Distributions—Distributions of Cash Upon Liquidation.” The liquidator may defer liquidation or distribution of our assets for a reasonable period of time or distribute assets to partners in kind if it determines that a sale would be impractical or would cause undue loss to our partners.

 

Withdrawal or Removal of Our General Partner

 

At any time, our general partner may withdraw as our general partner without first obtaining approval of any unitholder by giving 90 days’ written notice, and that withdrawal will not constitute a violation of our partnership agreement.

 

Upon withdrawal of our general partner under any circumstances, other than as a result of a transfer by our general partner of all or a part of its general partner interest in us, the holders of a unit majority may select a successor to that withdrawing general partner. If a successor is not elected, or is elected but an opinion of counsel regarding limited liability and tax matters cannot be obtained, we will be dissolved, wound up and liquidated, unless within a specified period of time after that withdrawal, the holders of a unit majority agree in writing to continue our business and to appoint a successor general partner. Please read “—Dissolution.”

 

Our general partner may not be removed unless that removal is approved by the vote of the holders of not less than 66 2/3% of the outstanding units, voting together as a single class, including units held by our general partner and its affiliates, and we receive an opinion of counsel regarding limited liability and tax matters. Any removal of our general partner is also subject to the approval of a successor general partner by the vote of the holders of a majority of the outstanding common units. The ownership of more than 33 1/3% of the outstanding units by our general partner and its affiliates gives them the ability to prevent our general partner’s removal. At the closing of this offering, an affiliate of our general partner will own     % of our outstanding common units.

 

Under circumstances where our general partner withdraws or is removed by the limited partners, the departing general partner will have the option to require the successor general partner to purchase the general partner interest of the departing general partner and its affiliates for fair market value. In each case, this fair market value will be determined by agreement between the departing general partner and the successor general partner. If no agreement is reached, an independent investment banking firm or other independent expert selected by the departing general partner and the successor general partner will determine the fair market value. If the departing general partner and the successor general partner cannot agree upon an expert, then an expert chosen by agreement of the experts selected by each of them will determine the fair market value.

 

If the option described above is not exercised by either the departing general partner or the successor general partner, the departing general partner’s general partner interest and all its and its affiliates’ incentive distribution rights will automatically convert into common units equal to the fair market value of those interests as determined by an investment banking firm or other independent expert selected in the manner described in the preceding paragraph.

 

In addition, we will be required to reimburse the departing general partner for all amounts due the departing general partner, including, without limitation, all employee-related liabilities, including severance liabilities, incurred as a result of the termination of any employees employed for our benefit by the departing general partner or its affiliates.

 

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Transfer of General Partner Interest

 

At any time, our general partner may transfer all or any of its general partner interest or common units to another person without the approval of our common unitholders. As a condition of this transfer, the transferee must assume, among other things, the rights and duties of our general partner, agree to be bound by the provisions of our partnership agreement and furnish an opinion of counsel regarding limited liability and tax matters.

 

Transfer of Ownership Interests in the General Partner

 

At any time, NRGY may sell or transfer all or part of its ownership interests in our general partner to an affiliate or third party without the approval of our common unitholders.

 

Transfer of Incentive Distribution Rights

 

At any time, NRGY may sell or transfer all or part of its incentive distribution rights to an affiliate or third party without the approval of our common unitholders.

 

By transfer of incentive distribution rights in accordance with our partnership agreement, each transferee of incentive distribution rights will be admitted as a limited partner with respect to the incentive distribution rights transferred when such transfer and admission is reflected in our books and records. Each transferee:

 

   

represents that the transferee has the capacity, power and authority to become bound by our partnership agreement;

 

   

automatically becomes bound by the terms and conditions of our partnership agreement; and

 

   

gives the consents, waivers and approvals contained in our partnership agreement, such as the approval of all transactions and agreements we are entering into in connection with this offering.

 

In addition to other rights acquired upon transfer, the transferor gives the transferee the right to become a limited partner for the transferred incentive distribution rights. Our general partner will cause any transfers to be recorded on our books and records no less frequently than quarterly.

 

Until an incentive distribution right has been transferred on our books, we may treat the record holder of the right as the absolute owner for all purposes, except as otherwise required by law.

 

We may, at our discretion, treat the nominee holder of incentive distribution rights as the absolute owner. In that case, the beneficial holder’s rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.

 

Incentive distribution rights are securities, and any transfers of incentive distribution rights are subject to the laws governing the transfer of securities.

 

Change of Management Provisions

 

Our partnership agreement contains specific provisions that are intended to discourage a person or group from attempting to remove NRGM GP, LLC as our general partner or from otherwise changing our management. Please read “—Withdrawal or Removal of Our General Partner” for a discussion of certain consequences of the removal of our general partner. If any person or group, other than our general partner and its affiliates, acquires beneficial ownership of 20% or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply in certain circumstances. Please read “—Meetings; Voting.”

 

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Limited Call Right

 

If at any time our general partner and its affiliates own more than     % of our then-issued and outstanding limited partner interests of any class, our general partner will have the right, which it may assign in whole or in part to any of its affiliates or beneficial owners or to us, to acquire all, but not less than all, of the limited partner interests of the class held by unaffiliated persons, as of a record date to be selected by our general partner, on at least 10 but not more than 60 days notice. The purchase price in the event of this purchase is the greater of:

 

   

the highest price paid by our general partner or any of its affiliates for any limited partner interests of the class purchased within the 90 days preceding the date on which our general partner first mails notice of its election to purchase those limited partner interests; and

 

   

the average of the daily closing prices of the partnership securities of such class over the 20 consecutive trading days immediately preceding the date three days before the date the notice is mailed.

 

As a result of our general partner’s right to purchase outstanding limited partner interests, a holder of limited partner interests may have its limited partner interests purchased at an undesirable time or at a price that may be lower than market prices at various times prior to such purchase or lower than a common unitholder may anticipate the market price to be in the future. The U.S. federal income tax consequences to a common unitholder of the exercise of this call right are the same as a sale by that unitholder of its common units in the market. Please read “Material U.S. Federal Income Tax Consequences—Disposition of Units.”

 

Non-Taxpaying Holders; Redemption

 

To avoid any adverse effect on the maximum applicable rates chargeable to customers by us or any of our future subsidiaries, or in order to reverse an adverse determination that has occurred regarding such maximum rate, our partnership agreement provides our general partner the power to amend the agreement. If our general partner, with the advice of counsel, determines that our not being treated as an association taxable as a corporation or otherwise taxable as an entity for U.S. federal income tax purposes, coupled with the tax status (or lack of proof thereof) of one or more of our limited partners, has, or is reasonably likely to have, a material adverse effect on the maximum applicable rates chargeable to customers by our subsidiaries, then our general partner may adopt such amendments to our partnership agreement as it determines necessary or advisable to:

 

   

obtain proof of the U.S. federal income tax status of our limited partners (and their owners, to the extent relevant); and

 

   

permit us to redeem the units held by any person whose tax status has or is reasonably likely to have a material adverse effect on the maximum applicable rates or who fails to comply with the procedures instituted by our general partner to obtain proof of the U.S. federal income tax status. The redemption price in the case of such a redemption will be the average of the daily closing prices per unit for the 20 consecutive trading days immediately prior to the date set for redemption.

 

Non-Citizen Assignees; Redemption

 

If our general partner, with the advice of counsel, determines we are subject to U.S. federal, state or local laws or regulations that, in the reasonable determination of our general partner, create a substantial risk of cancellation or forfeiture of any property that we have an interest in because of the nationality, citizenship or other related status of any limited partner, then our general partner may adopt such amendments to our partnership agreement as it determines necessary or advisable to:

 

   

obtain proof of the nationality, citizenship or other related status of our limited partners (and their owners, to the extent relevant); and

 

   

permit us to redeem the units held by any person whose nationality, citizenship or other related status creates substantial risk of cancellation or forfeiture of any property or who fails to comply with the

 

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procedures instituted by the general partner to obtain proof of the nationality, citizenship or other related status. The redemption price in the case of such a redemption will be the average of the daily closing prices per unit for the 20 consecutive trading days immediately prior to the date set for redemption.

 

Meetings; Voting

 

Except as described below regarding a person or group owning 20% or more of any class of units then outstanding, record holders of units on the record date will be entitled to notice of, and to vote at, meetings of our limited partners and to act upon matters for which approvals may be solicited.

 

Our general partner does not anticipate that any meeting of our common unitholders will be called in the foreseeable future. Any action that is required or permitted to be taken by the common unitholders may be taken either at a meeting of the common unitholders or without a meeting if consents in writing describing the action so taken are signed by holders of the number of units necessary to authorize or take that action at a meeting. Meetings of the common unitholders may be called by our general partner or by common unitholders owning at least 20% of the outstanding units of the class for which a meeting is proposed. Common unitholders may vote either in person or by proxy at meetings. The holders of a majority of the outstanding units of the class or classes for which a meeting has been called, represented in person or by proxy, will constitute a quorum, unless any action by the common unitholders requires approval by holders of a greater percentage of the units, in which case the quorum will be the greater percentage.

 

Each record holder of a unit has a vote according to its percentage interest in us, although additional limited partner interests having special voting rights could be issued. Please read “—Issuance of Additional Interests.” However, if at any time any person or group, other than our general partner and its affiliates, or a direct or subsequently approved transferee of our general partner or its affiliates and purchasers specifically approved by our general partner, acquires, in the aggregate, beneficial ownership of 20% or more of any class of units then outstanding, that person or group will lose voting rights on all of its units and the units may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of common unitholders, calculating required votes, determining the presence of a quorum or for other similar purposes. Units held in nominee or street name account will be voted by the broker or other nominee in accordance with the instruction of the beneficial owner unless the arrangement between the beneficial owner and its nominee provides otherwise.

 

Any notice, demand, request, report or proxy material required or permitted to be given or made to record common unitholders under our partnership agreement will be delivered to the record holder by us or by the transfer agent.

 

Voting Rights of Incentive Distribution Rights

 

If a majority of the incentive distribution rights are held by NRGY and its affiliates, the holders of the incentive distribution rights will have no right to vote in respect of such rights on any matter, unless otherwise required by law, and the holders of the incentive distribution rights, in their capacity as such, shall be deemed to have approved any matter approved by our general partner.

 

If less than a majority of the incentive distribution rights are held by NRGY and its affiliates, the incentive distribution rights will be entitled to vote on all matters submitted to a vote of common unitholders, other than amendments and other matters that our general partner determines do not adversely affect the holders of the incentive distribution rights in any material respect. On any matter in which the IDR holders are entitled to vote, such holders will vote together with the common units as a single class, and such incentive distribution rights shall be treated in all respects as common units when sending notices of a meeting of our limited partners to vote on any matter (unless otherwise required by law), calculating required votes, determining the presence of a quorum or for other similar purposes under our partnership agreement. The relative voting power of the holders

 

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of the incentive distribution rights and common units will be set in the same proportion as cumulative cash distributions, if any, in respect of the incentive distribution rights for the four consecutive quarters prior to the record date for the vote bears to the cumulative cash distributions in respect of common units for such four quarters.

 

Status as Limited Partner

 

By transfer of common units in accordance with our partnership agreement, each transferee of common units shall be admitted as a limited partner with respect to the common units transferred when such transfer and admission are reflected in our books and records. Except as described above under “—Limited Liability,” the common units will be fully paid, and common unitholders will not be required to make additional contributions.

 

Indemnification

 

Under our partnership agreement, in most circumstances, we will indemnify the following persons, to the fullest extent permitted by law, from and against all losses, claims, damages or similar events:

 

   

our general partner;

 

   

any departing general partner;

 

   

any person who is or was an affiliate of our general partner or any departing general partner;

 

   

any person who is or was a manager, managing member, general partner, director, officer, fiduciary or trustee of our partnership, our subsidiaries, our general partner, any departing general partner or any of their affiliates;

 

   

any person who is or was serving as a manager, managing member, general partner, director, officer, employee, agent, fiduciary or trustee of another person owing a fiduciary duty to us or our subsidiaries;

 

   

any person who controls our general partner or any departing general partner; and

 

   

any person designated by our general partner.

 

Any indemnification under these provisions will only be out of our assets. Unless our general partner otherwise agrees, it will not be personally liable for, or have any obligation to contribute or lend funds or assets to us to enable us to effectuate, indemnification. We may purchase insurance covering liabilities asserted against and expenses incurred by persons for our activities, regardless of whether we would have the power to indemnify the person against liabilities under our partnership agreement. To the extent these provisions purport to include indemnification for liabilities arising under the Securities Act, in the opinion of the SEC, such indemnification is contrary to public policy and, therefore, unenforceable.

 

Reimbursement of Expenses

 

Our partnership agreement requires us to reimburse our general partner for all direct and indirect expenses it incurs or payments it makes on our behalf and all other expenses allocable to us or otherwise incurred by our general partner in connection with operating 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. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our general partner is entitled to determine in good faith the expenses that are allocable to us. For more information on the omnibus agreement, please read “Certain Relationships and Related Party Transactions—Agreements with Affiliates in Connection with the Transactions—Omnibus Agreement.”

 

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Books and Reports

 

Our general partner is required to keep appropriate books of our business at our principal offices. These books will be maintained for both tax and financial reporting purposes on an accrual basis. For financial reporting purposes, our fiscal year ends on September 30. For U.S. federal income tax purposes, our taxable year ends on December 31.

 

We will furnish or make available to record holders of our common units, within 105 days after the close of each fiscal year, an annual report containing audited consolidated financial statements and a report on those consolidated financial statements by our independent registered public accounting firm. Except for our fourth quarter, we will also furnish or make available summary financial information within 50 days after the close of each quarter. We will be deemed to have made any such report available if we file such report with the SEC on EDGAR or make the report available on a publicly available website which we maintain.

 

We will furnish each record holder of a unit with information reasonably required for U.S. federal and state tax reporting purposes within 90 days after the close of each calendar year. This information is expected to be furnished in summary form so that some complex calculations normally required of partners can be avoided. Our ability to furnish this summary information to our common unitholders will depend on their cooperation in supplying us with specific information. Every common unitholder will receive information to assist such unitholder in determining its U.S. federal and state tax liability and in filing its U.S. federal and state income tax returns, regardless of whether such unitholder supplies us with the necessary information.

 

Right to Inspect Our Books and Records

 

Our partnership agreement provides that a limited partner can, for a purpose reasonably related to its interest as a limited partner, upon reasonable written demand stating the purpose of such demand and at such partner’s own expense, have furnished to it:

 

   

a current list of the name and last known address of each record holder;

 

   

copies of our partnership agreement, our certificate of limited partnership and related amendments and any powers of attorney under which they have been executed;

 

   

information regarding the status of our business and our financial condition; and

 

   

any other information regarding our affairs as our general partner determines is just and reasonable.

 

Our general partner may, and intends to, keep confidential from the limited partners trade secrets or other information the disclosure of which our general partner believes in good faith is not in our best interests, could damage us or our business or that we are required by law or by agreements with third parties to keep confidential.

 

Registration Rights

 

Under our partnership agreement, we have agreed to register for resale under the Securities Act and applicable state securities laws any common units or other limited partner interests proposed to be sold by our general partner or any of its affiliates or their assignees if an exemption from the registration requirements is not otherwise available. These registration rights continue for two years following any withdrawal or removal of NRGM GP, LLC as our general partner. We are obligated to pay all expenses incidental to the registration, excluding underwriting discounts and commissions. Please read “Units Eligible for Future Sale.”

 

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UNITS ELIGIBLE FOR FUTURE SALE

 

After the sale of the common units offered by this prospectus, NRGY will own, directly or indirectly, an aggregate of          common units (assuming that the underwriters do not exercise their option to purchase up to          additional common units). The sale of these common units could have an adverse impact on the price of our common units or on any trading market that may develop.

 

Our common units sold in this offering will generally be freely transferable without restriction or further registration under the Securities Act, except that any common units held by an “affiliate” of ours may not be resold publicly except in compliance with the registration requirements of the Securities Act or under an exemption under Rule 144 or otherwise. Rule 144 permits securities acquired by an affiliate to be sold into the market in an amount that does not exceed, during any three-month period, the greater of:

 

   

1% of the total number of our common units outstanding; or

 

   

the average weekly reported trading volume of our common units for the four weeks prior to the sale.

 

Sales under Rule 144 are also subject to specific manner of sale provisions, holding period requirements, notice requirements and the availability of current public information about us. Once we have been a reporting company for at least 90 days, a person who is not deemed to have been an affiliate of ours at any time during the three months preceding a sale, and who has beneficially owned the common units proposed to be sold for at least six months, would be entitled to sell those common units without complying with the manner of sale, volume limitation or notice provisions of Rule 144, subject only to the current public information requirement. After beneficially owning Rule 144 restricted common units for at least one year, such person would be entitled to freely sell those common units without regard to any of the requirements of Rule 144.

 

Our partnership agreement provides that we may issue an unlimited number of limited partner interests of any type without a vote of the common unitholders at any time. Any issuance of additional common units or other equity securities would result in a corresponding decrease in the proportionate ownership interest in us represented by, and could adversely affect the cash distributions to and market price of, common units then outstanding. Please read “The Partnership Agreement—Issuance of Additional Interests.”

 

Under our partnership agreement, our general partner and its affiliates, including NRGY, will have the right to cause us to register under the Securities Act and applicable state securities laws the offer and sale of any units that they hold. Subject to the terms and conditions of the partnership agreement, these registration rights allow our general partner and its affiliates or their assignees holding any units to require registration of any of these units and to include any of these units in a registration by us of other units, including units offered by us or by any unitholder. Our general partner and its affiliates will continue to have these registration rights for two years following its withdrawal or removal as our general partner. In connection with any registration of this kind, we will indemnify each unitholder participating in the registration and its officers, directors and controlling persons from and against any liabilities under the Securities Act or any applicable state securities laws arising from the registration statement or prospectus. We will bear all costs and expenses incidental to any registration, excluding any underwriting discounts and commissions. Except as described below, our general partner and its affiliates may sell their units in private transactions at any time, subject to compliance with applicable laws.

 

NRGY, our partnership, our general partner and its affiliates and the executive officers and directors of our general partner have agreed not to sell any common units they beneficially own for a specified period from the date of this prospectus. Please read “Underwriting” for a description of these lock-up provisions.

 

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MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES

 

This section summarizes the material U.S. federal income tax consequences that may be relevant to prospective common unitholders. To the extent this section discusses federal income taxes, that discussion is based upon current provisions of the U.S. Internal Revenue Code of 1986, as amended (the “Code”), existing and proposed U.S. Treasury regulations thereunder (the “Treasury Regulations”), and current administrative rulings and court decisions, all of which are subject to change. Changes in these authorities may cause the federal income tax consequences to a prospective common unitholder to vary substantially from those described below. Unless the context otherwise requires, references in this section to “we” or “us” are references to the partnership and its subsidiaries.

 

Legal conclusions contained in this section, unless otherwise noted, are the opinion of Vinson & Elkins L.L.P. and are based on the accuracy of representations made by us to them for this purpose. However, this section does not address all federal income tax matters that affect us or our common unitholders. Furthermore, this section focuses on common unitholders who are individual citizens or residents of the United States (for federal income tax purposes), whose functional currencies are the U.S. dollar and who hold units as capital assets (generally, property that is held for investment). This section has limited applicability to corporations, partnerships, entities treated as partnerships for federal income tax purposes, estates, trusts, non-resident aliens or other common unitholders subject to specialized tax treatment, such as tax-exempt institutions, non-U.S. persons, individual retirement accounts (“IRAs”), employee benefit plans, real estate investment trusts or mutual funds. Accordingly, because each common unitholder may have unique circumstances beyond the scope of the discussion herein, we encourage each common unitholder to consult such unitholder’s own tax advisor in analyzing the federal, state, local and non-U.S. tax consequences that are particular to that unitholder resulting from ownership or disposition of its units.

 

We are relying on opinions and advice of Vinson & Elkins L.L.P. with respect to the matters described in this section. An opinion of counsel represents only that counsel’s best legal judgment and does not bind the IRS or courts. Accordingly, the opinions and statements made herein may not be sustained by a court if contested by the IRS. Any such contest of the matters described herein may materially and adversely impact the market for our units and the prices at which such units trade. In addition, our costs of any contest with the IRS will be borne indirectly by our common unitholders because the costs will reduce our cash available for distribution. Furthermore, our tax treatment, or the tax treatment of an investment in us, may be significantly modified by future legislative or administrative changes or court decisions, which might be retroactively applied.

 

For the reasons described below, Vinson & Elkins L.L.P. has not rendered an opinion with respect to the following federal income tax issues: (1) the treatment of a common unitholder whose units are loaned to a short seller to cover a short sale of units (please read “—Tax Consequences of Unit Ownership—Treatment of Short Sales”); (2) whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations (please read “—Disposition of Units—Allocations Between Transferors and Transferees”); and (3) whether our method for taking into account Section 743 adjustments is sustainable in certain cases (please read “—Tax Consequences of Unit Ownership—Section 754 Election” and “—Uniformity of Units”).

 

Taxation of the Partnership

 

Partnership Status

 

We expect to be treated as a partnership for federal income tax purposes and, therefore, generally will not be liable for federal income taxes. Instead, as described below, each of our common unitholders will take into account its respective share of our items of income, gain, loss and deduction in computing its federal income tax liability as if the common unitholder had earned such income directly, even if no cash distributions are made to the common unitholder. Distributions by us to a common unitholder generally will not give rise to income or gain taxable to such unitholder, unless the amount of cash distributed to a common unitholder exceeds the unitholder’s adjusted tax basis in its units.

 

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Section 7704 of the Code generally provides that publicly traded partnerships will be treated as corporations for federal income tax purposes. However, if 90% or more of a partnership’s gross income for every taxable year it is publicly traded consists of “qualifying income,” the partnership may continue to be treated as a partnership for federal income tax purposes (the “Qualifying Income Exception”). Qualifying income includes (i) income and gains derived from the refining, transportation, storage, processing and marketing of crude oil, natural gas and products thereof (including NGLs), (ii) interest (other than from a financial business), (iii) dividends, (iv) gains from the sale of real property and (v) gains from the sale or other disposition of capital assets held for the production of qualifying income. We estimate that approximately         % of our current gross income is not qualifying income; however, this estimate could change from time to time.

 

Based upon factual representations made by us and our general partner regarding the composition of our income and the other representations set forth below, Vinson & Elkins L.L.P. is of the opinion that we will be treated as a partnership and each of our partnership or limited liability company subsidiaries will be treated as a partnership or will be disregarded as an entity separate from us for federal income tax purposes. In rendering its opinion, Vinson & Elkins L.L.P. has relied on factual representations made by us and our general partner. The representations made by us and our general partner upon which Vinson & Elkins L.L.P. has relied include, without limitation:

 

(a) Neither we nor any of our partnership or limited liability company subsidiaries has elected to be treated as a corporation for federal income tax purposes; and

 

(b) For each taxable year, more than 90% of our gross income has been and will be income of a character that Vinson & Elkins L.L.P. has opined is “qualifying income” within the meaning of Section 7704(d) of the Code.

 

We believe that these representations are true and will be true in the future.

 

If we fail to meet the Qualifying Income Exception, other than a failure that is determined by the IRS to be inadvertent and that is cured within a reasonable time after discovery (in which case the IRS may also require us to make adjustments with respect to our common unitholders or pay other amounts), we will be treated as transferring all of our assets, subject to liabilities, to a newly formed corporation, on the first day of the year in which we fail to meet the Qualifying Income Exception, in return for stock in that corporation and then distributing that stock to our common unitholders in liquidation of their units. This deemed contribution and liquidation generally will not result in the recognition of taxable income by our common unitholders or us so long as our liabilities do not exceed the tax basis of our assets. Thereafter, we would be treated as an association taxable as a corporation for federal income tax purposes.

 

If for any reason we are taxable as a corporation in any taxable year, our items of income, gain, loss and deduction would be taken into account by us in determining the amount of our liability for federal income tax, rather than being passed through to our common unitholders. Accordingly, our taxation as a corporation would materially reduce our cash distributions to common unitholders and thus would likely substantially reduce the value of our units. In addition, any distribution made to a common unitholder would be treated as (i) taxable dividend income to the extent of our current or accumulated earnings and profits, then (ii) a nontaxable return of capital to the extent of the common unitholder’s tax basis in our units, and thereafter (iii) taxable capital gain.

 

The remainder of this discussion is based on the opinion of Vinson & Elkins L.L.P. that we will be treated as a partnership for federal income tax purposes.

 

Tax Consequences of Unit Ownership

 

Limited Partner Status

 

Common unitholders who are admitted as limited partners of the partnership, as well as common unitholders whose units are held in street name or by a nominee and who have the right to direct the nominee in the exercise of all substantive rights attendant to the ownership of units, will be treated as partners of the partnership for

 

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federal income tax purposes. For a discussion related to the risks of losing partner status as a result of short sales, please read “—Treatment of Short Sales.” Common unitholders who are not treated as partners in us as described above are urged to consult their own tax advisors with respect to the tax consequences applicable to them under the circumstances.

 

Flow-Through of Taxable Income

 

Subject to the discussion below under “—Entity-Level Collections of Unitholder Taxes” with respect to payments we may be required to make on behalf of our common unitholders, we will not pay any federal income tax. Rather, each common unitholder will be required to report on its income tax return its share of our income, gains, losses and deductions for our taxable year or years ending with or within its taxable year without regard to whether we make cash distributions to such unitholder. Consequently, we may allocate income to a common unitholder even if that unitholder has not received a cash distribution.

 

Ratio of Taxable Income to Distributions

 

We estimate that a purchaser of common units in this offering who owns those common units from the date of closing of this offering through the record date for distributions for the period ending December 31, 2014, will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be         % or less of the cash distributed with respect to that period. Thereafter, we anticipate that the ratio of taxable income to cash distributions to the common unitholders will increase. These estimates are based upon the assumption that earnings from operations will approximate the amount required to make the initial quarterly distribution on all units and other assumptions with respect to capital expenditures, cash flow, net working capital and anticipated cash distributions. These estimates and assumptions are subject to, among other things, numerous business, economic, regulatory, legislative, competitive and political uncertainties beyond our control. Further, the estimates are based on current tax law and tax reporting positions that we will adopt and with which the IRS could disagree. Accordingly, we cannot assure you that these estimates will prove to be correct. The actual ratio of taxable income to cash distributions could be higher or lower than expected, and any differences could be material and could materially affect the value of the common units. For example, the ratio of taxable income to cash distributions to a purchaser of common units in this offering will be higher, and perhaps substantially higher, than our estimate with respect to the period described above if:

 

   

the earnings from operations exceeds the amount required to make initial quarterly distributions on all units, yet we only distribute the initial quarterly distributions on all units; or

 

   

we make a future offering of common units and use the proceeds of the offering in a manner that does not produce substantial additional deductions during the period described above, such as to repay indebtedness outstanding at the time of this offering or to acquire property that is not eligible for depreciation or amortization for federal income tax purposes or that is depreciable or amortizable at a rate significantly slower than the rate applicable to our assets at the time of this offering.

 

Basis of Units

 

A common unitholder’s tax basis in its units initially will be the amount it paid for those units plus its initial share of our liabilities. That basis generally will be (i) increased by the common unitholder’s share of our income and any increases in such unitholder’s share of our nonrecourse liabilities, and (ii) decreased, but not below zero, by distributions to it, by its share of our losses, any decreases in its share of our nonrecourse liabilities and its share of our expenditures that are neither deductible nor required to be capitalized.

 

Treatment of Distributions

 

Distributions made by us to a common unitholder generally will not be taxable to the common unitholder, unless such distributions are of cash or marketable securities that are treated as cash and exceed the common unitholder’s tax basis in its units, in which case the common unitholder will recognize gain taxable in the manner described below under “—Disposition of Units.”

 

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Any reduction in a common unitholder’s share of our “nonrecourse liabilities” (liabilities for which no partner bears the economic risk of loss) will be treated as a distribution by us of cash to that common unitholder. A decrease in a common unitholder’s percentage interest in us because of our issuance of additional units will decrease the common unitholder’s share of our nonrecourse liabilities. For purposes of the foregoing, a common unitholder’s share of our nonrecourse liabilities generally will be based upon that common unitholder’s share of the unrealized appreciation (or depreciation) in our assets, to the extent thereof, with any excess liabilities allocated based on the common unitholder’s share of our profits. Please read “—Disposition of Units.”

 

A non-pro rata distribution of money or property (including a deemed distribution described above) may cause a common unitholder to recognize ordinary income, if the distribution reduces the common unitholder’s share of our “unrealized receivables,” including depreciation recapture and substantially appreciated “inventory items,” both as defined in Section 751 of the Code (“Section 751 Assets”). To the extent of such reduction, the common unitholder would be deemed to receive its proportionate share of the Section 751 Assets and exchange such assets with us in return for an allocable portion of the non-pro rata distribution. This latter deemed exchange generally will result in the common unitholder’s realization of ordinary income in an amount equal to the excess of (1) the non-pro rata portion of that distribution over (2) the common unitholder’s tax basis (generally zero) in the Section 751 Assets deemed to be relinquished in the exchange.

 

Limitations on Deductibility of Losses

 

The deduction by a common unitholder of its share of our losses will be limited to the lesser of (i) the common unitholder’s tax basis in its units, and (ii) in the case of a common unitholder who is an individual, estate, trust or corporation (if more than 50% of the corporation’s stock is owned directly or indirectly by or for five or fewer individuals or a specific type of tax exempt organization), the amount for which the common unitholder is considered to be “at risk” with respect to our activities. In general, a common unitholder will be at risk to the extent of its tax basis in its units, reduced by (1) any portion of that basis attributable to the common unitholder’s share of our liabilities, (2) any portion of that basis representing amounts otherwise protected against loss because of a guarantee, stop loss agreement or similar arrangement and (3) any amount of money the common unitholder borrows to acquire or hold its units, if the lender of those borrowed funds owns an interest in us, is related to another common unitholder or can look only to the units for repayment.

 

A common unitholder subject to the basis and at risk limitation must recapture losses deducted in previous years to the extent that distributions (including distributions as a result of a reduction in a common unitholder’s share of nonrecourse liabilities) cause the common unitholder’s at risk amount to be less than zero at the end of any taxable year. Losses disallowed to a common unitholder or recaptured as a result of these limitations will carry forward and will be allowable as a deduction in a later year to the extent that the common unitholder’s tax basis or at risk amount, whichever is the limiting factor, is subsequently increased. Upon a taxable disposition of units, any gain recognized by a common unitholder can be offset by losses that were previously suspended by the at risk limitation but not losses suspended by the basis limitation. Any loss previously suspended by the at risk limitation in excess of that gain can no longer be used.

 

In addition to the basis and at risk limitations, passive activity loss limitations generally limit the deductibility of losses incurred by individuals, estates, trusts, some closely held corporations and personal service corporations from “passive activities” (generally, trade or business activities in which the taxpayer does not materially participate). The passive loss limitations are applied separately with respect to each publicly-traded partnership. Consequently, any passive losses we generate will be available to offset only our passive income generated in the future. Passive losses that are not deductible because they exceed a common unitholder’s share of income we generate may be deducted in full when he disposes of all of its units in a fully taxable transaction with an unrelated party. The passive activity loss rules are applied after other applicable limitations on deductions, including the at risk and basis limitations.

 

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Limitations on Interest Deductions

 

The deductibility of a non-corporate taxpayer’s “investment interest expense” is generally limited to the amount of that taxpayer’s “net investment income.” Investment interest expense includes:

 

   

interest on indebtedness properly allocable to property held for investment;

 

   

interest expense attributed to portfolio income; and

 

   

the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent attributable to portfolio income.

 

The computation of a common unitholder’s investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a unit. Net investment income includes gross income from property held for investment and amounts treated as portfolio income under the passive loss rules, less deductible expenses other than interest directly connected with the production of investment income. Such term generally does not include qualified dividend income or gains attributable to the disposition of property held for investment. A common unitholder’s share of a publicly traded partnership’s portfolio income and, according to the IRS, net passive income will be treated as investment income for purposes of the investment interest expense limitation.

 

Entity-Level Collections of Unitholder Taxes

 

If we are required or elect under applicable law to pay any federal, state, local or non-U.S. tax on behalf of any current or former common unitholder, we are authorized to pay those taxes and treat the payment as a distribution of cash to the relevant common unitholder. Where the relevant common unitholder’s identity cannot be determined, we are authorized to treat the payment as a distribution to all current common unitholders. We are authorized to amend our partnership agreement in the manner necessary to maintain uniformity of intrinsic tax characteristics of units and to adjust later distributions, so that after giving effect to these distributions, the priority and characterization of distributions otherwise applicable under our partnership agreement is maintained as nearly as is practicable. Payments by us as described above could give rise to an overpayment of tax on behalf of a common unitholder, in which event the common unitholder may be entitled to claim a refund of the overpayment amount. Common unitholders are urged to consult their tax advisors to determine the consequences to them of any tax payment we make on their behalf.

 

Allocation of Income, Gain, Loss and Deduction

 

In general, if we have a net profit, our items of income, gain, loss and deduction will be allocated among our common unitholders in accordance with their percentage interests in us. If we have a net loss, our items of income, gain, loss and deduction will be allocated first among our common unitholders in accordance with their percentage interests in us to the extent of their positive capital accounts and thereafter to our general partner. At any time that incentive distributions are made to IDR holders, gross income will be allocated to IDR holders to the extent of such distributions.

 

Specified items of our income, gain, loss and deduction will be allocated under Section 704(c) of the Code to account for any difference between the tax basis and fair market value of our assets at the time such assets are contributed to us and at the time of any subsequent offering of our units (a “Book-Tax Disparity”). In addition, items of recapture income will be specially allocated to the extent possible to the common unitholder who was allocated the deduction giving rise to that recapture income in order to minimize the recognition of ordinary income by other common unitholders.

 

An allocation of items of our income, gain, loss or deduction, generally must have “substantial economic effect” as determined under Treasury Regulations. If an allocation does not have substantial economic effect, it will be reallocated to our common unitholders the basis of their interests in us, which will be determined by taking into account all the facts and circumstances, including:

 

   

our partners’ relative contributions to us;

 

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the interests of all of our partners in our profits and losses;

 

   

the interest of all of our partners in our cash flow; and

 

   

the rights of all of our partners to distributions of capital upon liquidation.

 

Vinson & Elkins L.L.P. is of the opinion that, with the exception of the issues described in “—Section 754 Election” and “—Disposition of Units—Allocations Between Transferors and Transferees,” allocations under our partnership agreement will have substantial economic effect.

 

Treatment of Short Sales

 

A common unitholder whose units are loaned to a “short seller” to cover a short sale of units may be treated as having disposed of those units. If so, such common 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. As a result, during this period (i) any of our income, gain, loss or deduction allocated to those units would not be reportable by the common unitholder, and (ii) any cash distributions received by the common unitholder as to those units would be fully taxable, possibly as ordinary income.

 

Due to lack of controlling authority, Vinson & Elkins L.L.P. has not rendered an opinion regarding the tax treatment of a common unitholder whose units are loaned to a short seller to cover a short sale of our units. Common unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing and lending their units. The IRS has announced that it is studying issues relating to the tax treatment of short sales of partnership interests. Please read “—Disposition of Units—Recognition of Gain or Loss.”

 

Treatment of Liquidation and Termination

 

In general, if we liquidate or terminate the Partnership and sell all of the partnership’s assets, any gain or loss recognized upon such sale generally will be allocated among our common unitholders in the manner described under “—Allocation of Income, Gain, Loss and Deduction”. Please read “—Treatment of Distributions” for a discussion of the termination of any distributions that may result from a liquidation of the partnership. For a general discussion of the events and circumstances of a liquidation and termination of the Partnership, please read “The Partnership Agreement—Dissolution” and “The Partnership Agreement—Liquidation and Distribution of Proceeds.”

 

Alternative Minimum Tax

 

If a common unitholder is subject to federal alternative minimum tax, such tax will apply to such common unitholder’s distributive share of any items of our income, gain, loss or deduction. The current alternative minimum tax rate for non-corporate taxpayers is 26% on the first $175,000 of alternative minimum taxable income in excess of the exemption amount and 28% on any additional alternative minimum taxable income. Prospective common unitholders are urged to consult with their tax advisors with respect to the impact of an investment in our units on their alternative minimum tax liability.

 

Tax Rates

 

Under current law, the highest marginal federal income tax rates for individuals applicable to ordinary income and long-term capital gains (generally, gains from the sale or exchange of certain investment assets held for more than one year) are 35% and 15%, respectively. However, absent new legislation extending the current rates, beginning January 1, 2013, the highest marginal federal income tax rate applicable to ordinary income and long-term capital gains of individuals will increase to 39.6% and 20%, respectively. These rates are subject to change by new legislation at any time.

 

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A 3.8% Medicare tax on certain investment income earned by individuals, estates, and trusts will apply for taxable years beginning after December 31, 2012. For these purposes, investment income generally includes a common unitholder’s allocable share of our income and gain realized by a common unitholder from a sale of units. In the case of an individual, the tax will be imposed on the lesser of (i) the common unitholder’s net investment income from all investments, or (ii) the amount by which the common unitholder’s modified adjusted gross income exceeds $250,000 (if the common unitholder is married and filing jointly or a surviving spouse), $125,000 (if the common unitholder is married and filing separately) or $200,000 (in any other case).

 

Section 754 Election

 

We have made the election permitted by Section 754 of the Code that permits us to adjust the tax bases in our assets as to specific purchased units under Section 743(b) of the Code to reflect the unit purchase price. The Section 743(b) adjustment separately applies to each purchaser of units based upon the values and bases of our assets at the time of the relevant purchase. The Section 743(b) adjustment does not apply to a person who purchases units directly from us. For purposes of this discussion, a common unitholder’s basis in our assets will be considered to have two components: (1) its share of the tax basis in our assets as to all common unitholders (“common basis”) and (2) its Section 743(b) adjustment to that tax basis (which may be positive or negative).

 

Under Treasury Regulations, a Section 743(b) adjustment attributable to property depreciable under Section 168 of the Code, such as our storage assets, may be amortizable over the remaining cost recovery period for such property, while a Section 743(b) adjustment attributable to properties subject to depreciation under Section 167 of the Code, must be amortized straight-line or using the 150% declining balance method. As a result, if we owned any assets subject to depreciation under Section 167 of the Code, the amortization rates could give rise to differences in the taxation of common unitholders purchasing units from us and common unitholders purchasing from other common unitholders.

 

Under our partnership agreement, we are authorized to take a position to preserve the uniformity of units even if that position is not consistent with these or any other Treasury Regulations. Please read “—Uniformity of Units.” Consistent with this authority, we intend to treat properties depreciable under Section 167, if any, in the same manner as properties depreciable under Section 168 for this purpose. These positions are consistent with the methods employed by other publicly traded partnerships but are inconsistent with the existing Treasury Regulations, and Vinson & Elkins L.L.P. has not opined on the validity of this approach.

 

The IRS may challenge our position with respect to depreciating or amortizing the Section 743(b) adjustment we take to preserve the uniformity of units due to lack of controlling authority. Because a common unitholder’s tax basis for its units is reduced by its share of our items of deduction or loss, any position we take that understates deductions will overstate a common unitholder’s basis in its units, and may cause the common unitholder to understate gain or overstate loss on any sale of such units. Please read “—Disposition of Units—Recognition of Gain or Loss.” If a challenge to such treatment were sustained, the gain from the sale of units may be increased without the benefit of additional deductions.

 

The calculations involved in the Section 754 election are complex and will be made on the basis of assumptions as to the value of our assets and other matters. The IRS could seek to reallocate some or all of any Section 743(b) adjustment we allocated to our assets subject to depreciation to goodwill or nondepreciable assets. Goodwill, as an intangible asset, is generally nonamortizable or amortizable over a longer period of time or under a less accelerated method than our tangible assets. We cannot assure any common unitholder that the determinations we make will not be successfully challenged by the IRS or that the resulting deductions will not be reduced or disallowed altogether. Should the IRS require a different tax basis adjustment to be made, and should, in our opinion, the expense of compliance exceed the benefit of the election, we may seek permission from the IRS to revoke our Section 754 election. If permission is granted, a subsequent purchaser of units may be allocated more income than it would have been allocated had the election not been revoked.

 

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Tax Treatment of Operations

 

Accounting Method and Taxable Year

 

We will use the year ending December 31 as our taxable year and the accrual method of accounting for federal income tax purposes. Each common unitholder will be required to include in income its share of our income, gain, loss and deduction for each taxable year ending within or with its taxable year. In addition, a common unitholder who has a taxable year ending on a date other than December 31 and who disposes of all of its units following the close of our taxable year but before the close of its taxable year must include its share of our income, gain, loss and deduction in income for its taxable year, with the result that it will be required to include in income for its taxable year its share of more than one year of our income, gain, loss and deduction. Please read “—Disposition of Units—Allocations Between Transferors and Transferees.”

 

Tax Basis, Depreciation and Amortization

 

The tax basis of our assets will be used for purposes of computing depreciation and cost recovery deductions and, ultimately, gain or loss on the disposition of these assets. The federal income tax burden associated with the difference between the fair market value of our assets and their tax basis immediately prior to an offering will be borne by our partners holding interests in us prior to this offering. Please read “—Tax Consequences of Unit Ownership—Allocation of Income, Gain, Loss and Deduction.”

 

If we dispose of depreciable property by sale, foreclosure or otherwise, all or a portion of any gain, determined by reference to the amount of depreciation previously deducted and the nature of the property, may be subject to the recapture rules and taxed as ordinary income rather than capital gain. Similarly, a common unitholder who has taken cost recovery or depreciation deductions with respect to property we own will likely be required to recapture some or all of those deductions as ordinary income upon a sale of its interest in us. Please read “—Tax Consequences of Unit Ownership—Allocation of Income, Gain, Loss and Deduction” and “—Disposition of Units—Recognition of Gain or Loss.”

 

The costs we incur in offering and selling our units (called “syndication expenses”) must be capitalized and cannot be deducted currently, ratably or upon our termination. While there are uncertainties regarding the classification of costs as organization expenses, which may be amortized by us, and as syndication expenses, which may not be amortized by us, the underwriting discounts and commissions we incur will be treated as syndication expenses.

 

Valuation and Tax Basis of Our Properties

 

The federal income tax consequences of the ownership and disposition of units will depend in part on our estimates of the relative fair market values and the initial tax bases of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we will make many of the relative fair market value estimates ourselves. These estimates and determinations of tax basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or basis are later found to be incorrect, the character and amount of items of income, gain, loss or deduction previously reported by common unitholders could change, and common unitholders could be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.

 

Disposition of Units

 

Recognition of Gain or Loss

 

A common unitholder will be required to recognize gain or loss on a sale of units equal to the difference between the common unitholder’s amount realized and tax basis for the units sold. A common unitholder’s amount realized will equal the sum of the cash or the fair market value of other property it receives plus its share of our liabilities with respect to such units.

 

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Because the amount realized includes a common unitholder’s share of our liabilities, the gain recognized on the sale of units could result in a tax liability in excess of any cash received from the sale.

 

Except as noted below, gain or loss recognized by a common unitholder on the sale or exchange of a unit held for more than one year generally will be taxable as long-term capital gain or loss. However, gain or loss recognized on the disposition of units will be separately computed and taxed as ordinary income or loss under Section 751 of the Code to the extent attributable to Section 751 Assets, primarily depreciation recapture. Ordinary income attributable to Section 751 Assets may exceed net taxable gain realized on the sale of a unit and may be recognized even if there is a net taxable loss realized on the sale of a unit. Thus, a common unitholder may recognize both ordinary income and a capital loss upon a sale of units. Net capital loss may offset capital gains and, in the case of individuals, up to $3,000 of ordinary income per year.

 

The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all those interests. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests sold using an “equitable apportionment” method, which generally means that the tax basis allocated to the interest sold equals an amount that bears the same relation to the partner’s tax basis in its entire interest in the partnership as the value of the interest sold bears to the value of the partner’s entire interest in the partnership.

 

Treasury Regulations under Section 1223 of the Code allow a selling common unitholder who can identify units transferred with an ascertainable holding period to elect to use the actual holding period of the units transferred. Thus, according to the ruling discussed above, a common unitholder will be unable to select high or low basis units to sell as would be the case with corporate stock, but, according to the Treasury Regulations, it may designate specific units sold for purposes of determining the holding period of units transferred. A common unitholder electing to use the actual holding period of units transferred must consistently use that identification method for all subsequent sales or exchanges of our units. A common unitholder considering the purchase of additional units or a sale of units purchased in separate transactions is urged to consult its tax advisor as to the possible consequences of this ruling and application of the Treasury Regulations.

 

Specific provisions of the Code affect the taxation of some financial products and securities, including partnership interests, by treating a taxpayer as having sold an “appreciated” partnership interest, one in which gain would be recognized if it were sold, assigned or terminated at its fair market value, if the taxpayer or related persons enter(s) into:

 

   

a short sale;

 

   

an offsetting notional principal contract; or

 

   

a futures or forward contract with respect to the partnership interest or substantially identical property.

 

Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the partnership interest, the taxpayer will be treated as having sold that position if the taxpayer or a related person then acquires the partnership interest or substantially identical property. The Secretary of the Treasury is also authorized to issue regulations that treat a taxpayer that enters into transactions or positions that have substantially the same effect as the preceding transactions as having constructively sold the financial position.

 

Allocations Between Transferors and Transferees

 

In general, our taxable income or loss will be determined annually, will be prorated on a monthly basis and will be subsequently apportioned among the common unitholders in proportion to the number of units owned by each of them as of the opening of the applicable exchange on the first business day of the month (the “Allocation Date”). Nevertheless, we allocate certain deductions for depreciation of capital additions based upon the date the underlying property is placed in service, and gain or loss realized on a sale or other disposition of our assets or, in

 

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the discretion of the general partner, any other extraordinary item of income, gain, loss or deduction will be allocated among the common unitholders on the Allocation Date in the month in which such income, gain, loss or deduction is recognized. As a result, a common unitholder transferring units may be allocated income, gain, loss and deduction realized after the date of transfer.

 

Although simplifying conventions are contemplated by the Code and most publicly traded partnerships use similar simplifying conventions, the use of this method may not be permitted under existing Treasury Regulations. Recently, however, the Department of the Treasury and the IRS issued proposed Treasury Regulations that provide a safe harbor pursuant to which a publicly traded partnership may use a similar monthly simplifying convention to allocate tax items among transferor and transferee common unitholders. Nonetheless, the safe harbor in the proposed regulations differs slightly from the proration method we have adopted because the safe harbor would allocate tax items among the months based upon the relative number of days in each month, and could require certain tax items which our general partner may not consider extraordinary to be allocated to the month in which such items actually occur. Accordingly, Vinson & Elkins L.L.P. is unable to opine on the validity of this method of allocating income and deductions between transferee and transferor common unitholders. If this method is not allowed under the Treasury Regulations, or only applies to transfers of less than all of the common unitholder’s interest, our taxable income or losses might be reallocated among the common unitholders. We are authorized to revise our method of allocation between transferee and transferor common unitholders, as well as among common unitholders whose interests vary during a taxable year, to conform to a method permitted under future Treasury Regulations.

 

A common unitholder who disposes of units prior to the record date set for a cash distribution for that quarter will be allocated items of our income, gain, loss and deduction attributable to the month of disposition but will not be entitled to receive a cash distribution for that period.

 

Notification Requirements

 

A common unitholder who sells or purchases any units is generally required to notify us in writing of that transaction within 30 days after the transaction (or, if earlier, January 15 of the year following the transaction). Upon receiving such notifications, we are required to notify the IRS of that transaction and to furnish specified information to the transferor and transferee. Failure to notify us of a transfer of units may, in some cases, lead to the imposition of penalties. However, these reporting requirements do not apply to a sale by an individual who is a citizen of the United States and who effects the sale through a broker who will satisfy such requirements.

 

Constructive Termination

 

We will be considered to have terminated our partnership for federal income tax purposes upon the sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. Immediately following this offering, NRGY will own more than 50% of the total interests in our capital and profits. Therefore, a transfer by NRGY of all or a portion of its interests in us, including a deemed transfer as a result of a termination of NRGY’s partnership for federal income tax purposes, could result in a termination of our partnership for federal income tax purposes. For such purposes, multiple sales of the same unit are counted only once. A constructive termination results in the closing of our taxable year for all common unitholders. In the case of a common unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may result in more than twelve months of our taxable income or loss being includable in such common unitholder’s taxable income for the year of termination.

 

A constructive termination occurring on a date other than December 31 will result in us filing two tax returns for one fiscal year and the cost of the preparation of these returns will be borne by all common unitholders. However, pursuant to an IRS relief procedure the IRS may allow, among other things, a constructively terminated partnership to provide a single Schedule K-1 for the calendar year in which a termination occurs. We would be required to make new tax elections after a termination, including a new election

 

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under Section 754 of the Code, and a termination would result in a deferral of our deductions for depreciation. A termination could also result in penalties if we were unable to determine that the termination had occurred. Moreover, a termination might either accelerate the application of, or subject us to, any tax legislation enacted before the termination.

 

Uniformity of Units

 

Because we cannot match transferors and transferees of units and for other reasons, we must maintain uniformity of the economic and tax characteristics of the units to a purchaser of these units. In the absence of uniformity, we may be unable to completely comply with a number of federal income tax requirements, both statutory and regulatory. A lack of uniformity could result from a literal application of Treasury Regulation Section 1.167(c)-1(a)(6), which is not anticipated to apply to a material portion of our assets. Any non-uniformity could have a negative impact on the value of the units. Please read “—Tax Consequences of Unit Ownership—Section 754 Election.”

 

If necessary to preserve the uniformity of our units, our partnership agreement permits our general partner to take positions in filing our tax returns even when contrary to a literal application of regulations like the one described above. These positions may include reducing for some common unitholders the depreciation, amortization or loss deductions to which they would otherwise be entitled or reporting a slower amortization of Section 743(b) adjustments for some common unitholders than that to which they would otherwise be entitled. The general partner does not anticipate needing to take such positions, but if they were necessary, Vinson & Elkins L.L.P. would be unable to opine as to validity of such filing positions in the absence of direct and controlling authority.

 

A common unitholder’s basis in units is reduced by its share of our deductions (whether or not such deductions were claimed on an individual income tax return) so that any position that we take that understates deductions will overstate the common unitholder’s basis in its units, and may cause the common unitholder to understate gain or overstate loss on any sale of such units. Please read “—Disposition of Units—Recognition of Gain or Loss” above and “—Tax Consequences of Unit Ownership—Section 754 Election” above. The IRS may challenge one or more of any positions we take to preserve the uniformity of units. If such a challenge were sustained, the uniformity of units might be affected, and, under some circumstances, the gain from the sale of units might be increased without the benefit of additional deductions.

 

Tax-Exempt Organizations and Other Investors

 

Ownership of units by employee benefit plans, other tax-exempt organizations, non-resident aliens, non-U.S. corporations and other non-U.S. persons raises issues unique to those investors and, as described below, may have substantially adverse tax consequences to them. Prospective common unitholders who are tax-exempt entities or non-U.S. persons should consult their tax advisor before investing in our units. Employee benefit plans and most other tax-exempt organizations, including IRAs and other retirement plans, are subject to federal income tax on unrelated business taxable income. Virtually all of our income will be unrelated business taxable income and will be taxable to a tax-exempt common unitholder.

 

Non-resident aliens and foreign corporations, trusts or estates that own units will be considered to be engaged in business in the United States because of their ownership of our units. Consequently, they will be required to file federal tax returns to report their share of our income, gain, loss or deduction and pay federal income tax at regular rates on their share of our net income or gain. Moreover, under rules applicable to publicly traded partnerships, distributions to non-U.S. common unitholders are subject to withholding at the highest applicable effective tax rate. Each non-U.S. common unitholder must obtain a taxpayer identification number from the IRS and submit that number to our transfer agent on a Form W-8BEN or applicable substitute form in order to obtain credit for these withholding taxes. A change in applicable law may require us to change these procedures.

 

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In addition, because a foreign corporation that owns units will be treated as engaged in a United States trade or business, that corporation may be subject to the United States branch profits tax at a rate of 30%, in addition to regular federal income tax, on its share of our income and gain, as adjusted for changes in the foreign corporation’s “U.S. net equity,” which is effectively connected with the conduct of a United States trade or business. That tax may be reduced or eliminated by an income tax treaty between the United States and the country in which the foreign corporate common unitholder is a “qualified resident.” In addition, this type of common unitholder is subject to special information reporting requirements under Section 6038C of the Code.

 

A foreign common unitholder who sells or otherwise disposes of a unit will be subject to federal income tax on gain realized from the sale or disposition of that unit to the extent the gain is effectively connected with a U.S. trade or business of the foreign common unitholder. Under a ruling published by the IRS, interpreting the scope of “effectively connected income,” a foreign common unitholder would be considered to be engaged in a trade or business in the U.S. by virtue of the U.S. activities of the partnership, and part or all of that common unitholder’s gain would be effectively connected with that common unitholder’s indirect U.S. trade or business. Moreover, under the Foreign Investment in Real Property Tax Act, a foreign common unitholder generally will be subject to federal income tax upon the sale or disposition of a unit if (i) it owned (directly or constructively applying certain attribution rules) more than 5% of our units at any time during the five-year period ending on the date of such disposition and (ii) 50% or more of the fair market value of all of our assets consisted of U.S. real property interests at any time during the shorter of the period during which such common unitholder held the units or the 5-year period ending on the date of disposition. Currently, more than 50% of our assets consist of U.S. real property interests and we do not expect that to change in the foreseeable future. Therefore, foreign common unitholders may be subject to federal income tax on gain from the sale or disposition of their units.

 

Administrative Matters

 

Information Returns and Audit Procedures

 

We intend to furnish to each common unitholder, within 90 days after the close of each taxable year, specific tax information, including a Schedule K-1, which describes its share of our income, gain, loss and deduction for our preceding taxable year. In preparing this information, which will not be reviewed by counsel, we will take various accounting and reporting positions, some of which have been mentioned earlier, to determine each common unitholder’s share of income, gain, loss and deduction. We cannot assure our common unitholders that those positions will yield a result that conforms to the requirements of the Code, Treasury Regulations or administrative interpretations of the IRS.

 

Neither we, nor Vinson & Elkins L.L.P. can assure prospective common unitholders that the IRS will not successfully contend in court that those positions are impermissible, and such a contention could negatively affect the value of the units. The IRS may audit our federal income tax information returns. Adjustments resulting from an IRS audit may require each common unitholder to adjust a prior year’s tax liability, and possibly may result in an audit of its own return. Any audit of a common unitholder’s return could result in adjustments not related to our returns as well as those related to its returns.

 

Partnerships generally are treated as entities separate from their owners for purposes of federal income tax audits, judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax treatment of partnership items of income, gain, loss and deduction are determined in a partnership proceeding rather than in separate proceedings with the partners. The Code requires that one partner be designated as the “Tax Matters Partner” for these purposes, and our partnership agreement designates our general partner.

 

The Tax Matters Partner will make some elections on our behalf and on behalf of common unitholders. In addition, the Tax Matters Partner can extend the statute of limitations for assessment of tax deficiencies against common unitholders for items in our returns. The Tax Matters Partner may bind a common unitholder with less than a 1% profits interest in us to a settlement with the IRS unless that common unitholder elects, by filing a

 

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statement with the IRS, not to give that authority to the Tax Matters Partner. The Tax Matters Partner may seek judicial review, by which all the common unitholders are bound, of a final partnership administrative adjustment and, if the Tax Matters Partner fails to seek judicial review, judicial review may be sought by any common unitholder having at least a 1% interest in profits or by any group of common unitholders having in the aggregate at least a 5% interest in profits. However, only one action for judicial review will go forward, and each common unitholder with an interest in the outcome may participate in that action.

 

A common unitholder must file a statement with the IRS identifying the treatment of any item on its federal income tax return that is not consistent with the treatment of the item on our return. Intentional or negligent disregard of this consistency requirement may subject a common unitholder to substantial penalties.

 

Nominee Reporting

 

Persons who hold an interest in us as a nominee for another person are required to furnish to us:

 

(1) the name, address and taxpayer identification number of the beneficial owner and the nominee;

 

(2) a statement regarding whether the beneficial owner is:

 

(a) a non-U.S. person;

 

(b) a non-U.S. government, an international organization or any wholly owned agency or instrumentality of either of the foregoing; or

 

(c) a tax-exempt entity;

 

(3) the amount and description of units held, acquired or transferred for the beneficial owner; and

 

(4) specific information including the dates of acquisitions and transfers, means of acquisitions and transfers, and acquisition cost for purchases, as well as the amount of net proceeds from sales.

 

Brokers and financial institutions are required to furnish additional information, including whether they are U.S. persons and specific information on units they acquire, hold or transfer for their own account. A penalty of $100 per failure, up to a maximum of $1.5 million per calendar year, is imposed by the Code for failure to report that information to us. The nominee is required to supply the beneficial owner of the units with the information furnished to us.

 

Accuracy-Related Penalties

 

An additional tax equal to 20% of the amount of any portion of an underpayment of tax that is attributable to one or more specified causes, including negligence or disregard of rules or regulations, substantial understatements of income tax and substantial valuation misstatements, is imposed by the Code. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for the underpayment of that portion and that the taxpayer acted in good faith regarding the underpayment of that portion.

 

For individuals, a substantial understatement of income tax in any taxable year exists if the amount of the understatement exceeds the greater of 10% of the tax required to be shown on the return for the taxable year or $5,000. The amount of any understatement subject to penalty generally is reduced if any portion is attributable to a position adopted on the return:

 

(1) for which there is, or was, “substantial authority”; or

 

(2) as to which there is a reasonable basis and the relevant facts of that position are disclosed on the return.

 

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If any item of income, gain, loss or deduction included in the distributive shares of common unitholders might result in that kind of an “understatement” of income for which no “substantial authority” exists, we must disclose the relevant facts on our return. In addition, we will make a reasonable effort to furnish sufficient information for common unitholders to make adequate disclosure on their returns and to take other actions as may be appropriate to permit common unitholders to avoid liability for this penalty. More stringent rules apply to “tax shelters,” which we do not believe includes us, or any of our investments, plans or arrangements.

 

A substantial valuation misstatement exists if (a) the value of any property, or the tax basis of any property, claimed on a tax return is 150% or more of the amount determined to be the correct amount of the valuation or tax basis, (b) the price for any property or services (or for the use of property) claimed on any such return with respect to any transaction between persons described in Code Section 482 is 200% or more (or 50% or less) of the amount determined under Section 482 to be the correct amount of such price, or (c) the net Code Section 482 transfer price adjustment for the taxable year exceeds the lesser of $5 million or 10% of the taxpayer’s gross receipts. No penalty is imposed unless the portion of the underpayment attributable to a substantial valuation misstatement exceeds $5,000 ($10,000 for a corporation other than an S Corporation or a personal holding company). The penalty is increased to 40% in the event of a gross valuation misstatement. We do not anticipate making any valuation misstatements.

 

In addition, the 20% accuracy-related penalty also applies to any portion of an underpayment of tax that is attributable to transactions lacking economic substance. To the extent that such transactions are not disclosed, the penalty imposed is increased to 40%. Additionally, there is no reasonable cause defense to the imposition of this penalty to such transactions.

 

Reportable Transactions

 

If we were to engage in a “reportable transaction,” we (and possibly our common unitholders and others) would be required to make a detailed disclosure of the transaction to the IRS. A transaction may be a reportable transaction based upon any of several factors, including the fact that it is a type of tax avoidance transaction publicly identified by the IRS as a “listed transaction” or that it produces certain kinds of losses for partnerships, individuals, S corporations, and trusts in excess of $2 million in any single tax year, or $4 million in any combination of six successive tax years. Our participation in a reportable transaction could increase the likelihood that our federal income tax information return (and possibly our common unitholders’ tax return) would be audited by the IRS. Please read “—Information Returns and Audit Procedures.”

 

Moreover, if we were to participate in a reportable transaction with a significant purpose to avoid or evade tax, or in any listed transaction, our common unitholders may be subject to the following additional consequences:

 

   

accuracy-related penalties with a broader scope, significantly narrower exceptions, and potentially greater amounts than described above at “—Accuracy-Related Penalties”;

 

   

for those persons otherwise entitled to deduct interest on federal tax deficiencies, nondeductibility of interest on any resulting tax liability; and

 

   

in the case of a listed transaction, an extended statute of limitations.

 

We do not expect to engage in any “reportable transactions.”

 

State, Local and Other Tax Considerations

 

In addition to federal income taxes, common unitholders will be subject to other taxes, including state and local income taxes, unincorporated business taxes, and estate, inheritance or intangibles taxes that may be imposed by the various jurisdictions in which we conduct business or own property or in which the common unitholder is a resident. We currently conduct business or own property only in New York and Pennsylvania, each of which imposes an income tax on corporations and other entities and a personal income tax. Moreover, we

 

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may also own property or do business in other states in the future that impose income or similar taxes on nonresident individuals. Although an analysis of those various taxes is not presented here, each prospective common unitholder should consider their potential impact on its investment in us.

 

It is the responsibility of each common unitholder to investigate the legal and tax consequences, under the laws of pertinent states and localities, of its investment in us. Vinson & Elkins L.L.P. has not rendered an opinion on the state, local, or non-U.S. tax consequences of an investment in us. We strongly recommend that each prospective common unitholder consult, and depend on, its own tax counsel or other advisor with regard to those matters. It is the responsibility of each common unitholder to file all tax returns that may be required of it.

 

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INVESTMENT IN INERGY MIDSTREAM, L.P. BY EMPLOYEE BENEFIT PLANS

 

An investment in us by an employee benefit plan is subject to additional considerations because the investments of these plans are subject to the fiduciary responsibility and prohibited transaction provisions of ERISA and restrictions imposed by Section 4975 of the Internal Revenue Code. For these purposes, the term “employee benefit plan” includes, but is not limited to, qualified pension, profit-sharing and stock bonus plans, Keogh plans, simplified employee pension plans and tax deferred annuities or IRAs established or maintained by an employer or employee organization. Among other things, consideration should be given to:

 

   

whether the investment is prudent under Section 404(a)(1)(B) of ERISA;

 

   

whether in making the investment, that plan will satisfy the diversification requirements of Section 404(a)(1)(C) of ERISA; and

 

   

whether the investment will result in recognition of unrelated business taxable income by the plan and, if so, the potential after-tax investment return. Please read “Material U.S. Federal Income Tax Consequences—Tax-Exempt Organizations and Other Investors.”

 

The person with investment discretion with respect to the assets of an employee benefit plan, often called a fiduciary, should determine whether an investment in us is authorized by the appropriate governing instrument and is a proper investment for the plan or IRA.

 

Section 406 of ERISA and Section 4975 of the Internal Revenue Code prohibit employee benefit plans, and also IRAs that are not considered part of an employee benefit plan, from engaging in specified transactions involving “plan assets” with parties that are “parties in interest” under ERISA or “disqualified persons” under the Internal Revenue Code with respect to the plan.

 

In addition to considering whether the purchase of common units is a prohibited transaction, a fiduciary of an employee benefit plan should consider whether the plan will, by investing in us, be deemed to own an undivided interest in our assets, with the result that our operations would be subject to the regulatory restrictions of ERISA, including its prohibited transaction rules, as well as the prohibited transaction rules of the Internal Revenue Code.

 

The Department of Labor regulations provide guidance with respect to whether the assets of an entity in which employee benefit plans acquire equity interests would be deemed “plan assets” under some circumstances. Under these regulations, an entity’s assets would not be considered to be “plan assets” if, among other things:

 

(1) the equity interests acquired by employee benefit plans are publicly offered securities—i.e., the equity interests are widely held by 100 or more investors independent of the issuer and each other, freely transferable and registered under some provisions of the federal securities laws;

 

(2) the entity is an “operating company”—i.e., it is primarily engaged in the production or sale of a product or service other than the investment of capital either directly or through a majority-owned subsidiary or subsidiaries; or

 

(3) there is no significant investment by benefit plan investors, which is defined to mean that less than 25% of the value of each class of equity interest is held by the employee benefit plans referred to above, and IRAs that are subject to ERISA or Section 4975 of the Internal Revenue Code.

 

Our assets should not be considered “plan assets” under these regulations because it is expected that the investment will satisfy the requirements in (1) and (2) above.

 

Plan fiduciaries contemplating a purchase of common units should consult with their own counsel regarding the consequences under ERISA and the Internal Revenue Code in light of the serious penalties imposed on persons who engage in prohibited transactions or other violations.

 

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UNDERWRITING

 

Under the terms and subject to the conditions contained in an underwriting agreement dated the date of this prospectus, the underwriters named below, for whom Morgan Stanley & Co. LLC and Barclays Capital Inc. are acting as representatives, have severally agreed to purchase the number of common units indicated below:

 

Underwriter

   Number of
Common Units

Morgan Stanley & Co. LLC

  

Barclays Capital Inc.

  

Total

  

 

The underwriting agreement provides that the obligations of the underwriters to pay for and accept delivery of the common units offered by this prospectus are subject to the approval of certain legal matters by their counsel and to certain other conditions. The underwriters are obligated to take and pay for all of the common units offered by this prospectus if any such common units are taken. However, the underwriters are not required to take or pay for the common units covered by the underwriters’ over-allotment option described below.

 

The underwriters initially propose to offer part of the common units directly to the public at the public offering price listed on the cover page of this prospectus and part to certain dealers at a price that represents a concession not in excess of $         per common unit under the public offering price. After the initial offering of the common units, the offering price and other selling terms may from time to time be varied by the representatives.

 

We have granted to the underwriters an option, exercisable for 30 days from the date of this prospectus, to purchase up to an aggregate of          additional common units at the public offering price listed on the cover page of this prospectus, less underwriting discounts and commissions. The underwriters may exercise this option solely for the purpose of covering over-allotments, if any, made in connection with the offering of common units offered by this prospectus. To the extent the option is exercised, each underwriter will become obligated, subject to certain conditions, to purchase approximately the same percentage of the additional common units as the number listed next to the underwriter’s name in the preceding table bears to the total number of common units listed next to the names of all underwriters in the preceding table.

 

If the underwriters do not exercise their over-allotment option to purchase additional common units, we will deliver          common units to NRGY upon the option’s expiration. If and to the extent the underwriters exercise their option to purchase additional common units, the number of common units purchased by the underwriters pursuant to such exercise will be sold to the public and the remainder, if any, will be delivered to NRGY. Any such common units delivered to NRGY pursuant to the option’s expiration or any partial exercise of the option will be delivered for no additional consideration. Accordingly, the exercise of the underwriters’ over-allotment option will not affect the total number of common units outstanding.

 

The following table shows the per common unit and total public offering price, underwriting discounts and commissions, and proceeds before expenses to us. These amounts are shown assuming both no exercise and full exercise of the underwriters’ option to purchase up to an additional          common units.

 

            Total  
     Per Common
Unit
     No Exercise      Full Exercise  

Public offering price

   $                    $                    $                

Underwriting discounts and commissions

   $         $         $     

Proceeds, before expenses, to us

   $         $         $     

 

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We will pay to Morgan Stanley & Co. LLC and Barclays Capital Inc. a structuring fee equal to an aggregate of 0.375% of the gross proceeds from this offering, or $         ($         if the underwriters exercise the over-allotment option in full) for the evaluation, analysis and structuring of our partnership.

 

The estimated offering expenses payable by us, exclusive of the underwriting discounts and commissions and the structuring fee, are approximately $        .

 

The underwriters have informed us that they do not intend sales to discretionary accounts to exceed 5% of the total number of common units offered by them.

 

Listing

 

We intend to apply to list our common units on the NYSE under the trading symbol “NRGM”. The underwriters have undertaken to sell the minimum number of common units to the minimum number of beneficial owners necessary to meet the NYSE distribution requirements for trading.

 

Lock-up Agreements

 

We, our general partner, the officers and directors of our general partner, and NRGY have agreed that, without the prior written consent of Morgan Stanley & Co. LLC and Barclays Capital Inc. on behalf of the underwriters, we and each of them will not, during the period ending 180 days after the date of this prospectus:

 

   

offer, pledge, sell, contract to sell, sell any option or contract to purchase, purchase any option or contract to sell, grant any option, right or warrant to purchase, lend or otherwise transfer or dispose of, directly or indirectly, any of our common units or any securities convertible into or exerciseable or exchangeable for our common units;

 

   

file any registration statement with the Securities and Exchange Commission relating to the offering of any of our common units or any securities convertible into or exerciseable or exchangeable for our common units;

 

   

enter into any swap or other arrangement that transfers to another, in whole or in part, any of the economic consequences of ownership of our common units; or

 

   

dispose of or hedge any of our common units or securities convertible into or exerciseable or exchangeable for our common units;

 

whether any such transaction described above is to be settled by delivery of our common units or such other securities, in cash or otherwise. In addition, we, our general partner, the officers and directors of our general partner, and NRGY agree that, without the prior written consent of Morgan Stanley & Co. LLC and Barclays Capital Inc. on behalf of the underwriters, we and they will not, during the period ending 180 days after the date of this prospectus, make any demand for, or exercise any right with respect to, the registration of any of our common units or any security convertible into or exerciseable or exchangeable for our common units.

 

The 180-day restricted period described in the preceding paragraph will be extended if:

 

   

during the last 17 days of the 180-day restricted period, we issue an earnings release or material news or a material event relating to us occurs, or

 

   

prior to the expiration of the 180-day restricted period, we announce that we will release earnings results during the 16-day period beginning on the last day of the 180-day period,

 

in which case the restrictions described in the preceding paragraph will continue to apply until the expiration of the 18-day period beginning on the issuance of the earnings release or the occurrence of the material news or material event.

 

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Price Stabilization and Short Positions

 

In order to facilitate the offering of the common units, the underwriters may engage in transactions that stabilize, maintain or otherwise affect the price of the common units. Specifically, the underwriters may sell more common units than they are obligated to purchase under the underwriting agreement, creating a short position. A short sale is covered if the short position is no greater than the number of common units available for purchase by the underwriters under the over-allotment option. The underwriters can close out a covered short sale by exercising the over-allotment option or purchasing common units in the open market. In determining the source of common units to close out a covered short sale, the underwriters will consider, among other things, the open market price of common units compared to the price available under the over-allotment option. The underwriters may also sell common units in excess of the over-allotment option, creating a naked short position. The underwriters must close out any naked short position by purchasing common units in the open market. A naked short position is more likely to be created if the underwriters are concerned that there may be downward pressure on the price of the common units in the open market after pricing that could adversely affect investors who purchase in this offering. As an additional means of facilitating this offering, the underwriters may bid for, and purchase, common units in the open market to stabilize the price of the common units. These activities may raise or maintain the market price of the common units above independent market levels or prevent or retard a decline in the market price of the common units. The underwriters are not required to engage in these activities and may end any of these activities at any time.

 

Indemnification

 

We, our general partner and NRGY have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act, or to contribute to payments the underwriters may be required to make because of any of those liabilities.

 

Pricing of the Offering

 

Prior to this offering, there has been no public market for our common units. The initial public offering price will be determined by negotiations between us and the representatives. Among the factors that will be considered in determining the initial public offering price are estimates of distributions to our common unitholders, industry and market conditions, the information set forth in this prospectus or otherwise available to the representatives and the general conditions of the securities market at the time of this offering. The estimated initial public offering price range set forth on the cover page of this prospectus is subject to change as a result of market conditions and other factors. We and the underwriters cannot assure you, however, that the prices at which the common units will sell in the public market after this offering will not be lower than the initial public offering price or that an active trading market in our common units will develop and continue after this offering.

 

FINRA Conduct Rules

 

Because the Financial Industry Regulatory Authority, or FINRA, views the common units offered under this prospectus as interests in a direct participation program, the offering is being made in compliance with Rule 2310 of the FINRA rules. Investor suitability with respect to the common units should be judged similarly to the suitability with respect to other securities that are listed for trading on a national securities exchange.

 

Conflicts of Interest

 

The underwriters and their respective affiliates are full service financial institutions engaged in various activities, which may include securities trading, commercial and investment banking, financial advisory, investment management, investment research, principal investment, hedging, financing and brokerage activities. Certain of the underwriters and their respective affiliates have from time to time performed, and may in the future perform, various financial advisory, investment banking, commercial banking and other services for us

 

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and our affiliates, including NRGY, for which they received or will receive customary fees and expenses. For example, affiliates of certain of the underwriters are lenders under the revolving credit facility that we will assume from NRGY in connection with this offering and, as such, will receive a substantial portion of the net proceeds from this offering pursuant to the repayment of indebtedness outstanding under such credit facility. Furthermore, affiliates of certain of the underwriters are lenders under NRGY’s revolving credit facilities for which they receive customary fees and expenses. Additionally, certain of the underwriters and their respective affiliates may, from time to time, enter into arms-length transactions with us and our affiliates, including NRGY, in the ordinary course of their business for which they may receive customary fees and reimbursement of expenses. In the ordinary course of their various business activities, the underwriters and their respective affiliates may make or hold a broad array of investments and actively trade debt and equity securities (or related derivative securities) and financial instruments (including bank loans) for their own account and for the accounts of their customers, and such investment and securities activities may involve securities or instruments of ours or our affiliates, including NRGY. The underwriters and their respective affiliates may also make investment recommendations or publish or express independent research views in respect of such securities or instruments and may at any time hold, or recommend to clients that they acquire, long or short positions in such securities and instruments.

 

Electronic Distribution

 

A prospectus in electronic format may be made available on websites maintained by one or more underwriters, or selling group members, if any, participating in this offering. The representatives may agree to allocate a number of common units to underwriters for sale to their online brokerage account holders. Internet distributions will be allocated by the representatives to the underwriters that may make Internet distributions on the same basis as other allocations.

 

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VALIDITY OF OUR COMMON UNITS

 

The validity of our common units will be passed upon for us by Vinson & Elkins L.L.P., Houston, Texas. Certain legal matters in connection with our common units offered hereby will be passed upon for the underwriters by Baker Botts L.L.P., Houston, Texas.

 

EXPERTS

 

The consolidated financial statements of Inergy Midstream, LLC at September 30, 2010 and 2009, and for each of the three years in the period ended September 30, 2010, appearing in this Prospectus and Registration Statement have been audited by Ernst & Young LLP, independent registered public accounting firm, as set forth in their report thereon appearing elsewhere herein in the form that will be signed upon completion of the transfer of 100% ownership of US Salt, LLC to Inergy, L.P., and are included in reliance upon such report given on the authority of such firm as experts in accounting and auditing.

 

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WHERE YOU CAN FIND MORE INFORMATION

 

We have filed with the SEC a registration statement on Form S-l relating to the common units offered by this prospectus. This prospectus, which constitutes a part of the registration statement, does not contain all of the information set forth in the registration statement. For further information regarding us and the common units offered by this prospectus, we refer you to the full registration statement, including its exhibits and schedules, filed under the Securities Act. The registration statement, of which this prospectus forms a part, including its exhibits and schedules, may be inspected and copied at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. Copies of the materials may also be obtained from the SEC at prescribed rates by writing to the SEC’s Public Reference Room. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC maintains a website at http://www.sec.gov that contains reports, information statements and other information regarding issuers that file electronically with the SEC. Our registration statement, of which this prospectus constitutes a part, can be downloaded from the SEC’s website.

 

As a result of this offering, we will file with or furnish to the SEC periodic reports and other information. These reports and other information may be inspected and copied at the Public Reference Room maintained by the SEC or obtained from the SEC’s website as provided above. Our website address will be                     , and we intend to make our periodic reports and other information filed with or furnished to the SEC available, free of charge, through our website, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus.

 

We intend to furnish or make available to our common unitholders annual reports containing our audited financial statements prepared in accordance with GAAP. We also intend to furnish or make available to our common unitholders quarterly reports containing our unaudited interim financial information, including the information required by Form 10-Q, for the first three fiscal quarters of each fiscal year.

 

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FORWARD-LOOKING STATEMENTS

 

This prospectus contains forward-looking statements concerning our financial condition, results of operations, plans, objectives, future performance and business. These forward-looking statements include:

 

   

statements that are not historical in nature, including, but not limited to, our belief that we will complete our growth projects; we may have the opportunity to acquire midstream assets from NRGY in the future; we expect greater interconnectivity, among our assets and with the interstate pipeline system, to enhance our ability to sell storage and transportation services; we expect to jointly develop with NRGY a natural gas storage project by 2014; our acquisition expertise should allow us to continue to grow through acquisitions; our belief that we will have the capacity to fund internal growth projects and acquisitions; and our belief that we will be able to generate stable cash flows; 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:

 

   

changes in general and local economic conditions;

 

   

competitive conditions within our industry;

 

   

the demand for natural gas and NGL storage and transportation services;

 

   

our ability to successfully implement our business plan for our natural gas and NGL storage and transportation assets;

 

   

our ability to complete internal growth projects on time and on budget;

 

   

the price and availability of debt and equity financing;

 

   

the availability and price of natural gas and NGLs to the consumer compared to the price of alternative and competing fuels;

 

   

competition from the same and alternative energy sources;

 

   

energy efficiency and technology trends;

 

   

the effects of existing and future governmental legislation and regulations;

 

   

environmental claims;

 

   

operating hazards and other risks incidental to storing and transporting natural gas and NGLs;

 

   

natural disasters, weather-related delays, casualty losses and other matters beyond our control;

 

   

interest rates;

 

   

labor relations; and

 

   

large customer defaults.

 

A forward-looking statement may include a statement of the assumptions or bases underlying the forward-looking statement. We believe that we have chosen these assumptions or bases in good faith and that they are reasonable. However, we caution you that assumed facts or bases almost always vary from actual results, and the differences between assumed facts or bases and actual results can be material, depending on the circumstances. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this prospectus, including those described in the “Risk Factors” section of this prospectus. We will not update these statements unless the securities laws require us to do so.

 

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INDEX TO FINANCIAL STATEMENTS

 

UNAUDITED PRO FORMA CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

  

Introduction

     F-2   

Unaudited Pro Forma Condensed Consolidated Balance Sheet as of June 30, 2011

     F-3   

Unaudited Pro Forma Condensed Consolidated Statement of Operations for the Nine Months Ended June  30, 2011

     F-4   

Unaudited Pro Forma Condensed Consolidated Statement of Operations for the Year Ended September  30, 2010

     F-5   

Notes to the Unaudited Pro Forma Condensed Consolidated Financial Statements

     F-6   

HISTORICAL CONSOLIDATED FINANCIAL STATEMENTS

  

Report of Independent Registered Public Accounting Firm

     F-7   

Consolidated Balance Sheets as of September 30, 2009 and 2010

     F-8   

Consolidated Statements of Operations for the Years Ended September 30, 2008, 2009 and 2010

     F-9   

Consolidated Statements of Member’s Capital for the Years Ended September  30, 2008, 2009 and 2010

     F-10   

Consolidated Statements of Cash Flows for the Years Ended September 30, 2008, 2009 and 2010

     F-11   

Notes to the Consolidated Financial Statements

     F-13   

Unaudited Consolidated Balance Sheets as of September 30, 2010 and June 30, 2011

     F-22   

Unaudited Consolidated Statements of Operations for the Nine Months Ended June 30, 2010 and 2011

     F-23   

Unaudited Consolidated Statement of Member’s Capital for the Nine Months Ended June 30, 2011

     F-24   

Unaudited Consolidated Statements of Cash Flows for the Nine Months Ended June 30, 2010 and 2011

     F-25   

Notes to the Unaudited Consolidated Financial Statements

     F-27   

 

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INERGY MIDSTREAM, LLC

UNAUDITED PRO FORMA CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 

The following unaudited pro forma condensed consolidated financial statements give effect to the formation transactions, which include the following:

 

   

all indebtedness that we owe to a subsidiary of NRGY will be extinguished and treated as a capital contribution by NRGY to us, which was approximately $123.7 million as of June 30, 2011;

 

   

we expect to assume approximately $             million of indebtedness from NRGY under a $             million revolving credit facility that will be assigned to us of which we will repay $             million using net proceeds of this offering;

 

   

we expect to re-borrow $80 million under our revolving credit facility to fund a cash distribution to NRGY for reimbursement of capital expenditures associated with our assets;

 

   

we will issue to NRGY an aggregate of              common units, assuming that the underwriters do not exercise their option to purchase              additional common units and that we issue those common units to NRGY;

 

   

we will issue to NRGY the incentive distribution rights, which entitle the holder to 50.0% of the cash we distribute in excess of our initial quarterly distribution of $             per common unit per quarter;

 

   

NRGM GP, LLC will maintain its non-economic general partner interest in us;

 

   

we will issue              common units to the public (              common units if the underwriters exercise their option in full); and

 

   

we will enter into the omnibus agreement with NRGY and certain of its affiliates.

 

The following unaudited pro forma condensed consolidated statement of operations for the nine months ended June 30, 2011, has been prepared as if the formation transaction occurred on October 1, 2009. The following unaudited pro forma condensed consolidated statement of operations for the fiscal year ended September 30, 2010, has been prepared as if the formation transaction described above occurred on October 1, 2009. The unaudited pro forma condensed consolidated balance sheet at June 30, 2011, assumes the formation transaction was consummated on that date. The historical column of the unaudited pro forma condensed consolidated statements of operations and balance sheet exclude any amounts of Tres Palacios Gas Storage LLC and US Salt, LLC as such financials reflect the transfer of these assets to NRGY. The unaudited pro forma financial statements should be read in conjunction with and are qualified in their entirety by reference to the notes accompanying such unaudited pro forma financial statements as well as the notes included in the historical financial statements of Inergy Midstream, LLC for the periods ended September 30, 2010 and June 30, 2011, which are included in this document.

 

The unaudited pro forma financial statements are based on assumptions that we believe are reasonable under the circumstances and are intended for informational purposes only. They are not necessarily indicative of the results of the actual or future operations or financial condition that would have been achieved had the transaction occurred at the dates assumed (as noted above).

 

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INERGY MIDSTREAM, LLC

UNAUDITED PRO FORMA CONDENSED CONSOLIDATED BALANCE SHEET

AS OF JUNE 30, 2011

(in millions)

 

     Historical      Pro Forma
Adjustments
    Pro Forma  

Assets

       

Current assets:

       

Cash and cash equivalents

   $ 9.4       $              (c)    $ 9.4   
                     (c)   
                     (d)   
        80.0 (e)   
        (80.0 )(e)   

Accounts receivable

     9.1                9.1   

Inventories

     1.1                1.1   

Prepaid expenses and other current assets

     0.8                0.8   
  

 

 

    

 

 

   

 

 

 
       

Total current assets

     20.4           20.4   

Property, plant and equipment

     597.2                597.2   

Less: accumulated depreciation

     125.9                125.9   
  

 

 

    

 

 

   

 

 

 

Property, plant and equipment, net

     471.3                471.3   

Intangible assets:

       

Customer accounts

     36.3                36.3   

Other intangible assets

     7.0                      (d)      7.0   
  

 

 

    

 

 

   

 

 

 
     43.3           43.3   

Less: accumulated amortization

     17.9           17.9   
  

 

 

    

 

 

   

 

 

 

Intangible assets, net

     25.4                25.4   

Goodwill

     90.2                90.2   
  

 

 

    

 

 

   

 

 

 

Total assets

   $ 607.3       $      $ 607.3   
  

 

 

    

 

 

   

 

 

 

Liabilities and partners’ capital

       

Current liabilities:

       

Accounts payable

   $ 4.6       $      $ 4.6   

Accrued expenses

     2.2                2.2   

Payable to Inergy Propane, LLC and Inergy, L.P.

     123.7         (123.7 )(a)        
  

 

 

    

 

 

   

 

 

 

Total current liabilities

     130.5         (123.7     6.8   

Debt

                          (b)      80.0   
                     (c)   
        80.0 (e)   

Other long-term liabilities

     0.9                0.9   

Total partners’ capital

     475.9                      (b)      519.6   
                     (c)   
        123.7 (a)   
        (80.0 )(e)   
  

 

 

    

 

 

   

 

 

 

Total liabilities and capital

   $ 607.3       $      $ 607.3   
  

 

 

    

 

 

   

 

 

 

 

The accompanying notes are an integral part of these

Unaudited Pro Forma Condensed Consolidated Financial Statement

 

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INERGY MIDSTREAM, LLC

UNAUDITED PRO FORMA CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS

NINE MONTHS ENDED

JUNE 30, 2011

(in millions)

 

     Historical      Pro Forma
Adjustments
    Pro Forma  

Revenue:

       

Firm storage

   $ 67.3       $      $ 67.3   

Transportation

     9.5                9.5   

Hub services

     3.5                3.5   
  

 

 

    

 

 

   

 

 

 
     80.3                80.3   

Cost of services sold (excluding depreciation and amortization as shown below):

       

Storage

     6.8                6.8   

Transportation

     5.1                5.1   
  

 

 

    

 

 

   

 

 

 
     11.9                11.9   
  

 

 

    

 

 

   

 

 

 

Gross profit

     68.4                68.4   

Expenses:

       

Operating and administrative

     10.1                10.1   

Depreciation and amortization

     27.3                27.3   
  

 

 

    

 

 

   

 

 

 

Operating income

     31.0                31.0   

Other expense:

       

Interest expense, net

             1.0 (f)      1.0   
       
  

 

 

    

 

 

   

 

 

 

Net income

   $ 31.0       $ (1.0   $ 30.0   
  

 

 

    

 

 

   

 

 

 

 

The accompanying notes are an integral part of these

Unaudited Pro Forma Condensed Consolidated Financial Statements.

 

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INERGY MIDSTREAM, LLC

UNAUDITED PRO FORMA CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS

YEAR ENDED

SEPTEMBER 30, 2010

(in millions)

 

     Historical      Pro Forma
Adjustments
    Pro Forma  

Revenue:

       

Firm storage

   $ 81.0       $      $ 81.0   

Transportation

     12.1                12.1   

Hub services

     1.6                1.6   
  

 

 

    

 

 

   

 

 

 
     94.7                94.7   

Cost of services sold (excluding depreciation and amortization as shown below):

       

Storage

     5.2                5.2   

Transportation

     6.8                6.8   
  

 

 

    

 

 

   

 

 

 
     12.0                12.0   
  

 

 

    

 

 

   

 

 

 

Gross profit

     82.7                82.7   

Expenses:

       

Operating and administrative

     15.0                15.0   

Depreciation and amortization

     36.2                36.2   

Loss on disposal of assets

     0.9                0.9   
  

 

 

    

 

 

   

 

 

 

Operating income

     30.6                30.6   

Other income (expense):

       

Interest expense, net

             (1.3 )(f)      (1.3

Other income

     0.8                0.8   
  

 

 

    

 

 

   

 

 

 

Net income

     31.4         (1.3     30.1   

Net income attributable to non-controlling partners

     0.8                0.8   
  

 

 

    

 

 

   

 

 

 

Net income attributable to partners

   $ 30.6       $ (1.3   $ 29.3   
  

 

 

    

 

 

   

 

 

 

 

The accompanying notes are an integral part of these

Unaudited Pro Forma Condensed Consolidated Financial Statements.

 

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INERGY MIDSTREAM, LLC

NOTES TO THE UNAUDITED PRO FORMA CONDENSED CONSOLIDATED

FINANCIAL STATEMENTS

 

These unaudited pro forma condensed consolidated financial statements and underlying pro forma adjustments are based upon currently available information and certain estimates and assumptions made by management; therefore, actual results could differ materially from the pro forma information. However, we believe the assumptions provide a reasonable basis for presenting the significant effects of the transactions noted herein. We believe the pro forma adjustments give appropriate effect to those assumptions and are properly applied in the pro forma information.

 

Upon completion of this conversion, we anticipate incurring incremental administrative expenses associated with being a publicly traded limited partnership in an annual amount of approximately $3.0 million, including costs associated with annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution, independent auditor fees, Sarbanes-Oxley compliance, New York Stock Exchange listing, investor relations activities, registrar and transfer agent fees, director and officer liability insurance costs and director compensation. In future periods, the board of directors of our general partner may grant awards to our key employees and our outside directors pursuant to our long-term incentive plan; however, the board has not yet made any determination as to the number of awards or when the awards would be granted. The unaudited pro forma condensed consolidated financial statements do not reflect these incremental administrative expenses.

 

Pro Forma Adjustments

 

(a) Reflects the extinguishment of approximately $123.7 million of indebtedness that we owed to a subsidiary of Inergy, L.P., which will be treated as a capital contribution and part of Inergy, L.P.’s investment in us.

 

(b) Reflects the assumption of approximately $             million of indebtedness from Inergy, L.P. under a $             million revolving credit facility that will be assigned to Inergy Midstream, LLC.

 

(c) Reflects the net proceeds to Inergy Midstream, LLC of approximately $             million from the issuance and sale of common units at the initial price of $             per common unit, net of underwriter’s discounts and commissions and offering expenses of approximately $             million. We will use net proceeds of $             million to repay borrowings under the assumed revolving credit facility.

 

(d) Reflects the expected payment of $             million of debt issuance costs in conjunction with the $             million referenced in (b) above.

 

(e) Reflects the borrowing of $80 million on the assumed revolving credit facility to fund a distribution to Inergy, L.P. in connection with the reimbursement of capital expenditures associated with our assets, which are reflected, along with the related payable to Inergy, L.P., in our historical consolidated financial statements.

 

(f) Reflects the recording of pro forma interest expense on the anticipated revolver debt borrowings needed to fund (i) the $ 80 million borrowings referred to (e) above and (ii) capital expenditures during the period. This assumes:

 

   

The pro forma rate on these borrowings is 3.5%, which is based on LIBOR rates during the period plus the margin and the associated commitment fees; and

 

   

Amortization of debt issuance costs, referenced in (d) above, associated with our revolving credit facility. The amortization of debt issuance costs are classified as a component of interest expense.

 

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Report of Independent Registered Public Accounting Firm

 

The Board of Directors of Inergy GP, LLC

We have audited the accompanying consolidated balance sheets of Inergy Midstream, LLC as of September 30, 2010 and 2009, and the related consolidated statements of operations, member’s capital and noncontrolling interests, and cash flows for each of the three years in the period ended September 30, 2010. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements 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, LLC at September 30, 2010 and 2009, and the results of its consolidated operations and its cash flows for each of the three years in the period ended September 30, 2010, in conformity with U.S. generally accepted accounting principles.

 

Ernst & Young LLP

Kansas City, Missouri

 

August 24, 2011, except for Notes 1 and 6, as to which the date is                     , 2011

 

The foregoing report is in the form that will be signed upon the completion of the transfer of 100% ownership of US Salt, LLC to Inergy, L.P.

 

/s/ Ernst & Young LLP

Kansas City, Missouri

 

August 24, 2011

 

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INERGY MIDSTREAM, LLC

CONSOLIDATED BALANCE SHEETS

(in millions)

 

     As of
September 30,
 
         2010              2009      

Assets

     

Current assets:

     

Cash and cash equivalents

   $       $ 3.6   

Accounts receivable

     7.7         6.5   

Inventories

     0.8         0.2   

Prepaid expenses and other current assets

     5.0         11.1   
  

 

 

    

 

 

 

Total current assets

     13.5         21.4   

Property, plant and equipment (Note 4)

     529.3         486.4   

Less: accumulated depreciation

     100.9         68.4   
  

 

 

    

 

 

 

Property, plant and equipment, net

     428.4         418.0   

Intangible assets (Note 4):

     

Customer accounts

     36.3         36.3   

Other intangible assets

     7.0         7.5   
  

 

 

    

 

 

 
     43.3         43.8   

Less: accumulated amortization

     15.9         13.0   
  

 

 

    

 

 

 

Intangible assets, net

     27.4         30.8   

Goodwill

     90.2         90.1   

Other assets

             0.7   
  

 

 

    

 

 

 

Total assets

   $ 559.5       $ 561.0   
  

 

 

    

 

 

 

Liabilities and partners’ capital

     

Current liabilities:

     

Accounts payable

   $ 0.4       $ 5.2   

Accrued expenses

     3.3         9.3   

Bank overdraft

     0.9           

Current portion of long-term debt (Note 5)

             1.4   

Payable to Inergy Propane, LLC and Inergy, L.P.

     109.2         123.0   
  

 

 

    

 

 

 

Total current liabilities

     113.8         138.9   

Long-term debt, less current portion (Note 5)

             6.9   

Other long-term liabilities

     0.9         0.9   

Total Inergy Midstream, LLC member’s capital

     444.8         409.6   

Interest of non-controlling partners

             4.7   
  

 

 

    

 

 

 

Total member’s capital

     444.8         414.3   

Total liabilities and capital

   $ 559.5       $ 561.0   
  

 

 

    

 

 

 

 

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

 

F-8


Table of Contents
Index to Financial Statements

INERGY MIDSTREAM, LLC

CONSOLIDATED STATEMENTS OF OPERATIONS

(in millions)

 

     Year Ended September 30,  
         2010              2009              2008      

Revenue:

        

Firm storage

   $ 81.0       $ 72.1       $ 67.6   

Transportation

     12.1         12.2         13.0   

Hub services

     1.6         3.2         2.1   
  

 

 

    

 

 

    

 

 

 
     94.7         87.5         82.7   

Cost of services sold (excluding depreciation and amortization as shown below):

        

Storage

     5.2         11.0         3.0   

Transportation

     6.8         6.8         9.4   
  

 

 

    

 

 

    

 

 

 
     12.0         17.8         12.4   
  

 

 

    

 

 

    

 

 

 

Gross profit

     82.7         69.7         70.3   

Expenses:

        

Operating and administrative

     15.0         10.8         11.7   

Depreciation and amortization

     36.2         29.2         24.5   

(Gain) loss on disposal of assets

     0.9                 (1.9
  

 

 

    

 

 

    

 

 

 

Operating income

     30.6         29.7         36.0   

Other income

     0.8                 0.8   
  

 

 

    

 

 

    

 

 

 

Net income

     31.4         29.7         36.8   

Net income attributable to non-controlling partners

     0.8         1.4         1.4   
  

 

 

    

 

 

    

 

 

 

Net income attributable to member

   $ 30.6       $ 28.3       $ 35.4   
  

 

 

    

 

 

    

 

 

 

 

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

 

F-9


Table of Contents
Index to Financial Statements

INERGY MIDSTREAM, LLC

CONSOLIDATED STATEMENTS OF MEMBER’S CAPITAL

(in millions)

 

     Parent Company’s
Investment
    Non-Controlling
Partners
    Total Member’s
Capital
 

Balance at September 30, 2007

   $ 311.1      $      $ 311.1   

Contribution by Inergy, L.P.

     34.8               34.8   

Acquisition

            3.0        3.0   

Distributions

            (0.8     (0.8

Comprehensive income:

      

Net income

     35.4        1.4        36.8   

Reclassification of cash flow hedges

     (0.1            (0.1
      

 

 

 

Comprehensive income

         36.7   
  

 

 

   

 

 

   

 

 

 

Balance at September 30, 2008

     381.2        3.6        384.8   
  

 

 

   

 

 

   

 

 

 

Distributions

            (0.7     (0.7

Investment in entity

            0.4        0.4   

Comprehensive income:

      

Net income

     28.3        1.4        29.7   

Reclassification of cash flow hedges

     0.1               0.1   
      

 

 

 

Comprehensive income

         29.8   
  

 

 

   

 

 

   

 

 

 

Balance at September 30, 2009

     409.6        4.7        414.3   
  

 

 

   

 

 

   

 

 

 

Purchase of minority interest

     (13.8     (4.5     (18.3

Contribution by Inergy, L.P.

     18.3               18.3   

Distributions

            (0.6     (0.6

Disposal of entity

            (0.4     (0.4

Comprehensive income:

      

Net income

     30.6        0.8        31.4   

Reclassification of cash flow hedges

     0.1               0.1   
      

 

 

 

Comprehensive income

         31.5   
  

 

 

   

 

 

   

 

 

 

Balance at September 30, 2010

   $ 444.8      $      $ 444.8   
  

 

 

   

 

 

   

 

 

 

 

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

 

F-10


Table of Contents
Index to Financial Statements

INERGY MIDSTREAM, LLC

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

 

     Year Ended September 30,  
     2010     2009     2008  

Operating activities

      

Net income

   $ 31.4      $ 29.7      $ 36.8   

Adjustments to reconcile net income to net cash provided by operating activities:

      

Depreciation

     32.9        26.7        22.0   

Amortization

     3.3        2.5        2.5   

(Gain) loss on disposal of assets

     0.9               (1.9

Changes in operating assets and liabilities, net of effects from acquisitions:

      

Accounts receivable

     (1.2     (0.8     (0.4

Inventories

     (0.6     1.8        (1.4

Prepaid expenses and other current assets

     6.1        (3.7       

Other assets

     0.7        0.1        0.1   

Accounts payable and accrued expenses

     (5.2     (4.1     (2.6

Bank overdraft

     0.9                 

Payable to Inergy Propane, LLC and Inergy, L.P.

     14.3        8.0        7.7   

Customer deposits

            (0.7     0.1   
  

 

 

   

 

 

   

 

 

 

Net cash provided by operating activities

     83.5        59.5        62.9   

Investing activities

      

Acquisitions, net of cash acquired

                   (36.0

Purchases of property, plant and equipment

     (49.8     (74.4     (94.4

Proceeds from sale of assets

                   21.6   

Other

            0.3        (0.1
  

 

 

   

 

 

   

 

 

 

Net cash used in investing activities

     (49.8     (74.1     (108.9

 

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

 

F-11


Table of Contents
Index to Financial Statements

INERGY MIDSTREAM, LLC

CONSOLIDATED STATEMENTS OF CASH FLOWS (CONTINUED)

(in millions)

 

     Year Ended September 30,  
     2010     2009     2008  

Financing activities

      

Borrowings from related party

   $ 62.4      $ 79.8      $ 100.9   

Payments to related party

     (90.8     (61.3     (84.9

Principal payments on long-term debt

     (8.3     (2.5     (1.1

Equity contributions from parent

     18.3               34.8   

Acquisition of minority interest

     (18.3              

Distributions paid to non-controlling partners

     (0.6     (0.7     (0.8
  

 

 

   

 

 

   

 

 

 

Net cash provided by (used in) financing activities

     (37.3     15.3        48.9   

Net increase (decrease) in cash

     (3.6     0.7        2.9   

Cash at beginning of period

     3.6        2.9          
  

 

 

   

 

 

   

 

 

 

Cash at end of period

   $      $ 3.6      $ 2.9   
  

 

 

   

 

 

   

 

 

 

Supplemental schedule of noncash investing and financing activities

      

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

   $ (5.7   $ 3.4      $ 0.9   
  

 

 

   

 

 

   

 

 

 

Acquisitions, net of cash acquired:

      

Current assets

   $      $      $ 0.9   

Property, plant and equipment

                   44.4   

Intangible assets, net

                   2.1   

Goodwill

                   4.4   

Other assets

                   0.7   

Current liabilities

                   (0.5

Other liabilities

                   (16.0
  

 

 

   

 

 

   

 

 

 

Total acquisitions, net of cash acquired

   $      $      $ 36.0   
  

 

 

   

 

 

   

 

 

 

 

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

 

F-12


Table of Contents
Index to Financial Statements

INERGY MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

Note 1. Organization and Basis of Presentation

 

Organization

 

Inergy Midstream, LLC (“Inergy Midstream” or the “Company”) is a wholly owned subsidiary of Inergy, L.P., its sole member. The sole member’s maximum liability arising from its investment in a limited liability company is limited to the amount of its investment.

 

Nature of Operations

 

Inergy Midstream is engaged primarily in the storage and transportation of natural gas and natural gas liquids. Inergy Midstream’s operations are primarily concentrated in the Northeast region of the United States.

 

Inergy Midstream owns and operate the following assets:

 

   

Stagecoach, a 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 multi-cycle depleted reservoir natural gas storage facility located in Steuben County, New York.

 

   

Steuben, a single-turn depleted reservoir natural gas storage facility located in Steuben County, New York.

 

   

Bath NGL storage facility located near Bath, New York.

 

Basis of Presentation

 

Inergy Midstream is a wholly owned subsidiary of Inergy, L.P., and the accompanying consolidated financial statements have been prepared to represent the net assets and related historical results of Inergy Midstream as if it were a stand-alone entity with the exception that the operations of US Salt, LLC have been excluded from the historical Inergy Midstream operations. The general ledger of each of the entities owned by Inergy Midstream (excluding US Salt, LLC) forms the primary basis for the accompanying financial statements. Costs incurred by Inergy, L.P. benefiting both Inergy Midstream and Inergy Propane, LLC, a wholly owned subsidiary of Inergy, L.P., have been allocated in a manner described in “Allocation of Expenses” below.

 

Principles of Consolidation

 

The accompanying consolidated financial statements include the accounts of Inergy Midstream, LLC as well as all of its subsidiaries (excluding US Salt, LLC). 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 our customers. Revenue for transportation services is recognized ratably over the contract period regardless of the volume of natural gas that has shipped. Transportation revenue is derived entirely from the sale of capacity that the Company has secured on certain third party pipelines. Revenue from hub services is recognized ratably over the contract period. The contract period for hub services is typically less than one year.

 

Expense Classification

 

Cost of storage services provided consists of the direct costs to operate the storage facilities including power, contractor and fuel costs. These costs support the revenue generated from firm storage and hub services.

 

F-13


Table of Contents
Index to Financial Statements

INERGY MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

 

Our transportation cost of services sold consists of costs to procure firm transportation capacity on certain pipelines. In limited instances, the Company may sell inventory obtained from fuel-in-kind collections. The cost basis of this inventory will be recorded in cost of storage services sold. Operating and administrative expenses consist of all expenses incurred by Inergy Midstream other than those described above in cost of services sold and depreciation and amortization. Certain of Inergy Midstream’s operating and administrative expenses and depreciation and amortization are incurred in providing storage services, but are not included in cost of services sold. These amounts were $33.9 million, $27.5 million and $23.0 million during the years ended September 30, 2010, 2009 and 2008, respectively.

 

Credit Risk and Concentrations

 

Inergy Midstream generally extends unsecured credit to the majority of its customer base. Credit for our customers is extended based on an evaluation of each customer’s financial condition. A substantial portion of Inergy Midstream’s customer base is investment grade companies. Historically, write-offs for uncollectible accounts have been insignificant and the Company has determined that an allowance for doubtful accounts is not necessary at either the September 30, 2010 or September 30, 2009.

 

For the fiscal years ended September 30, 2010 and 2009, ConEdison accounted for approximately 28% and 29%, respectively, of our total revenue. For the fiscal year ended September 30, 2008, ConEdison, NJR Energy Services and its affiliates and TGP accounted for approximately 19%, 15% and 12%, respectively, of our total revenue. Other than as described above, no other customer accounted for 10% or more of our total revenue for the fiscal years ended September 30, 2010, 2009 or 2008.

 

ConEdison accounted for 28% of consolidated accounts receivable as of September 30, 2010.

 

 

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, consisting primarily of natural gas, are stated at the lower of cost or market and are computed predominantly using the average cost method.

 

Property, Plant and Equipment

 

Property, plant and equipment are stated at historical cost less accumulated depreciation. We capitalize 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 $4.2 million, $4.8 million and $2.3 million for the years ended September 30, 2010, 2009 and 2008, 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

     5   

Base Gas

     10   

Plant Equipment

     15   

 

F-14


Table of Contents
Index to Financial Statements

INERGY MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

 

Inergy Midstream 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. Inergy Midstream has determined that no impairment exists as of September 30, 2010.

 

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.

 

Inergy Midstream has recorded certain identifiable intangible assets, including customer accounts and covenants not to compete. Customer accounts and covenants not to compete have arisen from the various acquisitions by Inergy Midstream and are amortized on a straight-line basis over their estimated economic lives, as follows:

 

     Weighted-Average
Life

(years)
 

Customer accounts

     20.0   

Covenants not to compete

     3.8   

 

Estimated amortization for the next five years ending September 30, is as follows (in millions):

 

Year Ending September 30,

      

2011

   $ 2.7   

2012

     2.3   

2013

     1.8   

2014

     1.8   

2015

     1.8   

 

Goodwill

 

Goodwill is recognized for various acquisitions by Inergy Midstream 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, Inergy Midstream identified one reporting unit. The carrying value of this reporting unit is determined by assigning the assets and liabilities, including the existing goodwill and intangible assets, to the reporting unit as of the date of the evaluation on a specific identification basis. To the extent the reporting unit’s carrying value exceeds its fair value, an indication exists that the reporting unit’s goodwill may be impaired and the second step of the impairment test must be performed. In the second step, the implied fair value of the goodwill is determined by allocating the fair value to all of its assets (recognized and unrecognized) and liabilities to its carrying amount.

 

Inergy Midstream has completed the impairment test for its reporting unit and determined that no impairment existed as of September 30, 2010.

 

F-15


Table of Contents
Index to Financial Statements

INERGY MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

 

Income Taxes

 

Inergy Midstream and Inergy, L.P. are generally not subject to federal or state income tax. Therefore, the earnings of Inergy Midstream are included in the federal and state income tax returns of the individual partners of Inergy, L.P. Net earnings for financial statement purposes may differ significantly from taxable income reportable to unitholders as a result of differences between the tax basis and the financial reporting basis of assets and liabilities and the taxable income allocation requirements under the partnership agreement.

 

Cash and Cash Equivalents

 

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

 

Fair Value

 

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

 

Transactions with Inergy, L.P. and Inergy Propane, LLC

 

Inergy, L.P., through Inergy Propane, LLC has historically provided Inergy Midstream with funding to support acquisitions, capital expansion and working capital needs. The amounts provided by Inergy, L.P. to finance acquisitions are considered to be permanent investments by Inergy, L.P. and have accordingly been classified as parent company’s investment on the consolidated financial statements of Inergy Midstream. Amounts financed to support capital expansion and working capital needs, net of what Inergy Midstream has provided to Inergy Propane, LLC, are considered to be loans and are classified as payable to Inergy Propane, LLC and Inergy, L.P. on the consolidated financial statements of Inergy Midstream.

 

Interest is charged on these balances during the period of construction of Inergy Midstream’s expansion projects.

 

Allocation of Expenses

 

Inergy Midstream shares common management, operating and administrative and overhead costs with Inergy, L.P. The following summarizes the assumptions utilized by management in allocating these shared costs to Inergy Midstream. The shared costs allocated to Inergy Midstream totaled $9.9 million, $6.6 million and $7.1 million for the years ended September 30, 2010, 2009 and 2008, respectively. 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 Inergy Midstream had operated as a stand-alone entity.

 

Professional service fees—Fees incurred for accounting, audit, IT and legal services that benefit both Inergy, L.P. and Inergy Midstream have been allocated based primarily on a combination of the following two methods: (1) the percentage of Inergy Midstream’s transactions relative to total transactions with an equal value assigned to each transaction and (2) the percentage of Inergy Midstream’s net income before interest, taxes and depreciation and amortization (EBITDA) to Inergy, L.P.’s EBITDA. Amounts allocated to Inergy Midstream from Inergy, L.P. for such items were $1.5 million, $0.9 million and $1.1 million for the years ended September 30, 2010, 2009 and 2008, respectively.

 

F-16


Table of Contents
Index to Financial Statements

INERGY MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

 

Insurance expenses—Inergy, L.P. utilizes third-party insurance subject to varying retention levels of self-insurance, which management considers prudent. Costs associated with health and dental insurance, workers’ compensation insurance and general liability insurance have been allocated based primarily on a combination of the following three methods: (1) specific identification of loss information related to Inergy Midstream employees, (2) the percentage of Inergy Midstream’s EBITDA to Inergy, L.P.’s EBITDA and (3) state workers’ compensation rates for Midstream employees. Amounts allocated to Inergy Midstream from Inergy, L.P. for such items were $2.0 million, $1.8 million and $1.3 million for the years ended September 30, 2010, 2009 and 2008, respectively.

 

Personnel expenses—Costs associated with certain executive and administrative employees that provide services to both Inergy Midstream and Inergy, L.P. have been allocated based primarily on a combination of the following two methods: (1) specific identification of compensation information related to Inergy Midstream employees and (2) the percentage of Inergy Midstream’s EBITDA to Inergy, L.P.’s EBITDA. Amounts allocated to Inergy Midstream from Inergy, L.P. for such items were $5.2 million, $2.9 million and $3.4 million for the years ended September 30, 2010, 2009 and 2008, respectively. The aforementioned amounts include an allocation of long-term incentive and equity compensation in the amounts of $2.7 million, $0.7 million and $0.5 million for the years ended September 30, 2010, 2009 and 2008, respectively.

 

Fixed assets—Depreciation associated with corporate fixed assets benefiting Inergy, L.P. and Inergy Midstream have been allocated based on the percentage of Inergy Midstream’s EBITDA to Inergy, L.P.’s EBITDA. Depreciation amounts allocated to Inergy Midstream from Inergy, L.P. for corporate fixed assets were $0.3 million for the years ended September 30, 2010 and 2009, and $0.4 million for the year ended September 30, 2008.

 

Other expenses—Other operating expenses incurred, predominantly for rent, bank fees and membership dues, etc, that benefit both Inergy, L.P. and Inergy Midstream have been allocated based on the percentage of Inergy Midstream’s EBITDA to Inergy, L.P.’s EBITDA. Amounts allocated to Inergy Midstream from Inergy, L.P. for such items were $0.9 million for the years ended September 30, 2010 and 2008, and $0.7 million for the year ended September 30, 2009.

 

Comprehensive Income (Loss)

 

Comprehensive income includes net income and other comprehensive income. Other comprehensive income includes the realized loss on a derivative instrument that Inergy Midstream entered into to hedge the purchase of base gas for one of its storage facilities. 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.

 

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 $3.7 million and $7.0 million as of September 30, 2010 and 2009, respectively. These amounts have been classified in prepaid expenses and other current assets on the consolidated balance sheets.

 

Exchange Agreements

 

The Company will periodically enter into gas exchange contracts to optimize the storage field. Amounts prepaid for these contracts amounted to $0.5 million and $3.5 million as of September 30, 2010 and 2009, respectively. These amounts have been classified in prepaid expenses and other current assets on the consolidated balance sheets.

 

F-17


Table of Contents
Index to Financial Statements

INERGY MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

 

Accrued Payroll

 

The Company’s accrued payroll amounted to $0.9 million and $0.8 million as of September 30, 2010 and 2009, respectively. These amounts have been classified in accrued expenses on the consolidated balance sheets.

 

Asset Retirement Obligations

 

As asset retirement obligation (ARO) is an estimated liability for the cost to retire a tangible asset. The fair value of certain AROs could not be made as settlement dates (or range of dates) associated with these assets were not estimable.

 

Earnings Per Share

 

Basic and diluted net income per common unit holder is not presented since the ownership structure of the Company is a single member limited liability company.

 

Reportable Segment

 

The Company has determined that is has one operating and one reportable segment based on the information reviewed by its chief operating decision maker in making decisions regarding allocation of resources.

 

Noncontrolling Interest

 

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

 

Recently Issued Accounting Pronouncements

 

Financial Accounting Standards Board (“FASB”) Accounting Standards Codification Subtopic 810-10 (“810-10”), originally issued as SFAS No. 160, “Non-controlling Interests in Consolidated Financial Statements—an amendment of ARB No. 51”, was issued in December 2007 and requires that accounting and reporting for minority interests will be recharacterized as non-controlling interests and classified as a component of equity. 810-10 also establishes reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the non-controlling owners. 810-10 applies to all entities that prepare consolidated financial statements, except not-for-profit organizations, but will affect only those entities that have an outstanding non-controlling interest in one or more subsidiaries or that deconsolidate a subsidiary. Inergy Midstream adopted 810-10 on October 1, 2009. The adoption of 810-10 did not have a material impact on Inergy Midstream’s results of operations or financial position.

 

Note 3. Acquisitions

 

During the fiscal year 2010, Inergy Midstream acquired the remaining 45% interest in Steuben Gas that the Company did not own previously. Steuben Gas became an indirect, wholly owned subsidiary of Inergy Midstream as a result of this acquisition. This acquisition of the additional interest increased net income attributable to partners by $0.8 million for the year ended September 30, 2010.

 

F-18


Table of Contents
Index to Financial Statements

INERGY MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

 

Note 4. Certain Balance Sheet Information

 

Property, Plant and Equipment

 

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

 

     September 30,  
     2010      2009  

Plant equipment

   $ 104.9       $ 81.1   

Land and buildings

     287.6         230.3   

Vehicles

     2.1         1.9   

Construction in process

     64.7         110.7   

Base gas

     69.9         62.3   

Office furniture and equipment

     0.1         0.1   
  

 

 

    

 

 

 
     529.3         486.4   

Less: accumulated depreciation

     100.9         68.4   
  

 

 

    

 

 

 

Total property, plant and equipment, net

   $ 428.4       $ 418.0   
  

 

 

    

 

 

 

 

Depreciation expense totaled $32.9 million, $26.7 million and $22.0 million for the years ended September 30, 2010, 2009 and 2008, respectively.

 

Intangible Assets

 

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

 

     September 30,  
     2010     2009  

Customer accounts

   $ 36.3      $ 36.3   

(accumulated amortization—customer accounts)

     (10.3     (8.2

Covenants not to compete

     7.0        7.0   

(accumulated amortization—covenants not to compete)

     (5.6     (4.7

Deferred financing and other costs

            0.5   

(accumulated amortization—deferred financing costs)

            (0.1
  

 

 

   

 

 

 

Total intangible assets, net

   $ 27.4      $ 30.8   
  

 

 

   

 

 

 

 

Amortization associated with the above described intangible assets was $3.3 million for the year ended September 30, 2010, and $2.5 million for the years ended September 30, 2009 and 2008.

 

Note 5. Long-Term Debt

 

ASC Credit Agreement

 

Steuben Gas, a wholly owned subsidiary of ASC, had a loan agreement (the “ASC Credit Agreement”) in place at the time Inergy Midstream acquired ASC. In July 2010, Inergy Midstream paid in full the balance outstanding under the ASC Credit Agreement. Interest associated with this debt was capitalized.

 

F-19


Table of Contents
Index to Financial Statements

INERGY MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

 

Note 6. Employee Benefit Plans

 

Inergy, L.P. sponsors a 401(k) plan which is available to all of Inergy Midstream’s employees after meeting certain requirements. The plan permits employees to make contributions up to 75% of their salary, up to statutory limits, which was $16,500 in 2010. The plan provides for matching contributions by Inergy, LP for employees completing one year of service of at least 1,000 hours. Aggregate matching contributions allocated to Inergy Midstream were $0.1 million in fiscal 2010, 2009 and 2008.

 

Note 7. Commitments and Contingencies

 

Inergy Midstream has entered into certain purchase commitments in connection with the identified growth projects primarily related to the North/South pipeline compression project and the Watkins Glen NGL storage development. At September 30, 2010, the total of these firm purchase commitments was $12.3 million and the purchases associated with these commitments are expected to occur over the course of the next twelve months.

 

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

 

Inergy Midstream guarantees certain indebtedness of Inergy, L.P. and Inergy Finance Corp. Inergy Midstream’s guarantee of certain indebtedness of Inergy, L.P. and Inergy Finance Corp. will be terminated in connection with Inergy Midstream’s initial public offering. The indentures governing the above described Inergy, L.P. and Inergy Finance Corp. debt restrict the Company’s ability to pay dividends. The amount of such debt at September 30, 2010, was $1,650 million.

 

Note 8. Related Party Transactions

 

Inergy Midstream has recorded sales to Inergy, L.P. of $0.5 million and $0.1 million for the fiscal years ended September 30, 2010 and 2009, respectively. The sales relate to storage space leased at the Company’s Bath storage facility. Inergy Midstream had no sales to Inergy, L.P. for the fiscal year ended September 30, 2008. These sales increased Inergy Midstream’s net income by $0.5 million and $0.1 million for the fiscal years ended September 30, 2010 and 2009, respectively.

 

As discussed in Note 2, Inergy, L.P. has historically funded certain activities of Inergy Midstream.

 

Note 9. Subsequent Events

 

The Company has identified subsequent events requiring disclosure through the date of the filing of this Form S-1.

 

On July 13, 2011, Inergy Midstream closed on its previously announced acquisition of the Seneca Lake natural gas storage facility located in Schuyler County, New York, and two related pipelines for approximately $65 million from New York State Electric & Gas Corporation. The natural gas storage facility and its West lateral were acquired by Arlington Storage Company, LLC (“ASC”) and are subject to FERC jurisdiction. The intrastate 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, L.P. This acquisition of assets collectively constitutes a business and has been accounted for under FASB Accounting Standards Codification 805.

 

F-20


Table of Contents
Index to Financial Statements

INERGY MIDSTREAM, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

 

The Company is in the process of finalizing its valuations of certain property, plant and equipment as well as identifiable intangible assets; thus the provisional measurements of property, plant and equipment, intangible assets and goodwill are subject to material change. The following table summarizes the estimated fair value of the assets acquired at the acquisition date (in millions):

 

     July 13, 2011  

Property, plant and equipment

   $ 66.8   

 

The following represents the pro forma consolidated statements of operations as if Seneca Lake had been acquired on October 1, 2009 (in millions):

 

     Year ended
September 30, 2010
 

Revenue

     103.2   

Net Income

     34.4   

 

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.

 

F-21


Table of Contents
Index to Financial Statements

INERGY MIDSTREAM, LLC

CONSOLIDATED BALANCE SHEETS

(in millions)

 

     June 30,
2011
     September 30,
2010
 
     (unaudited)         

Assets

     

Current assets:

     

Cash and cash equivalents

   $ 9.4       $   

Accounts receivable

     9.1         7.7   

Inventories

     1.1         0.8   

Prepaid expenses and other current assets

     0.8         5.0   
  

 

 

    

 

 

 

Total current assets

     20.4         13.5   

Property, plant and equipment (Note 3)

     597.2         529.3   

Less: accumulated depreciation

     125.9         100.9   
  

 

 

    

 

 

 

Property, plant and equipment, net

     471.3         428.4   

Intangible assets (Note 3):

     

Customer accounts

     36.3         36.3   

Other intangible assets

     7.0         7.0   
  

 

 

    

 

 

 
     43.3         43.3   

Less: accumulated amortization

     17.9         15.9   
  

 

 

    

 

 

 

Intangible assets, net

     25.4         27.4   

Goodwill

     90.2         90.2   
  

 

 

    

 

 

 

Total assets

   $ 607.3       $ 559.5   
  

 

 

    

 

 

 

Liabilities and partners’ capital

     

Current liabilities:

     

Accounts payable

   $ 4.6       $ 0.4   

Accrued expenses

     2.2         3.3   

Bank overdraft

             0.9   

Payable to Inergy Propane, LLC and Inergy, L.P.

     123.7         109.2   
  

 

 

    

 

 

 

Total current liabilities

     130.5         113.8   

Other long-term liabilities

     0.9         0.9   

Total member’s capital

     475.9         444.8   
  

 

 

    

 

 

 

Total liabilities and capital

   $ 607.3       $ 559.5   
  

 

 

    

 

 

 

 

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

 

F-22


Table of Contents
Index to Financial Statements

INERGY MIDSTREAM, LLC

CONSOLIDATED STATEMENTS OF OPERATIONS

(in millions)

(unaudited)

 

     Nine Months Ended
June 30,
 
         2011              2010      

Revenue:

     

Firm storage

   $ 67.3       $ 58.6   

Transportation

     9.5         9.1   

Hub services

     3.5         1.4   
  

 

 

    

 

 

 
     80.3         69.1   

Cost of services sold (excluding depreciation and amortization as shown below):

     

Storage

     6.8         4.6   

Transportation

     5.1         5.1   
  

 

 

    

 

 

 
     11.9         9.7   
  

 

 

    

 

 

 

Gross profit

     68.4         59.4   

Expenses:

     

Operating and administrative

     10.1         11.3   

Depreciation and amortization

     27.3         26.7   

Loss on disposal of assets

             0.9   
  

 

 

    

 

 

 

Net income

     31.0         20.5   

Net income attributable to non-controlling partners

             0.8   
  

 

 

    

 

 

 

Net income attributable to member

   $ 31.0       $ 19.7   
  

 

 

    

 

 

 

 

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

 

F-23


Table of Contents
Index to Financial Statements

INERGY MIDSTREAM, LLC

CONSOLIDATED STATEMENT OF MEMBER’S CAPITAL

(in millions)

(unaudited)

 

     Total Member’s
Capital
 

Balance at September 30, 2010

   $ 444.8   

Comprehensive income:

  

Net income

     31.0   

Reclassification of cash flow hedges

     0.1   
  

 

 

 

Comprehensive income

     31.1   
  

 

 

 

Balance at June 30, 2011

   $ 475.9   
  

 

 

 

 

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

 

F-24


Table of Contents
Index to Financial Statements

INERGY MIDSTREAM, LLC

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

(unaudited)

 

     Nine Months Ended
June 30,
 
         2011             2010      

Operating activities

    

Net income

   $ 31.0      $ 20.5   

Adjustments to reconcile net income to net cash provided by operating activities:

    

Depreciation

     25.3        24.5   

Amortization

     2.0        2.2   

Loss on disposal of assets

            0.9   

Changes in operating assets and liabilities:

    

Accounts receivable

     (1.4     (1.7

Inventories

     (0.3     (0.7

Prepaid expenses and other current assets

     4.2        7.1   

Other liabilities

            (1.2

Accounts payable and accrued expenses

     (0.7     (3.3

Bank overdraft

     (0.9       

Payable to Inergy Propane, LLC and Inergy, L.P.

     6.0        8.5   
  

 

 

   

 

 

 

Net cash provided by operating activities

     65.2        56.8   

Investing activities

    

Purchases of property, plant and equipment

     (64.1     (38.4
  

 

 

   

 

 

 

Net cash used in investing activities

     (64.1     (38.4

 

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

 

F-25


Table of Contents
Index to Financial Statements

INERGY MIDSTREAM, LLC

CONSOLIDATED STATEMENTS OF CASH FLOWS (continued)

(in millions)

(unaudited)

 

     Nine Months Ended
June 30,
 
         2011             2010      

Financing activities

    

Borrowings from related party

   $ 63.0      $ 49.0   

Payments to related party

     (54.7     (66.4

Principal payments on long-term debt

            (2.0

Acquisition of minority interest

            (14.2

Equity contribution from parent

            14.2   

Distributions paid to non-controlling partners

            (0.6
  

 

 

   

 

 

 

Net cash provided by (used in) financing activities

     8.3        (20.0

Net increase (decrease) in cash

     9.4        (1.6

Cash at beginning of period

            3.6   
  

 

 

   

 

 

 

Cash at end of period

   $ 9.4      $ 2.0   
  

 

 

   

 

 

 

Supplemental schedule of noncash investing and financing activities

    

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

   $ 3.9      $ (6.2
  

 

 

   

 

 

 

 

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

 

F-26


Table of Contents
Index to Financial Statements

INERGY MIDSTREAM, LLC

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

 

Note 1—Partnership Organization and Basis of Presentation

 

Organization

 

Inergy Midstream, LLC (“Inergy Midstream” or the “Company”) is a wholly owned subsidiary of Inergy, L.P., its sole member. The sole member’s maximum liability arising from its investment in a limited liability company is limited to the amount of its investment.

 

Nature of Operations

 

Inergy Midstream is engaged primarily in the storage and transportation of natural gas and natural gas liquids. Inergy Midstream’s operations are primarily concentrated in the Northeast region of the United States.

 

Inergy Midstream owns and operate the following assets:

 

   

Stagecoach, a 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 multi-cycle depleted reservoir natural gas storage facility located in Steuben County, New York.

 

   

Steuben, a single-turn depleted reservoir natural gas storage facility located in Steuben County, New York.

 

   

Bath NGL storage facility located near Bath, New York.

 

Basis of Presentation

 

Inergy Midstream is a wholly owned subsidiary of Inergy, L.P., and the accompanying consolidated financial statements have been prepared to represent the net assets and related historical results of Inergy Midstream as if it were a stand-alone entity with the exception that the operations of Tres Palacios Gas Storage LLC and US Salt, LLC have been excluded from the historical Inergy Midstream operations. The general ledger of each of the entities owned by Inergy Midstream (excluding Tres Palacios Gas Storage LLC and US Salt, LLC) forms the primary basis for the accompanying financial statements. Costs incurred by Inergy, L.P. benefiting both Inergy Midstream and Inergy Propane, LLC have been allocated in a manner described in “Allocation of Expenses” below.

 

The financial information contained herein as of June 30, 2011, and for the nine-month periods ended June 30, 2011 and 2010, is unaudited. The Company believes this information has been prepared in accordance with accounting principles generally accepted in the United States for interim financial information and Article 10 of Regulation S-X. The Company also believes this information includes all adjustments (consisting only of normal recurring adjustments) necessary to present fairly the financial position, results of operations and cash flows for the periods then ended. The results of operations for the nine-month periods ended June 30, 2011 and 2010, are not indicative of the results of operations that may be expected for the entire fiscal year.

 

The accompanying consolidated financial statements should be read in conjunction with the consolidated financial statements of Inergy Midstream, LLC and subsidiaries and the notes thereto for the fiscal year ended September 30, 2010.

 

Principles of Consolidation

 

The accompanying consolidated financial statements include the accounts of Inergy Midstream, LLC as well as all of its subsidiaries. All significant intercompany balances and transactions have been eliminated in consolidation.

 

F-27


Table of Contents
Index to Financial Statements

INERGY MIDSTREAM, LLC

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

 

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 our customers. Revenue for transportation services is recognized ratably over the contract period regardless of the volume of natural gas that has shipped. Transportation revenue is derived entirely from the sale of capacity that the Company has secured on certain third party pipelines. Revenue from hub services is recognized ratably over the contract period. The contract period for hub services is typically less than one year.

 

Expense Classification

 

Cost of storage services provided consists of the direct costs to operate the storage facilities including power, contractor and fuel costs. These costs support the revenue generated from firm storage and hub services. Our transportation cost of services sold consist of cost to procure firm transportation capacity on certain pipelines. In limited instances, the Company may sell inventory obtained from fuel-in-kind collections. The cost basis of this inventory will be recorded in cost of storage services sold. Operating and administrative expenses consist of all expenses incurred by Inergy Midstream other than those described above in cost of sales and depreciation and amortization. Certain of Inergy Midstream’s operating and administrative expenses and depreciation and amortization are incurred in providing storage services, but are not included in cost of services sold. These amounts were $26.4 million and $25.1 million for the nine months ended June 30, 2011 and 2010, respectively.

 

Credit Risk and Concentrations

 

Inergy Midstream generally extends unsecured credit to the majority of its customer base. Credit for our customers is extended based on an evaluation of each customer’s financial condition. A substantial portion of Inergy Midstream’s customer base is investment grade companies. Historically, write-offs for uncollectible accounts have been insignificant and the Company has determined that an allowance for doubtful accounts is not necessary at either June 30, 2011 or September 30, 2010.

 

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 are stated at the lower of cost or market and are computed predominantly using the average cost method.

 

Property, Plant and Equipment

 

Property, plant and equipment are stated at historical cost less accumulated depreciation. We capitalize 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 $4.0 million and $3.2 million for the nine months ended June 30, 2011 and 2010, respectively. Depreciation is computed by the straight-line method over the estimated useful lives of the assets, as follows:

 

     Years  

Land, improvement and buildings

     15-25   

Office furniture and equipment

     3–7   

Vehicles

     5   

Base Gas

     10   

Plant Equipment

     15   

 

F-28


Table of Contents
Index to Financial Statements

INERGY MIDSTREAM, LLC

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

 

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.

 

Inergy Midstream has recorded certain identifiable intangible assets, including customer accounts and covenants not to compete. Customer accounts and covenants not to compete have arisen from the various acquisitions by Inergy Midstream and are amortized on a straight-line basis over their estimated economic lives, as follows:

 

     Years  

Customer accounts

     4-20   

Covenants not to compete

     3-5   

 

Goodwill

 

Goodwill is recognized for various acquisitions by Inergy Midstream 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, Inergy Midstream identified one reporting unit. The carrying value of this reporting unit is determined by assigning the assets and liabilities, including the existing goodwill and intangible assets, to the reporting unit as of the date of the evaluation on a specific identification basis. To the extent the reporting unit’s carrying value exceeds its fair value, an indication exists that the reporting unit’s goodwill may be impaired and the second step of the impairment test must be performed. In the second step, the implied fair value of the goodwill is determined by allocating the fair value to all of its assets (recognized and unrecognized) and liabilities to its carrying amount.

 

Inergy Midstream has completed the impairment test for its reporting unit and determined that no impairment existed as of September 30, 2010. No indicators of impairment were identified requiring an interim impairment test during the nine-month period ended June 30, 2011.

 

Income Taxes

 

Inergy Midstream and Inergy, L.P. are disregarded for income tax purposes. Therefore, the earnings of Inergy Midstream are included in the federal and state income tax returns of the individual partners of Inergy, L.P. Net earnings for financial statement purposes may differ significantly from taxable income reportable to unitholders as a result of differences between the tax basis and the financial reporting basis of assets and liabilities and the taxable income allocation requirements under the partnership agreement.

 

Fair Value

 

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

 

Transactions with Inergy, L.P. and Inergy Propane, LLC

 

Inergy, L.P., through Inergy Propane, LLC, has historically provided Inergy Midstream with funding to support acquisitions, capital expansion and working capital needs. The amounts provided by Inergy, L.P. to finance acquisitions are considered to be permanent investments by Inergy, L.P. and have accordingly been classified as parent companies’ investment on the consolidated financial statements of Inergy Midstream. Amounts financed to support capital expansion and working capital needs, net of what Inergy Midstream has provided to Inergy Propane, LLC, are considered to be loans and are classified as payable to Inergy Propane, LLC and Inergy, L.P. on the consolidated financial statements of Inergy Midstream.

 

Interest is charged on these balances during the period of construction of Inergy Midstream’s expansion projects.

 

F-29


Table of Contents
Index to Financial Statements

INERGY MIDSTREAM, LLC

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

 

Allocation of Expenses

 

Inergy Midstream shares common management, general and administrative and overhead costs with Inergy, L.P. The following summarizes the assumptions utilized by management in allocating these shared costs to Inergy Midstream. The shared costs allocated to Inergy Midstream totaled $5.8 million and $7.4 million for the nine months ended June 30, 2011 and 2010, respectively. 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 Inergy Midstream had operated as a stand-alone entity.

 

Professional service fees—Fees incurred for accounting, audit, IT and legal services that benefit both Inergy, L.P. and Inergy Midstream have been allocated based primarily on a combination of the following two methods: (1) the percentage of Inergy Midstream’s transactions relative to total transactions with an equal value assigned to each transaction and (2) the percentage of Inergy Midstream’s net income before income taxes, plus net interest expense and depreciation and amortization (EBITDA) to Inergy, L.P.’s EBITDA. Amounts allocated to Inergy Midstream from Inergy, L.P. for such items were $0.8 million and $1.2 million for the nine months ended June 30, 2011 and 2010, respectively.

 

Insurance expenses—Inergy, L.P. utilizes third-party insurance subject to varying retention levels of self-insurance, which management considers prudent. Costs associated with health and dental insurance, workers’ compensation insurance and general liability insurance have been allocated based primarily on a combination of the following three methods: (1) specific identification of loss information related to Inergy Midstream employees, (2) the percentage of Inergy Midstream’s EBITDA to Inergy, L.P.’s EBITDA and (3) state workers’ compensation rates for Midstream employees. Amounts allocated to Inergy Midstream from Inergy, L.P. for such items were $1.9 million and $1.5 million for the nine months ended June 30, 2011 and 2010, respectively.

 

Personnel expenses—Costs associated with certain executive and administrative employees that provide services to both Inergy Midstream and Inergy, L.P. have been allocated based primarily on a combination of the following two methods: (1) specific identification of compensation information related to Inergy Midstream employees and (2) the percentage of Inergy Midstream’s EBITDA to Inergy, L.P.’s EBITDA. Amounts allocated to Inergy Midstream from Inergy, L.P. for such items were $2.3 million and $3.9 million for the nine months ended June 30, 2011 and 2010, respectively. The aforementioned amounts include an allocation of long-term incentive and equity compensation in the amounts of $0.9 million and $2.0 million for the nine months ended June 30, 2011 and 2010, respectively.

 

Fixed assets—Depreciation associated with corporate fixed assets benefiting Inergy, L.P. and Inergy Midstream have been allocated based on the percentage of Inergy Midstream’s EBITDA to Inergy, L.P.’s EBITDA. Depreciation amounts allocated to Inergy Midstream from Inergy, L.P. for corporate fixed assets were $0.2 million for the nine months ended June 30, 2011 and 2010.

 

Other expenses—Other operating expenses incurred, predominantly for rent, bank fees and membership dues, etc, that benefit both Inergy, L.P. and Inergy Midstream have been allocated based on the percentage of Inergy Midstream’s EBITDA to Inergy, L.P.’s EBITDA. Amounts allocated to Inergy Midstream from Inergy, L.P. for such items were $0.6 million for the nine months ended June 30, 2011 and 2010.

 

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 $3.7 million as of September 30, 2010 and no such amount was due at June 30, 2011. This amount has been classified in prepaid expenses and other current assets on the consolidated balance sheets.

 

F-30


Table of Contents
Index to Financial Statements

INERGY MIDSTREAM, LLC

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

 

Accrued Payroll

 

The Company’s accrued payroll amounted to $0.3 million and $0.9 million as of June 30, 2011 and September 30, 2010, respectively. These amounts have been classified in accrued expenses on the consolidated balance sheets.

 

Asset Retirement Obligations

 

An asset retirement obligation (ARO) is an estimated liability for the cost to retire a tangible asset. The fair value for certain AROs could not be made as settlement dates (or range of dates) associated with these assets were not estimable.

 

Earnings Per Share

 

Basic and diluted net income per common unit is not presented since the ownership structure of the Company is a single member limited liability company.

 

Reportable Segment

 

The Company has determined that is has one operating and one reportable segment based on the information reviewed by its chief operating decision maker in making decisions regarding allocation of resources.

 

Noncontrolling Interest

 

The noncontrolling interest on the consolidated statement of operations is related entirely to minority partners in the Company’s Steuben natural gas storage facility. The noncontrolling 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. The amendments contained in ASU 2011-05 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 unit is calculated or presented. ASU 2011-05 will be effective for Inergy Midstream on October 1, 2012. Inergy Midstream does not currently anticipate the adoption of ASU 2011-05 will impact comprehensive income; however, it will require Inergy Midstream to change its historical practice of presenting these items within the Consolidated Statement of Partners’ Capital.

 

F-31


Table of Contents
Index to Financial Statements

INERGY MIDSTREAM, LLC

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

 

Note 3—Certain Balance Sheet Information

 

Property, plant and equipment consisted of the following at June 30, 2011 and September 30, 2010, respectively (in millions):

 

     June 30,
2011
     September 30,
2010
 

Plant equipment

   $ 108.5       $ 104.9   

Land and buildings

     289.7         287.6   

Vehicles

     2.3         2.1   

Construction in process

     126.7         64.7   

Base gas

     69.9         69.9   

Office furniture and equipment

     0.1         0.1   
  

 

 

    

 

 

 
     597.2         529.3   

Less: accumulated depreciation

     125.9         100.9   
  

 

 

    

 

 

 

Total property, plant and equipment, net

   $ 471.3       $ 428.4   
  

 

 

    

 

 

 

 

Intangible assets consisted of the following at June 30, 2011 and September 30, 2010, respectively (in millions):

 

     June 30,
2011
     September 30,
2010
 

Customer accounts

   $ 36.3       $ 36.3   

Covenants not to compete

     7.0         7.0   
  

 

 

    

 

 

 
     43.3         43.3   

Less: accumulated amortization

     17.9         15.9   
  

 

 

    

 

 

 

Total intangible assets, net

   $ 25.4       $ 27.4   
  

 

 

    

 

 

 

 

Note 4—Commitments and Contingencies

 

Inergy Midstream has entered into certain purchase commitments in connection with the identified growth projects primarily related to the North/South pipeline compression project and the Watkins Glen NGL storage development. At June 30, 2011, the total of these firm purchase commitments was $47.8 million and the purchases associated with these commitments are expected to occur over the course of the next twelve months.

 

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

 

Inergy Midstream guarantees certain indebtedness of Inergy, L.P. and Inergy Finance Corp. Inergy Midstream’s guarantee of certain indebtedness of Inergy, L.P. and Inergy Finance Corp. will be terminated in connection with Inergy Midstream’s initial public offering. The indentures governing the above described Inergy, L.P. and Inergy Finance Corp. debt restrict the Company’s ability to pay dividends except to Inergy, L.P. or to the holders of the Company’s equity interests on a pro rata basis. The amount of such debt at June 30, 2011, was $1,766.1 million.

 

Note 5—Related Party Transactions

 

Inergy Midstream has recorded sales to Inergy, L.P. of $2.2 million and $0.3 million for the nine months ended June 30, 2011 and 2010, respectively. The sales relate to storage space leased at the Company’s Bath storage facility. These sales increased Inergy Midstream’s net income by $2.2 million and $0.3 million for the nine months ended June 30, 2011 and 2010, respectively.

 

As discussed in Note 2, Inergy, L.P. has historically funded certain activities of Inergy Midstream.

 

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INERGY MIDSTREAM, LLC

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

 

Note 6—Subsequent Events

 

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

 

On July 13, 2011, Inergy Midstream closed on its previously announced acquisition of the Seneca Lake natural gas storage facility located in Schuyler County, New York, and two related pipelines for approximately $65 million from New York State Electric & Gas Corporation. The natural gas storage facility and its West lateral were acquired by Arlington Storage Company, LLC (“ASC”) and are subject to FERC jurisdiction. The intrastate 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, L.P. This acquisition of assets collectively constitutes a business and has been accounted for under FASB Accounting Standards Codification 805.

 

The Company is in the process of finalizing its valuations of certain property, plant and equipment as well as identifiable intangible assets; thus the provisional measurements of property, plant and equipment, intangible assets and goodwill are subject to material change. The following table summarizes the estimated fair value of the assets acquired at the acquisition date (in millions):

 

     July 13, 2011  

Property, plant and equipment

   $ 66.8   

 

The following represents the pro-forma consolidated statements of operations as if Seneca Lake had been acquired on October 1, 2009 (in millions):

 

     Nine months
ended
June 30, 2011
 

Revenue

     86.7   

Net Income

     33.2   

 

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.

 

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APPENDIX A

 

FORM OF

 

FIRST AMENDED AND RESTATED

 

AGREEMENT OF LIMITED PARTNERSHIP

 

OF

 

INERGY MIDSTREAM, L.P.

 

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Index to Financial Statements

APPENDIX B

 

GLOSSARY OF TERMS

 

Adjusted EBITDA: a supplemental non-GAAP financial measure defined by us as EBITDA excluding the gain or loss on the disposal of assets, long-term incentive and equity compensation expenses, transaction costs and interest of non-controlling partners.

 

aquifers: a naturally occurring underground rock formation that only contains formation water and never had any accumulation of crude oil or natural gas.

 

balancing services: those services pursuant to 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.

 

barrel (or bbl): one barrel of petroleum products equals 42 U.S. gallons.

 

base gas (or cushion gas): the volume of natural gas needed as a permanent inventory to maintain adequate reservoir pressures and deliverability rates.

 

Bcf: one billion cubic feet.

 

Bcf/d: one billion cubic feet per day.

 

capital account: the capital account maintained for a partner under the partnership agreement. The capital account of a partner for a common unit, an incentive distribution right or any other partnership interest will be the amount which that capital account would be if that common unit, incentive distribution right or other partnership interest were the only interest in the partnership held by a partner.

 

city gate: a point or measuring station at which a distributing natural gas utility receives natural gas from a natural gas pipeline company or transmission system.

 

cycle: a complete withdrawal and injection of working gas.

 

cycling fees: fees typically collected under a firm storage contract based on the volume of natural gas nominated for injection and/or withdrawal.

 

depleted reservoir: a sub-surface natural geological reservoir, usually a depleted natural gas or oil field, used for storing natural gas.

 

EBITDA: a supplemental non-GAAP financial measure defined by us as income before income taxes, plus net interest expense and depreciation and amortization expense.

 

FERC: U.S. Federal Energy Regulatory Commission.

 

firm storage services: our firm storage services include storage services pursuant to which customers receive an assured, or “firm,” right to store natural gas (or, if applicable, NGLs) in our facilities over a defined period.

 

GAAP: generally accepted accounting principles.

 

 

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Index to Financial Statements

header system: the network of pipelines that connect a storage facility to interstate or intrastate pipelines, or both, as applicable, through a series of interconnects.

 

hub: geographic location of a natural gas storage facility and multiple pipeline interconnections.

 

hub services: our hub services include (i) “interruptible” storage services; (ii) firm and interruptible “park and loan” services; (iii) interruptible “wheeling” services; and (iv) balancing services.

 

incentive distribution rights: rights that entitle the holder to receive 50% of the cash we distribute from operating surplus in excess of the initial quarterly distribution.

 

injection rate: the rate at which a customer is permitted to inject natural gas into a natural gas storage facility.

 

interruptible storage services: those services pursuant to 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.

 

liquefied natural gas (or 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. We have converted each of the throughput numbers from a heating value number to a volumetric number based upon the following conversion factor: 1 MMbtu = 1 Mcf.

 

MMbtu: one million British thermal units, which is approximately equivalent to one Mcf. One British thermal unit is equivalent to the amount of heat required to raise the temperature of one pound of water by one degree.

 

MMcf: one million cubic feet.

 

MMcf/d: one million cubic feet per day.

 

natural gas: a gaseous mixture of hydrocarbon compounds, the primary one being methane, but other components include ethane, propane and butane.

 

natural gas liquids (or 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. Generally such liquids consist of propane and heavier hydrocarbons and are commonly referred to as lease condensate, natural gasoline and liquefied petroleum gases. 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).

 

NYMEX: New York Mercantile Exchange, Inc.

 

park and loan services: those services pursuant to which customers receive the right to store natural gas in (park), or borrow gas from (loan), our facilities on a seasonal basis.

 

reservoir: a porous and permeable underground formation containing an individual and separate natural accumulation of producible hydrocarbons (crude oil and/or natural gas) which is confined by impermeable rock or water barriers and is characterized by a single natural pressure system.

 

salt cavern: a man made cavern developed in either a salt dome or salt beds by leaching or mining of the salt.

 

salt dome: domical arch (anticline) of sedimentary rock beneath the earth’s surface in which the layers bend downward in opposite directions from the crest and that has a mass of rock salt as its core.

 

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Index to Financial Statements

shale gas: natural gas produced from organic (black) shale formations.

 

Tcf: one trillion cubic feet.

 

wheeling: 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 the actual storage but merely uses the surface facilities of the storage operation.

 

wheeling services: those services pursuant to 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.

 

withdrawal rate: the rate at which a customer is permitted to withdraw natural gas from a natural gas storage facility.

 

working gas: the volume of gas in the reservoir that is in addition to the cushion or base gas. It may or may not be completely withdrawn during any particular withdrawal season. Conditions permitting, the total working capacity could be used more than once during any season.

 

working 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. Effective working gas storage capacity excludes cushion gas and non-cycling working gas.

 

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Index to Financial Statements

 

Common Units

 

Inergy Midstream, L.P.

 

Representing Limited Partner Interests

 

Prospectus

 

                    , 2011

 

MORGAN STANLEY

 

BARCLAYS CAPITAL

 

Until                    , 2011 (25 days after the date of this prospectus), all dealers that effect transactions in our common units, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealers’ obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.


Table of Contents
Index to Financial Statements

PART II

 

INFORMATION NOT REQUIRED IN PROSPECTUS

 

Item 13. Other Expenses of Issuance and Distribution.

 

Set forth below are the expenses (other than underwriting discounts and commissions and the structuring fee) expected to be incurred in connection with the issuance and distribution of the securities registered hereby. With the exception of the SEC registration fee, the FINRA filing fee and the NYSE listing fee, the amounts set forth below are estimates.

 

SEC registration fee

   $ 34,830   

FINRA filing fee

     30,500   

NYSE listing fee

     *   

Printing and engraving expenses

     *   

Fees and expenses of legal counsel

     *   

Accounting fees and expenses

     *   

Transfer agent and registrar fees

     *   

Miscellaneous

     *   
  

 

 

 

Total

   $ *   
  

 

 

 

 

  *   To be filed by amendment.

 

Item 14. Indemnification of Directors and Officers.

 

Inergy Midstream, L.P.

 

Subject to any terms, conditions or restrictions set forth in the partnership agreement, Section 17-108 of the Delaware Revised Uniform Limited Partnership Act empowers a Delaware limited partnership to indemnify and hold harmless any partner or other persons from and against all claims and demands whatsoever. The section of the prospectus entitled “The Partnership Agreement—Indemnification” discloses that we will generally indemnify officers, directors and affiliates of our general partner to the fullest extent permitted by law against all losses, claims, damages or similar events and is incorporated herein by this reference.

 

Our general partner will purchase insurance covering its officers and directors against liabilities asserted and expenses incurred in connection with their activities as officers and directors of our general partner or any of its direct or indirect subsidiaries.

 

The underwriting agreement to be entered into in connection with the sale of the securities offered pursuant to this registration statement, the form of which will be filed as an exhibit to this registration statement, provides for indemnification of Inergy Midstream, L.P. and our general partner, its officers and directors and any person who controls our general partner, including indemnification for liabilities under the Securities Act.

 

NRGM GP, LLC

 

Subject to any terms, conditions or restrictions set forth in the limited liability company agreement, Section 18-108 of the Delaware Limited Liability Company Act empowers a Delaware limited liability company to indemnify and hold harmless any member or manager or other person from and against any and all claims and demands whatsoever.

 

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Index to Financial Statements

Under the limited liability agreement of our general partner, in most circumstances, our general partner will indemnify the following persons, to the fullest extent permitted by law, from and against any and all losses, claims, damages, liabilities (joint or several), expenses (including legal fees and expenses), judgments, fines, penalties, interest, settlements or other amounts arising from any and all claims, demands, actions, suits or proceedings (whether civil, criminal, administrative or investigative):

 

   

any person who is or was an affiliate of our general partner (other than us and our subsidiaries);

 

   

any person who is or was a member, partner, officer, director, employee, agent or trustee of our general partner or any affiliate of our general partner;

 

   

any person who is or was serving at the request of our general partner or any affiliate of our general partner as an officer, director, employee, member, partner, agent, fiduciary or trustee of another person; and

 

   

any person designated by our general partner.

 

Item 15. Recent Sales of Unregistered Securities.

 

There have been no sales of unregistered securities within the past three years.

 

Item 16. Exhibits.

 

The following documents are filed as exhibits to this registration statement:

 

Exhibit
Number

       

Description

  1.1*

      Form of Underwriting Agreement

  3.1

      Limited Liability Company Agreement of Inergy Midstream, LLC (formerly Inergy Acquisition Company, LLC), dated as of September 21, 2004

  3.2*

      Certificate of Conversion of Inergy Midstream, LLC to Inergy Midstream, L.P.

  3.3*

      Certificate of Limited Partnership of Inergy Midstream, L.P.

  3.4*

      Agreement of Limited Partnership of Inergy Midstream, L.P.

  3.5*

      Form of First Amended and Restated Agreement of Limited Partnership of Inergy Midstream, L.P. (included as Appendix A to the prospectus included in this Registration Statement)

  3.6*

      Certificate of Formation of NRGM GP, LLC

  3.7*

      Limited Liability Company Agreement of NRGM GP, LLC

  3.8*

      Form of Amended and Restated Limited Liability Company Agreement of NRGM GP, LLC

  4.1*

      Form of Certificate Evidencing Common Units Representing Limited Partner Interests in Inergy Midstream, L.P.

  5.1*

      Opinion of Vinson & Elkins L.L.P. as to the legality of the securities being registered

  8.1*

      Opinion of Vinson & Elkins L.L.P. relating to tax matters

10.1*

      Form of Contribution, Conveyance and Assignment Agreement

10.2*

      Form of Omnibus Agreement

10.3†*

      Form of Inergy Midstream, L.P. Long Term Incentive Plan

10.4†*

      Form of Inergy Midstream, L.P. Long Term Incentive Plan Grant Letter

10.5*

      Form of Tax Sharing Agreement

10.6*†

      Directors’ Compensation Summary

10.7*

      Form of Credit Agreement

21.1*

      List of Subsidiaries of Inergy Midstream, L.P.

23.1

      Consent of Ernst & Young LLP

23.2*

      Consent of Vinson & Elkins L.L.P. (contained in Exhibit 5.1)

23.3*

      Consent of Vinson & Elkins L.L.P. (contained in Exhibit 8.1)

24.1#

      Powers of Attorney (contained on the signature page to this registration statement on page II-5)

 

  #   Previously filed.
  *   To be filed by amendment.
    Compensatory plan or arrangement.

 

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Index to Financial Statements
Item 17. Undertakings.

 

The undersigned registrant hereby undertakes to provide to the underwriters at the closing specified in the underwriting agreement certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.

 

Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

 

The undersigned registrant hereby undertakes that each prospectus filed pursuant to Rule 424(b) as part of a registration statement relating to an offering, other than registration statements relying on Rule 430B or other than prospectuses filed in reliance on Rule 430A, shall be deemed to be part of and included in the registration statement as of the date it is first used after effectiveness; provided, however, that no statement made in a registration statement or prospectus that is part of the registration statement or made in a document incorporated or deemed incorporated by reference into the registration statement or prospectus that is part of the registration statement will, as to a purchaser with a time of contract of sale prior to such first use, supersede or modify any statement that was made in the registration statement or prospectus that was part of the registration statement or made in any such document immediately prior to such date of first use.

 

The undersigned registrant hereby undertakes that, for the purpose of determining liability of the registrant under the Securities Act to any purchaser in the initial distribution of the securities, in a primary offering of securities of the undersigned registrant pursuant to this registration statement, regardless of the underwriting method used to sell the securities to the purchaser, if the securities are offered or sold to such purchaser by means of any of the following communications, the undersigned registrant will be a seller to the purchaser and will be considered to offer or sell such securities to such purchaser:

 

(1) Any preliminary prospectus or prospectus of the undersigned registrant relating to the offering required to be filed pursuant to Rule 424;

 

(2) Any free writing prospectus relating to the offering prepared by or on behalf of the undersigned registrant or used or referred to by the undersigned registrant;

 

(3) The portion of any other free writing prospectus relating to the offering containing material information about the undersigned registrant or its securities provided by or on behalf of the undersigned registrant; and

 

(4) Any other communication that is an offer in the offering made by the undersigned registrant to the purchaser.

 

The undersigned registrant hereby undertakes that:

 

(1) For purposes of determining any liability under the Securities Act, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective.

 

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Index to Financial Statements

(2) For the purpose of determining any liability under the Securities Act, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

 

The undersigned registrant undertakes to send to each common unitholder, at least on an annual basis, a detailed statement of any transactions with Inergy, L.P., NRGM GP, LLC or any of their affiliates, and of fees, commissions, compensation and other benefits paid, or accrued to Inergy, L.P., NRGM GP, LLC or any of their affiliates for the fiscal year completed, showing the amount paid or accrued to each recipient and the services performed.

 

The registrant undertakes to provide to the common unitholders the financial statements required by Form 10-K for the first full fiscal year of operations of the registrant.

 

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Index to Financial Statements

SIGNATURES

 

Pursuant to the requirements of the Securities Act of 1933, as amended, the registrant has duly caused this Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Kansas City, State of Missouri, on October 7, 2011.

 

Inergy Midstream, LLC

By:  

/s/ R. Brooks Sherman, Jr.

Name:   R. Brooks Sherman, Jr.
Title:  

Executive Vice President and

Chief Financial Officer

 

Pursuant to the requirements of the Securities Act of 1933, as amended, this Registration Statement has been signed below by the following persons in the capacities and the dates indicated.

 

Signature

  

Title

 

Date

*

John J. Sherman

  

President, Chief Executive Officer and

Representative of the Sole Member of

Inergy Midstream, LLC

(Principal Executive Officer)

  October 7, 2011

/s/ R. Brooks Sherman, Jr.

R. Brooks Sherman, Jr.

  

Executive Vice President and

Chief Financial Officer

(Principal Financial Officer and

Principal Accounting Officer)

  October 7, 2011

 

*By:  

/s/ R. Brooks Sherman, Jr.

  R. Brooks Sherman, Jr.
  Attorney-in-Fact

 

II-5


Table of Contents
Index to Financial Statements

Index to Exhibits

 

Exhibit
Number

       

Description

  1.1*

     

Form of Underwriting Agreement

  3.1

      Limited Liability Company Agreement of Inergy Midstream, LLC (formerly Inergy Acquisition Company, LLC), dated as of September 21, 2004

  3.2*

     

Certificate of Conversion of Inergy Midstream, LLC to Inergy Midstream, L.P.

  3.3*

     

Certificate of Limited Partnership of Inergy Midstream, L.P.

  3.4*

     

Agreement of Limited Partnership of Inergy Midstream, L.P.

  3.5*

      Form of First Amended and Restated Agreement of Limited Partnership of Inergy Midstream, L.P. (included as Appendix A to the prospectus included in this Registration Statement)

  3.6*

     

Certificate of Formation of NRGM GP, LLC

  3.7*

     

Limited Liability Company Agreement of NRGM GP, LLC

  3.8*

     

Form of Amended and Restated Limited Liability Company Agreement of NRGM GP, LLC

  4.1*

      Form of Certificate Evidencing Common Units Representing Limited Partner Interests in Inergy Midstream, L.P.

  5.1*

     

Opinion of Vinson & Elkins L.L.P. as to the legality of the securities being registered

  8.1*

     

Opinion of Vinson & Elkins L.L.P. relating to tax matters

10.1*

     

Form of Contribution, Conveyance and Assignment Agreement

10.2*

     

Form of Omnibus Agreement

10.3†*

     

Form of Inergy Midstream, L.P. Long Term Incentive Plan

10.4†*

     

Form of Inergy Midstream, L.P. Long Term Incentive Plan Grant Letter

10.5*

     

Form of Tax Sharing Agreement

10.6*†

     

Directors’ Compensation Summary

10.7*

     

Form of Credit Agreement

21.1*

     

List of Subsidiaries of Inergy Midstream, L.P.

23.1

     

Consent of Ernst & Young LLP

23.2*

     

Consent of Vinson & Elkins L.L.P. (contained in Exhibit 5.1)

23.3*

     

Consent of Vinson & Elkins L.L.P. (contained in Exhibit 8.1)

24.1#

      Powers of Attorney (contained on the signature page to this registration statement on
page II-5)

 

  #   Previously filed.
  *   To be filed by amendment.
    Compensatory plan or arrangement.

 

II-6