424A 1 d221930d424a.htm FORM 424A Form 424A
Table of Contents
Index to Financial Statements

Filed Pursuant to Rule 424(a)
Registration No. 333-176445

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.

 

PROSPECTUS (Subject to Completion)

Issued December 7, 2011

 

16,000,000 Common Units

Representing Limited Partner Interests

 

LOGO

 

Inergy Midstream, L.P.

 

This is the initial public offering of our common units representing limited partner interests. We are offering 16,000,000 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 $19.00 and $21.00 per common unit. We have been approved to list our common units on the New York Stock Exchange, subject to official notice of issuance, under the symbol “NRGM.”

 

Investing in our common units involves risks. See “Risk Factors” beginning on page 19.

 

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, 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 duties, and they may favor their own interests to the detriment of us and our common unitholders.

 

   

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

 

   

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 $0.37 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 $13.53 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(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. For additional information about underwriting compensation, see “Underwriting.”

 

We have granted the underwriters a 30-day option to purchase up to an additional 2,400,000 common units from us on the same terms and conditions as set forth above if the underwriters sell more than 16,000,000 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 Book-Running Managers

MORGAN STANLEY         BARCLAYS CAPITAL   
BofA MERRILL LYNCH    CREDIT SUISSE      WELLS FARGO SECURITIES   

 

Co-Managers

J.P. Morgan       RBC Capital Markets
Baird    Morgan Keegan    Stifel Nicolaus Weisel

 

                    , 2011


Table of Contents
Index to Financial Statements

Inergy Midstream Storage and Transportation Assets

 

LOGO

 

 

 


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

     15   

Non-GAAP Financial Measures

     17   

RISK FACTORS

     19   

Risks Inherent in Our Business

     19   

Risks Inherent in an Investment in Us

     32   

Tax Risks to Common Unitholders

     41   

USE OF PROCEEDS

     45   

CAPITALIZATION

     46   

DILUTION

     47   

CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

     48   

General

     48   

Our Initial Quarterly Distribution

     50   

Unaudited Pro Forma Cash Available for Distribution

     52   

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

     54   

Assumptions and Considerations

     56   

PROVISIONS OF OUR PARTNERSHIP AGREEMENT RELATING TO CASH DISTRIBUTIONS

     62   

Distributions of Available Cash

     62   

Operating Surplus and Capital Surplus

     63   

Capital Expenditures

     64   

Distributions of Available Cash from Operating Surplus

     65   

General Partner Interest

     65   

Incentive Distribution Rights

     65   

Percentage Allocations of Available Cash from Operating Surplus

     66   

NRGY’s Right to Reset the Incentive Distribution Level

     66   

Distributions from Capital Surplus

     68   

Adjustment to the Initial Quarterly Distribution

     68   
     Page  

Distributions of Cash Upon Liquidation

     69   

SELECTED HISTORICAL AND PRO FORMA FINANCIAL AND OPERATING DATA

     70   

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

     73   

Overview

     73   

How We Generate Revenue

     74   

Factors That Impact Our Business

     74   

Future Trends and Outlook

     76   

How We Evaluate Our Operations

     77   

Results of Operations

     79   

Liquidity and Sources of Capital

     84   

Quantitative and Qualitative Disclosures About Market Risk

     88   

Recent Accounting Pronouncements

     89   

Critical Accounting Policies

     89   

Seasonality

     90   

NATURAL GAS INDUSTRY

     91   

Market Fundamentals

     91   

Natural Gas Storage Industry

     94   

Key Characteristics of Storage Facilities

     95   

Competition and Barriers to Entry

     96   

Value Drivers for Natural Gas Storage

     96   

NGL Industry Dynamics

     97   

BUSINESS

     99   

Overview

     99   

Our Assets

     99   

Our Growth Projects

     102   

Our Operations

     104   

Our Business Strategies

     107   

Our Competitive Strengths

     109   

Inergy, L.P.

     111   

Customers

     111   

Contracts

     112   

Competition

     112   

Regulation

     113   

Environmental and Occupational Safety and Health Regulation

     116   

Seasonality

     119   

Title to Properties and Rights-of-Way

     119   

Insurance

     119   

Employees

     119   

Legal Proceedings

     120   
 

 

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Index to Financial Statements
     Page  

MANAGEMENT

     121   

Management of Inergy Midstream, L.P.

     121   

Executive Officers and Directors of Our General Partner

     122   

Director Independence

     123   

Board Leadership Structure and Role in Risk Oversight

     124   

Committees of the Board of Directors

     124   

EXECUTIVE COMPENSATION

     126   

Compensation Discussion and Analysis

     126   

Long-Term Incentive Plan

     127   

Employee Unit Purchase Plan

     127   

Director Compensation

     128   

Compensation Committee Interlocks and Insider Participation

     128   

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

     129   

NRGM GP, LLC Change of Control Event

     130   

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

     131   

Distributions and Payments to Our General Partner and Its Affiliates

     131   

Agreements with Affiliates in Connection with the Transactions

     133   

NRGM GP, LLC Change of Control Event

     135   

Other Transactions with Related Persons

     136   

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

     137   

CONFLICTS OF INTEREST AND FIDUCIARY DUTIES

     138   

Conflicts of Interest

     138   

Fiduciary Duties

     144   

Indemnification

     146   

DESCRIPTION OF THE COMMON UNITS

     147   

The Common Units

     147   

Transfer Agent and Registrar

     147   

Transfer of Common Units

     147   

THE PARTNERSHIP AGREEMENT

     149   

Organization and Duration

     149   

Purpose

     149   

Cash Distributions

     149   

Capital Contributions

     149   

Limited Voting Rights

     150   

Applicable Law; Forum, Venue and Jurisdiction

     151   
     Page  

Limited Liability

     151   

Issuance of Additional Interests

     152   

Amendment of the Partnership Agreement

     153   

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

     155   

Dissolution

     155   

Liquidation and Distribution of Proceeds

     156   

Withdrawal or Removal of Our General Partner

     156   

Transfer of General Partner Interest

     157   

Transfer of Ownership Interests in the General Partner

     157   

Transfer of Incentive Distribution Rights

     157   

Change of Management Provisions

     157   

Limited Call Right

     158   

Non-Taxpaying Holders; Redemption

     158   

Non-Citizen Assignees; Redemption

     158   

Meetings; Voting

     159   

Voting Rights of Incentive Distribution Rights

     159   

Status as Limited Partner

     160   

Indemnification

     160   

Reimbursement of Expenses

     160   

Books and Reports

     161   

Right to Inspect Our Books and Records

     161   

Registration Rights

     161   

UNITS ELIGIBLE FOR FUTURE SALE

     162   

MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES

     163   

Taxation of the Partnership

     163   

Tax Consequences of Unit Ownership

     164   

Tax Treatment of Operations

     170   

Disposition of Units

     170   

Uniformity of Units

     173   

Tax-Exempt Organizations and Other Investors

     173   

Administrative Matters

     174   

State, Local and Other Tax Considerations

     176   

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

     178   

UNDERWRITING

     179   

Listing

     180   

Lock-up Agreements

     180   

Price Stabilization and Short Positions

     181   

Indemnification

     182   

Pricing of the Offering

     182   

Directed Unit Program

     182   
 

 

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Index to Financial Statements
     Page  

FINRA Conduct Rules

     182   

Conflicts of Interest

     183   

Electronic Distribution

     183   

VALIDITY OF OUR COMMON UNITS

     184   

EXPERTS

     184   

WHERE YOU CAN FIND MORE INFORMATION

     185   
 

 

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.

 

Industry and Market Data

 

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.

 

iii


Table of Contents
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 $20.00 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 19 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.

 

On November 14, 2011, Inergy Midstream, LLC converted from a Delaware limited liability company to a Delaware limited partnership and changed its name to Inergy Midstream, L.P. 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 were transferred to Inergy, L.P. in connection with 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. 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 355 MMcf/d of interstate and intrastate transportation capacity and, upon completion of our MARC I pipeline that is currently under development, we will own a total of 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 October 31, 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

Significant Growth Projects

 

Project

  

Capacity

  

Anticipated
In-Service Date

MARC I Pipeline

   550 MMcf/d    July 2012

North/South Expansion Project

   325 Mmcf/d    December 2011(1)

Watkins Glen NGL Storage Facility

   2.1 Mmbbl    June 2012

Seneca Lake Natural Gas Storage Expansion

   0.6 Bcf    December 2012

 

(1)   Our North/South expansion project was placed into service on December 1, 2011.

 

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.

 

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.

 

 

2


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Index to Financial Statements

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 presented to us or to NRGY, 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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Index to Financial Statements

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. Our approximately $380 million in internal growth projects around our existing assets are 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 September 30, 2011, approximately 94% 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 November 14, 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. 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 provide NRGY with a strong incentive to do so.

 

 

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Index to Financial Statements

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 19 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 fiscal year ended September 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.

 

   

If we are unable to obtain needed capital or financing on satisfactory terms to fund expansions of our asset base, our ability to pay cash distributions may be diminished or our financial leverage could increase. We do not have any commitment with any of our affiliates 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.

 

   

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 duties, and they may favor their own interests to the detriment of us and our common unitholders.

 

 

5


Table of Contents
Index to Financial Statements

 

   

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

 

   

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 $0.37 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 $13.53 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 78.5% 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, have agreed to enter into an agreement under which, under certain circumstances, Holdings GP will be required to purchase the entity that controls 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. Upon the closing of this offering, assuming we distribute the initial quarterly distribution only, NRGY will be entitled to receive approximately 78% of all cash distributed (assuming we grant 5,000 restricted units to our independent directors and an additional 495,000 restricted units to certain key employees at the closing of this offering). Please read “Certain Relationships and Related Party Transactions—NRGM GP, LLC Change of Control Event.”

 

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. The board of directors of our general partner will be comprised of three directors, including two independent directors, at the completion of this offering. NRGY will appoint a third independent director within one year from the effective date of the registration statement of which this prospectus forms a part.

 

 

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Index to Financial Statements

In connection with the closing of this offering, we will enter into an omnibus agreement with our general partner, NRGY and its general partner, 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—Agreements with Affiliates in Connection with the Transactions—Omnibus Agreement.”

 

Summary of Conflicts of Interest and Fiduciary Duties

 

Our general partner has a duty to manage our partnership in a manner it believes is in our best interests. 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, expand, restrict or eliminate the fiduciary duties owed by the general partner to limited partners and the partnership. Our partnership agreement restricts the remedies available to our common unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty. 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 www.inergylp.com. 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. On November 14, 2011, Inergy Midstream, LLC converted into a Delaware limited partnership and changed its name to Inergy Midstream, L.P. On November 25, 2011, we transferred 100% of our ownership interests in Tres Palacios Gas Storage LLC, or Tres Palacios Gas Storage, and US Salt to NRGY.

 

 

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Index to Financial Statements

In connection with this offering, the following will occur:

 

   

all indebtedness that we owe to a subsidiary of NRGY, which was approximately $129.8 million as of September 30, 2011, will be extinguished and treated as a capital contribution by NRGY to us;

 

   

we will assume from NRGY a $300 million unsecured promissory note (which we refer to in this prospectus as our promissory note) that will be issued by NRGY to JPMorgan Chase Bank, N.A., which we expect to (i) pay in full using the net proceeds from this offering and borrowings of approximately $2.8 million under our revolving credit facility and (ii) retire immediately following the closing of this offering;

 

   

we will enter into a new $500 million revolving credit facility (which we refer to in this prospectus as our revolving credit facility);

 

   

we expect to 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 58,325,000 common units, assuming that the underwriters do not exercise their option to purchase 2,400,000 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 $0.37 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 $50,000 of restricted units (or 2,500 restricted units based on a grant date value of $20.00 per unit at the closing of this offering) to each of our two independent directors pursuant to our long-term incentive plan; in addition, we may elect to grant up to an additional 495,000 restricted units to certain key employees (please read “Executive Compensation—Long-Term Incentive Plan”);

 

   

we will issue 16,000,000 common units to the public (18,400,000 common units if the underwriters exercise their option in full); and

 

   

we will enter into or remain a party to certain agreements with NRGY and its affiliates, including the omnibus agreement, contribution agreement, tax sharing agreement, assignment and assumption agreement relating to Tres Palacios Gas Storage and storage contracts relating to our Watkins Glen and Bath facilities. Please read “Certain Relationships and Related Party Transactions.”

 

 

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Index to Financial Statements

Ownership of Inergy Midstream, L.P.

 

The following diagram illustrates our simplified organizational structure and approximate 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

     21.5

Common Units owned by NRGY

     78.5

Independent Directors

     *   

Non-Economic General Partner Interest

    
  

 

 

 

Total

     100.0
  

 

 

 

 

LOGO

 

*   Less than 1%.
(1)   Owned by management and other investors.

 

 

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Index to Financial Statements

The Offering

 

Common units offered to the public

16,000,000 common units.

 

  18,400,000 common units if the underwriters exercise their option to purchase an additional 2,400,000 common units (the “option units”) in full.

 

Common units outstanding after this offering

74,330,000 common units, which includes 5,000 restricted units to be granted to our independent directors, regardless of whether or not the underwriters exercise their option to purchase up to an additional 2,400,000 common units. Of this amount, 55,925,000 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 2,400,000 option units, all 2,400,000 option units will be issued to NRGY 30 days following this offering upon the expiration of the underwriters’ option exercise period resulting in NRGY owning 58,325,000 common units. 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 up to 495,000 restricted units that we may grant to key employees in connection with this offering and other common units reserved for issuance under our long-term incentive plan. Please read “Executive Compensation—Long-Term Incentive Plan.”

 

Use of proceeds

We intend to use the estimated net proceeds of approximately $297.2 million from this offering, after deducting the estimated underwriting discounts, the structuring fee and offering expenses payable by us of approximately $22.8 million, along with expected borrowings of approximately $82.8 million under our revolving credit facility, to repay all of the $300 million of indebtedness outstanding under our promissory note and to fund a cash distribution to NRGY for reimbursement of capital expenditures associated with our assets.

 

  JPMorgan Chase Bank, N.A., an affiliate of J.P. Morgan Securities LLC, is the holder of our promissory note and will, in that respect, receive all or substantially all of the net proceeds from this offering in connection with the repayment in full of such promissory note. Please read “Underwriting.”

 

 

If the underwriters exercise their option to purchase 2,400,000 additional common units in full, the additional net proceeds would be approximately $44.9 million. The net proceeds from any exercise of

 

 

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Index to Financial Statements
 

the underwriters’ option to purchase additional common units will be distributed to NRGY, and we expect that NRGY will use substantially all such net proceeds to repay outstanding borrowings under NRGY’s revolving credit facility. Please read “Use of Proceeds.”

 

Cash distributions

Upon completion of this offering, our general partner will establish an initial quarterly distribution of $0.37 per common unit ($1.48 per common unit on an annualized basis). 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 $5.0 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 $0.37.

 

  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 $0.37 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.

 

 

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Index to Financial Statements
  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 $0.37

     100.0     0.0

above $0.37

     50.0     50.0

 

  We refer to the additional distributions to NRGY of 50% of the cash we distribute in excess of $0.37 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 $0.37 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, 2011 would have been sufficient to pay only 66% of the full initial quarterly distribution on all of our common units and restricted units for such period (assuming we grant 5,000 restricted units to our independent directors and an additional 495,000 restricted units to certain key employees at the closing of this offering). Please read “Cash Distribution Policy and Restrictions on Distributions” and “Executive Compensation—Long-Term Incentive Plan.”

 

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. Following a reset election, the initial quarterly distribution will be adjusted to equal the reset initial quarterly distribution. The following assumes that NRGY holds all of the incentive distribution rights at the time that a reset election is made.

 

 

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Index to Financial Statements
  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 the 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 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 78.5% of our outstanding common units (or 75.2% 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 85% 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 average of the daily closing prices per limited partner interest of the class purchased for the 20 consecutive trading days immediately prior to the date three days before the date our general partner first mails notice of its election to purchase those limited partner interests and (2) the highest price paid by our general partner or any of its affiliates for any limited partner interests of the class purchased during the 90-day period preceding the date that the notice is mailed. 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 20% or less of the cash distributed to you with respect to that period. For example, if you receive an annual distribution of $1.48 per unit, we

 

 

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Index to Financial Statements
 

estimate that your average allocable federal taxable income per year will be no more than approximately $0.296 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.

 

Directed unit program

At our request, the underwriters have reserved up to 5% of the common units being offered by this prospectus for sale at the initial public offering price to the officers, directors and employees of our general partner and its affiliates and certain other persons associated with us, as designated by us. For further information regarding our directed unit program, please read “Underwriting—Directed Unit Program.”

 

Exchange listing

We have been approved to list our common units on the NYSE, subject to official notice of issuance, 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, 2009 are derived from our audited historical consolidated financial statements that are not included in this prospectus. The summary historical financial data presented as of September 30, 2010 and 2011 and for the fiscal years ended September 30, 2009, 2010 and 2011 are derived from our audited 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, L.P. and its subsidiaries.

 

The summary pro forma financial data presented as of and for the fiscal year ended September 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 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 $129.8 million as of September 30, 2011;

 

   

our assumption of $300 million of indebtedness from NRGY under our promissory note, which we expect to (i) pay in full using the net proceeds from this offering and borrowings of approximately $2.8 million under our revolving credit facility and (ii) retire immediately following the closing of this offering;

 

   

our 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 of an aggregate 5,000 restricted units to our two independent directors pursuant to our long-term incentive plan;

 

   

the issuance by us to NRGY of 58,325,000 common units and all of our incentive distribution rights; and

 

   

the issuance by us to the public of 16,000,000 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 September 30, 2011. The unaudited pro forma statement of operations data for the fiscal year ended September 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 addition to the 5,000 restricted units granted to our independent directors, we may grant up to an additional 495,000 restricted units at the closing of this offering to certain key employees with an aggregate annual expense of approximately $2.0 million. Please read “Executive Compensation—Long-Term Incentive Plan.” Such incremental 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 conjunction with “Use of Proceeds” and our audited historical consolidated financial statements and our

 

 

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Index to Financial Statements

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,     Year
Ended
September  30,
 
     2009     2010     2011     2011  
     ($ in millions)  

Statement of operations data:

        

Revenue

   $ 87.5      $ 94.7      $ 110.9      $ 110.9   

Costs and expenses:

        

Service related costs

     17.8        12.0        15.8        15.8   

Operating and administrative

     10.8        15.0        15.9        15.9   

Depreciation and amortization

     29.2        36.2        37.6        37.6   

Loss on disposal of assets

            0.9                 
  

 

 

   

 

 

   

 

 

   

 

 

 
     57.8        64.1        69.3        69.3   
  

 

 

   

 

 

   

 

 

   

 

 

 

Operating income

     29.7        30.6        41.6        41.6   

Interest expense, net

                          (2.4

Other income

            0.8                 
  

 

 

   

 

 

   

 

 

   

 

 

 

Net income

     29.7        31.4        41.6        39.2   

Net income attributable to non-controlling partners

     1.4        0.8                 
  

 

 

   

 

 

   

 

 

   

 

 

 

Net income attributable to partners

   $ 28.3      $ 30.6      $ 41.6      $ 39.2   
  

 

 

   

 

 

   

 

 

   

 

 

 

Balance sheet data (at end of period):

        

Total assets

   $ 561.0      $ 559.5      $ 702.4      $ 706.6   

Total debt

     8.3                      82.8   

Partners’ capital

     414.3        444.8        553.3        600.3   

Other financial data:

        

Adjusted EBITDA

   $ 57.7      $ 70.4      $ 81.1      $ 81.1   

Maintenance capital expenditures

            0.3        3.3     

Net cash provided by operating activities

     59.5        83.5        88.8        88.8   

Net cash used in investing activities

     (74.1     (49.8     (165.1  

Net cash provided by (used in) financing activities

     15.3        (37.3     76.3     

Operating data:

        

Natural gas storage capacity (Bcf)

     32.5        39.5        41.0     

% of revenue generated from firm contracts

     96     98     94  

 

 

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Index to Financial Statements

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 expense, 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,
     Year Ended
September 30,
 
     2009     2010     2011      2011  
     ($ in millions)  

Reconciliation of net income to EBITDA and Adjusted EBITDA:

         

Net income

   $ 29.7      $ 31.4      $ 41.6       $ 39.2   

Depreciation and amortization

     29.2        36.2        37.6         37.6   

Interest expense, net

                           2.4   
  

 

 

   

 

 

   

 

 

    

 

 

 

EBITDA

   $ 58.9      $ 67.6      $ 79.2       $ 79.2   

Long-term incentive and equity compensation expense

     0.7        2.7        1.5         1.5   

Loss on disposal of assets

            0.9                  

Transaction costs

            0.2        0.4         0.4   

Net income attributable to non-controlling partners

     (1.4     (0.8               

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

     (0.5     (0.2               
  

 

 

   

 

 

   

 

 

    

 

 

 

Adjusted EBITDA

   $ 57.7      $ 70.4      $ 81.1       $ 81.1   
  

 

 

   

 

 

   

 

 

    

 

 

 

 

 

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           Pro Forma  
     Year Ended
September 30,
    Year Ended
September 30,
 
     2009     2010     2011     2011  
     ($ in millions)  

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

        

Net cash provided by operating activities

   $ 59.5      $ 83.5      $ 88.8      $ 88.8   

Net changes in working capital balances

     (0.6     (15.0     (9.6     (9.6

Loss on disposal of assets

            (0.9              
  

 

 

   

 

 

   

 

 

   

 

 

 

EBITDA

   $ 58.9      $ 67.6      $ 79.2      $ 79.2   

Long-term incentive and equity compensation expense

     0.7        2.7        1.5        1.5   

Loss on disposal of assets

            0.9                 

Transaction costs

            0.2        0.4        0.4   

Interest of non-controlling partners in consolidated EBITDA

     (1.9     (1.0              
  

 

 

   

 

 

   

 

 

   

 

 

 

Adjusted EBITDA

   $ 57.7      $ 70.4      $ 81.1      $ 81.1   
  

 

 

   

 

 

   

 

 

   

 

 

 

 

(a)   Consists of interest, tax, depreciation and amortization expense attributable to non-controlling partners, which is determined by allocating based on proportional ownership the interest, taxes, depreciation and amortization of our less than wholly-owned Steuben natural gas storage facility for each period. However, we acquired 100% ownership of the Steuben natural gas storage facility during the year ended September 30, 2010.

 

 

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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 $0.37 per unit, or $1.48 per unit per year, which will require us to have available cash of approximately $27.7 million per quarter, or $110.7 million per year, based on (i) the number of common units to be outstanding after the completion of this offering and (ii) up to 500,000 restricted units that may be granted in connection with this offering (which includes an aggregate 5,000 restricted units that will be granted to our independent directors). Please read “Executive Compensation—Long-Term Incentive Plan.” 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 $5.0 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;

 

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

 

   

changes in tax laws; and

 

   

force majeure events.

 

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, 2011.

 

To pay our cash distributions at our initial quarterly distribution rate of $0.37 per common unit per quarter, or $1.48 per common unit per year, we will require available cash of approximately $27.7 million per quarter, or $110.7 million per year, based on (i) the number of common units outstanding after the completion of this offering and (ii) up to 500,000 restricted units that may be granted in connection with this offering (which includes an aggregate 5,000 restricted units that will be granted to our independent directors). Please read “Executive Compensation—Long-Term Incentive Plan.” Our pro forma cash available for distribution generated during the fiscal year ended September 30, 2011 of $73.2 million 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, 2011 would have resulted in distributions with respect to our common units and restricted units representing approximately 66% of our initial quarterly distribution (assuming we grant 5,000 restricted units to our independent directors and an additional 495,000 restricted units to certain key employees at the closing of this offering). 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, 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 presented to us or to NRGY, 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 Oil 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 October 31, 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, 2011, Consolidated Edison of New York, Inc., or ConEdison, accounted for approximately 24% 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, 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 have been or are expected to be completed throughout 2011 and 2012 at a total expected cost of approximately $380 million, of which approximately $134.4 million has been incurred through September 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 regulatory approval from federal and state authorities prior to construction, such as our Watkins Glen storage development project. The approval process for storage and transportation projects located in the Northeast has become increasingly challenging, due in part to state and local concerns related to unregulated exploration and production and gathering activities in new production areas (including the Marcellus shale play). We cannot guarantee such authorization will be granted or, if granted, that such authorization will be free of burdensome or expensive conditions.

 

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Index to Financial Statements

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.

 

If we are unable to obtain needed capital or financing on satisfactory terms to fund expansions of our asset base, our ability to pay cash distributions may be diminished or our financial leverage could increase. We do not have any commitment with any of our affiliates 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.

 

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

 

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outstanding senior notes would substantially restrict the types, amounts and terms of any such assistance that NRGY might desire to provide us. For example, under NRGY’s indentures, NRGY and its restricted subsidiaries may not have any direct or indirect obligation to purchase any equity interests in our partnership or maintain or preserve our financial condition. NRGY and its restricted subsidiaries are also prohibited from guaranteeing or providing credit support for our indebtedness. Finally, none of NRGY or its restricted subsidiaries may enter into an agreement with us unless the terms of the agreement are no less favorable to NRGY or its restricted subsidiaries than those that might be obtained from an unaffiliated third party.

 

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, 2011, ConEdison accounted for approximately 24% 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.

 

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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 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.

 

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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;

 

   

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.

 

We secured a commitment letter from lenders containing the material terms of a new $500 million revolving credit facility that we will enter into at the closing of this offering, with a maturity date five years from the closing of this offering. Our revolving credit facility will be available to fund working capital and our internal growth projects, make acquisitions and for general partnership purposes.

 

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

 

   

incur additional debt;

 

   

make distributions on or redeem or repurchase units;

 

   

make certain investments and acquisitions;

 

   

incur or permit certain liens to exist;

 

   

enter into certain types of transactions with affiliates;

 

   

merge, consolidate or amalgamate with another company; and

 

   

transfer or otherwise dispose of assets.

 

Furthermore, our revolving credit facility will contain covenants requiring us to maintain certain financial ratios. For example, our revolving credit facility will require maintenance of a consolidated leverage ratio (as defined in our credit agreement) of not more than 5.00 to 1.00 and an interest coverage ratio (as defined in our credit agreement) of not less than 2.50 to 1.00. Borrowings under our revolving credit facility will be secured by pledges of the equity interests of, and guaranteed by, our existing and future subsidiaries. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Sources of Capital—Revolving Credit Facility.”

 

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.”

 

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

 

On September 23, 2011, Anadarko Petroleum Corporation, or Anadarko, filed a complaint against Inergy Midstream, LLC and CNYOG in the Court of Common Pleas in Lycoming County, Pennsylvania (Cause No. 11-01697) alleging that (i) Anadarko had an option to acquire, and timely exercised its option to acquire, a 25% ownership interest in the MARC I pipeline, (ii) we refused to enter into definitive agreements under which Anadarko would acquire a 25% interest in the pipeline and, by doing so, we breached the letter of intent, and (iii) by refusing to enter into definitive agreements, we breached a duty of good faith and fair dealing in connection with the letter of intent. Based on these allegations, Anadarko seeks various remedies, including specific performance of the letter of intent and monetary damages. For further information regarding this lawsuit, please read “Business—Legal Proceedings.” We filed preliminary objections to the complaint and have sought a judgment in our favor and an order dismissing Anadarko’s complaint. We cannot predict the outcome of the Anadarko lawsuit or the amount of time and expense that will be required to resolve the lawsuit. An unfavorable resolution of such litigation could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions. In addition, such litigation could divert the attention of management and resources in general from day-to-day operations.

 

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

 

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

 

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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 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

 

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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.

 

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,

 

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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 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 duty to manage our partnership in a manner it believes is in our best interests, the executive officers and directors of our general partner have a fiduciary duty to manage our general partner in a manner beneficial to 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 presented to us or to NRGY, is under no obligation to make acquisition opportunities available to us and may compete with us;

 

   

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 restricts the remedies available to our common unitholders for actions taken by our general partner that might otherwise 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;

 

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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 85% 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 $55 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.

 

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

 

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

 

Our partnership agreement 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.

 

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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, or in our revolving credit facility, on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, may impact the available cash that we have to distribute to our common unitholders.

 

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

 

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

 

   

how to allocate business opportunities among us and its affiliates;

 

   

whether to exercise its limited call right;

 

   

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

 

   

whether to exercise its registration rights;

 

   

whether to 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.”

 

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

 

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

 

   

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

 

   

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

 

   

our general partner 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

 

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

 

Whenever a conflict arises between our general partner or its affiliates, on the one hand, and us and our limited partners, on the other hand, the resolution or course of action in respect of such conflict of interest shall be permitted and deemed approved by all our limited partners and shall not constitute a breach of our partnership agreement, of any agreement contemplated thereby or of any duty, if the resolution or course of action in respect of such conflict of interest is:

 

  (1)   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

 

  (2)   approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner or its affiliates. Please read “Conflicts of Interest and Fiduciary Duties.”

 

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

 

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

 

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 presented to us or to NRGY 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

 

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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 $0.37 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.

 

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, 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 the 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

 

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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—NRGM GP, LLC Change of Control Event.” 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 required to remove our general partner. Following the closing of this offering, NRGY will own, directly or indirectly, an aggregate of 78.5% of our common units (or 75.2% 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 $13.53 per common unit.

 

The assumed initial public offering price of $20.00 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 $7.51 per common unit. Based on the assumed initial public offering price of $20.00 per common unit, common unitholders will incur immediate and substantial dilution in net tangible book value per common unit of $13.53 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, at any time, our general partner may transfer all or any of its general partner interest or common units to another person without the consent of our common unitholders, and our common unitholders will have no right to elect our general partner or its directors on an annual or other continuing basis. In addition, in connection with this offering, NRGY and Holdings GP, the indirect owner of NRGY’s general partner, have agreed to enter into an agreement under which Holdings GP will be required to purchase the entity that controls our general partner in the event that (i) a change of control of 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. Upon the closing of this offering, assuming we distribute the initial quarterly distribution only, NRGY will be entitled to receive approximately 78% of all cash distributed (assuming we grant 5,000 restricted units to our independent directors and an additional 495,000 restricted units to certain key employees at the closing of this offering). Please read “Certain Relationships and Related Party Transactions—NRGM GP, LLC Change of Control Event.” If the sole member of our general partner transfers its membership interest in our general partner to a third party or Holdings GP acquires the entity that controls our general partner, the third party or Holdings GP, as applicable, would then be in a position to replace the board of directors and executive officers of our general partner with its designees and thereby exert significant control over the decisions taken by the board of directors and executive officers of our general partner. This effectively permits a “change of control” without the vote or consent of the common unitholders.

 

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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 85% of the outstanding common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price equal to the greater of (1) the average of the daily closing prices per limited partner interest of the class purchased for the 20 consecutive trading days immediately prior to the date three days before the date our general partner first mails notice of its election to purchase those limited partner interests and (2) the highest price paid by our general partner or any of its affiliates for any limited partner interests of the class purchased during the 90-day period preceding the date that the notice is mailed. As a result, unitholders may be required to sell their common units at an undesirable time or price and may not receive any return or a negative return on their investment. Unitholders may also incur a tax liability upon a sale of their common units. Our general partner is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon exercise of the limited call right. There is no restriction in our partnership agreement that prevents our general partner from issuing additional common units and exercising its call right. If our general partner exercised its limited call right, the effect would be to take us private and, if the units were subsequently deregistered, we would no longer be subject to the reporting requirements of the Exchange Act. 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 78.5% 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 74,330,000 common units outstanding, which includes the 16,000,000 common units we are selling in this offering that may be resold in the public market immediately (18,400,000 common units if the underwriters exercise in full their option to purchase additional common units) and an aggregate 5,000 restricted units outstanding that will be issued to our independent directors. All of the 58,325,000 common units (55,925,000 common units if the underwriters exercise in full their option to purchase

 

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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.

 

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 $5.0 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 16,000,000 publicly traded common units held by our public unitholders (18,400,000 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

 

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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;

 

   

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. A purchaser of common units who becomes a limited partner is liable for the obligations of the transferring limited partner to make contributions to the partnership that are known to the purchaser of the common units at the time it became a limited partner and for unknown obligations if the liabilities could be determined from the partnership agreement. Liabilities to partners on account of their partnership interests and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.

 

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

 

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

 

We have been approved to list our common units on the NYSE, subject to official notice of issuance. 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 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. In addition to the 5,000 restricted units granted to our independent directors, we may grant up to an additional 495,000 restricted units at the closing of this offering to certain key employees with an aggregate annual expense of approximately $2.0 million.

 

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.

 

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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 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

 

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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 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.

 

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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 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 $297.2 million from this offering, after deducting the estimated underwriting discounts, the structuring fee and offering expenses payable by us of approximately $22.8 million, along with expected borrowings of approximately $82.8 million under our revolving credit facility to:

 

   

repay all of the $300 million of indebtedness outstanding under our promissory note; and

 

   

fund an $80 million cash distribution to NRGY for reimbursement of capital expenditures associated with our assets.

 

The borrowings under our promissory note, which we will assume from NRGY immediately prior to the closing of this offering, will be incurred by NRGY to repay, repurchase or redeem existing debt of NRGY. We will assume the promissory note as partial consideration to NRGY in connection with the recapitalization of its interest in us. Our promissory note will mature at 5:00 p.m. (Chicago time) on the closing date of this offering. We expect borrowings under our promissory note will bear interest at a rate equal to JPMorgan Chase Bank, N.A.’s prime rate plus 5%.

 

We expect borrowings under our revolving credit facility to initially bear interest at approximately 3.25%. Our revolving credit facility will mature five years from the closing date of this offering.

 

If and to the extent the underwriters exercise their option to purchase all or a portion of the 2,400,000 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 2,400,000 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 2,400,000 additional common units in full, the additional net proceeds would be approximately $44.9 million. The net proceeds from any exercise of the underwriters’ option to purchase additional common units will be distributed to NRGY, and we expect that NRGY will use substantially all such net proceeds to repay outstanding borrowings under NRGY’s revolving credit facility. Borrowings under NRGY’s revolving credit facility were incurred to fund the acquisition of the Seneca Lake facility, to fund the construction of the MARC I pipeline and North/South expansion project and for NRGY’s working capital needs. As of November 30, 2011, borrowings under NRGY’s revolving credit facility had a weighted average interest rate of approximately 2.85%. NRGY’s revolving credit facility matures on July 28, 2016. If the underwriters do not exercise their option to purchase additional common units, we will issue 2,400,000 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 $20.00 per common unit would cause the net proceeds from this offering, after deducting the estimated underwriting discounts, the structuring fee and offering expenses payable by us, to increase or decrease, respectively, by approximately $15.0 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 $21.00 per common unit, would increase net proceeds to us from this offering by approximately $34.6 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 $19.00 per common unit, would decrease the net proceeds to us from this offering by approximately $32.8 million.

 

JPMorgan Chase Bank, N.A., an affiliate of J.P. Morgan Securities LLC, is the holder of our promissory note and will, in that respect, receive all or substantially all of the net proceeds from this offering in connection with the repayment in full of such promissory note. Please read “Underwriting.”

 

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CAPITALIZATION

 

The following table shows our cash and cash equivalents and capitalization as of September 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 September 30, 2011  
     Actual          As Adjusted      
     (In millions)  

Cash and cash equivalents

   $       $   
  

 

 

    

 

 

 

Debt:

     

Revolving credit facility

   $       $ 82.8 (a) 

Promissory note

             (b) 

Partners’ capital:

     

Held by public:

     

Common units

             297.2   

Held by NRGY:

     

Net parent capital

     553.3           

Common units

             303.1   

General partner interest

               
  

 

 

    

 

 

 

Total partners’ capital

   $ 553.3       $ 600.3   
  

 

 

    

 

 

 

Total capitalization

   $ 553.3       $ 683.1   
  

 

 

    

 

 

 

 

(a)   Reflects our borrowing of approximately $82.8 million under our revolving credit facility, which will be used to (i) reimburse NRGY for $80 million of capital expenditures incurred prior to this offering related to our assets and (ii) repay approximately $2.8 million of indebtedness on our promissory note.
(b)   Reflects (i) our assumption of $300 million of indebtedness from NRGY under our promissory note that will be assigned to us immediately prior to the closing of this offering and (ii) our repayment in full of the promissory note using the net proceeds from this offering and borrowings of approximately $2.8 million under our revolving credit facility.

 

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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 $20.00 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 September 30, 2011, after giving effect to the offering of common units and the related transactions, our net tangible book value was approximately $481.1 million, or $6.47 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

     $ 20.00   

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

   $ 7.51     

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

     (1.04  
  

 

 

   

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

       6.47   
    

 

 

 

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

     $ 13.53   
    

 

 

 

 

(1)   Determined by dividing the pro forma net tangible book value of our assets and liabilities by the number of common units (58,325,000 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 (74,330,000 common units, including an aggregate 5,000 restricted units that we will grant to our two independent directors at the closing of this offering and 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 $20.00 per common unit would increase or decrease, respectively, our pro forma net tangible book value by approximately $15.0 million, or approximately $0.20 per common unit, and dilution per common unit to investors in this offering would be approximately $14.33 per common unit for a $1.00 increase and $12.73 for a $1.00 decrease, after deducting the estimated underwriting discounts, 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 $21.00 per common unit, would result in a pro forma net tangible book value of approximately $515.7 million, or $6.94 per common unit, and dilution per common unit to investors in this offering would be $14.06 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 $19.00 per common unit, would result in an pro forma net tangible book value of approximately $448.3 million, or $6.03 per common unit, and dilution per common unit to investors in this offering would be $12.97 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 and restricted 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.

 

     Units     Total Consideration     Average Price
Paid Per Unit
 
     Number      Percent     Amount      Percent    
                  (in thousands)               

Common units owned by NRGY

     58,325,000         78.5   $ 135,900         29.8   $ 2.33   

Public common units

     16,000,000         21.5   $ 320,000         70.2   $ 20.00   

Restricted units held by directors

    
5,000
  
     *                      
  

 

 

    

 

 

   

 

 

    

 

 

   

Total

     74,330,000         100.0   $ 455,900         100.0   $ 6.13   
  

 

 

    

 

 

   

 

 

    

 

 

   

 

*   Less than 1%.

 

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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, 2010 and 2011 and for the fiscal years ended September 30, 2009, 2010 and 2011 and our unaudited pro forma condensed consolidated financial statements as of and for the fiscal year ended September 30, 2011 included elsewhere in this prospectus.

 

General

 

Our Cash Distribution Policy

 

Our partnership agreement contains a policy pursuant to which we will pay regular quarterly cash distributions in an aggregate amount equal to substantially all of our available cash. Under the policy, each quarter the board of directors of our general partner will make a determination of the amount of cash available for distribution to our partners, which amount will equal all cash on hand at the end of the quarter, less reserves for the proper conduct of our business (including reserves for capital expenditures, operating expenditures and debt service) or for distributions to partners in respect of future periods. Our available cash may also include, if the board of directors of our general partner so determines, all or any portion of the cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made subsequent to the end of such quarter.

 

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:

 

   

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 will 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 proper conduct of our business and for future cash distributions to our common unitholders, and the establishment of or

 

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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 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 78.5% of the outstanding common units (assuming the underwriters do not exercise their option to purchase additional 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 $5.0 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.

 

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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 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. For example, under NRGY’s indentures, NRGY and its restricted subsidiaries may not have any direct or indirect obligation to purchase any equity interests in our partnership or maintain or preserve our financial condition. NRGY and its restricted subsidiaries are also prohibited from guaranteeing or providing credit support for our indebtedness. Finally, none of NRGY or its restricted subsidiaries may enter into an agreement with us unless the terms of the agreement are no less favorable to NRGY or its restricted subsidiaries than those that might be obtained from an unaffiliated third party.

 

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 $0.37 per unit for each complete quarter, or $1.48 per year, to be paid within 45 days after the end of each quarter. This equates to an aggregate cash distribution of $27.7 million per quarter, or $110.7 million per year, based on (i) the number of common units that will be outstanding immediately after the completion of this offering and (ii) up to 500,000 restricted units that may be granted in connection with this offering (which includes an aggregate 5,000 restricted units that will be granted to our independent directors). Please read “Executive Compensation—Long-Term Incentive Plan.” 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 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.”

 

In connection with the closing of this offering, the board of directors of our general partner will grant 2,500 restricted units to each of our independent directors and may grant up to an additional 495,000 restricted units to certain key employees that provide services for us, including executive officers, pursuant to our long-term incentive plan. Restricted units awarded to our independent directors at the closing of this offering will vest ratably over three years beginning on the first anniversary from the date of the grant. Restricted units awarded to key employees at the closing of this offering are expected to vest 25%, 25% and 50% on the third, fourth and fifth anniversaries, respectively, from the date of the grant. Holders of restricted units are entitled to distributions at the initial quarterly distribution rate and have such voting rights as are provided to holders of common units under our partnership agreement. Please read “Executive Compensation—Long-Term Incentive Plan.”

 

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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 and restricted 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 (assuming the underwriters do not exercise their option to purchase additional common units and that we grant 500,000 restricted units at the closing of this offering):

 

            Distributions  
     Number of Units      One Quarter      Annualized  
            (in millions)  

Publicly held common units

     16,000,000       $ 5.9       $ 23.7   

Common units held by NRGY

     58,325,000         21.6         86.3   

Restricted units(1)

     500,000         0.2         0.7   

General partner interest(2)

                       
  

 

 

    

 

 

    

 

 

 

Total

     74,825,000       $ 27.7       $ 110.7   
  

 

 

    

 

 

    

 

 

 

 

(1)   In connection with the closing of this offering, the board of directors of our general partner will grant 2,500 restricted units to each of our two independent directors and may grant up to an additional 495,000 restricted units to certain key employees that provide services for us, including executive officers, pursuant to our long-term incentive plan. Please read “Executive Compensation—Long-Term Incentive Plan.”
(2)   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 $0.37 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 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 a determination, other action or failure to act by our general partner, the board of directors of our general partner or any committee thereof (including the conflicts committee) will be deemed to be in good faith unless our general partner, the board of directors of our general partner or any committee thereof believed such determination, other action or failure to act was not in the best interests of the partnership. 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

 

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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 $0.37 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, 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, 2010, our unaudited pro forma cash available for distribution for the fiscal year ended September 30, 2011 would have been approximately $73.2 million. This amount would have been insufficient to make the initial quarterly distribution of $0.37 per unit per quarter (or $1.48 per unit on an annualized basis) on all of our common units during such period. We estimate that our pro forma cash available for distribution for the fiscal year ended September 30, 2011 would have been sufficient to pay only 66% of the full initial quarterly distribution on all of our common units and restricted units for such period (assuming we grant 5,000 restricted units to our independent directors and an additional 495,000 restricted units to certain key employees at the closing of this offering). Please read “Executive Compensation—Long-Term Incentive Plan.”

 

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. 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 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.

 

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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  
     September 30, 2011  
     ($ in millions,
except per
unit data)
 

Pro Forma Net Income

   $ 39.2   
  

 

 

 

Add:

  

Depreciation and amortization

     37.6   

Interest expense, net(1)

     2.4   

Long-term incentive and equity compensation expense(2)

     1.5   

Transaction costs

     0.4   

Income tax expense

       
  

 

 

 

Pro Forma Adjusted EBITDA(3)

   $ 81.1  

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

  

Less:

  

Estimated incremental administrative expense(4)

     3.0   

Cash interest expense(5)

     1.6   

Cash tax expense(6)

       

Maintenance capital expenditures

     3.3   

Expansion capital expenditures(7)

     95.0   

Add:

  

Borrowings to fund expansion capital expenditures(7)

     95.0   
  

 

 

 

Pro Forma Cash Available for Distribution

   $ 73.2   
  

 

 

 

Pro Forma Cash Distributions

  

Annualized initial quarterly distributions per unit

   $ 1.48   

Distributions to public common unitholders

   $ 23.7   

Distributions to NRGY—common units

   $ 86.3   

Distributions to holders of restricted units(8)

   $ 0.7   
  

 

 

 

Total annualized initial quarterly cash distributions

   $ 110.7   
  

 

 

 

Excess (shortfall)

   $ (37.5)   
  

 

 

 

Percent of initial quarterly distributions payable to common unitholders

     66%   

 

(1)   Interest expense is based upon our estimates of: (i) average borrowings under our revolving credit facility of $132 million during the fiscal year ended September 30, 2011; (ii) interest incurred at a rate of 3.25% 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 0.30% per annum. Interest expense also includes the amortization of debt issuance costs of approximately $0.8 million per year incurred in connection with our revolving credit facility.
(2)   Represents expense associated with grants under NRGY’s long-term incentive plan and our long-term incentive plan to employees that are dedicated to our operations. Please read “Executive Compensation—Long-Term Incentive Plan.”
(3)   Adjusted EBITDA is defined in “Summary—Non-GAAP Financial Measures.”
(4)   Represents estimated incremental cash expense associated with our being a publicly traded partnership.
(5)   Cash interest expense reflects our interest expense less the non-cash amortization of deferred financing costs incurred in connection with our revolving credit facility.
(6)   As a limited liability company, we did not pay income tax during the applicable period.
(7)   Expansion capital expenditures for the fiscal year ended September 30, 2011 were $95.0 million and were primarily incurred to fund our growth projects. We assumed that these capital expenditures were funded by borrowings under our revolving credit facility. Assuming that all $95.0 million of expansion capital expenditures for the fiscal year ended September 30, 2011 were funded by borrowings under our revolving credit facility, we would have been in compliance with the financial and other covenants expected to be contained in the credit agreement for our revolving credit facility. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Sources of Capital—Revolving Credit Facility.”
(8)   Assumes that in connection with the closing of this offering, the board of directors of our general partner will grant 500,000 restricted units, in the aggregate, to our independent directors and certain key employees that provide services for us, including executive officers, pursuant to our long-term incentive plan. Please read “Executive Compensation—Long-Term Incentive Plan.” In addition, assumes that no additional unit compensation will be granted for the period presented.

 

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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 $10.3 million the amount needed to pay the initial quarterly distribution of $0.37 per unit on all of our common units and restricted 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 $0.37 per unit each quarter (or $1.48 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,
except per
unit data)
 

Revenue

 

Firm storage

  $ 104.7   

Transportation

    42.5   

Hub services

    11.5   
 

 

 

 

Total Revenue

    158.7   

Costs and expenses:

 

Storage related costs

    4.4   

Transportation related costs

    7.4   

Operating and administrative(1)

    24.7   

Depreciation and amortization

    55.0   
 

 

 

 

Total costs and expenses

    91.5   

Operating Income

    67.2   

Interest expense, net(2)

    3.6   
 

 

 

 

Net Income

    63.6   

Adjustments to reconcile net income to estimated Adjusted EBITDA:

 

Add:

 

Income tax expense(3)

      

Interest expense, net

    3.6   

Depreciation and amortization expense

    55.0   

Long-term incentive and equity compensation expense(4)

    3.6   
 

 

 

 

Estimated Adjusted EBITDA(5)

    125.8   

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

 

Less:

 

Cash interest expense(6)

    2.8   

Estimated expansion capital expenditures(2)

    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

  $ 1.48   

Distributions to public common unitholders

  $ 23.7   

Distributions to NRGY—common units

  $ 86.3   

Distributions to holders of restricted units(7)

  $ 0.7   
 

 

 

 

Total annualized initial quarterly cash distributions

  $ 110.7   
 

 

 

 

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

  $ 10.3   

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

  $ 10.3   

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

  $ 115.5   

 

(1)   Includes expense associated with grants under NRGY’s long-term incentive plan and our long-term incentive plan to employees that are dedicated to our operations.
(2)   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.”
(3)   As a limited partnership, we do not expect to pay income tax during the forecast period.

 

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(4)   Represents expense associated with grants under NRGY’s long-term incentive plan and our long-term incentive plan to employees that are dedicated to our operations. Please read “Executive Compensation—Long-Term Incentive Plan.”
(5)   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.”
(6)   Cash interest expense is book interest expense less amortization of deferred financing costs.
(7)   Assumes that in connection with the closing of this offering, the board of directors of our general partner will grant 500,000 restricted units, in the aggregate, to our independent directors and certain key employees that provide services for us, including executive officers, pursuant to our long-term incentive plan. Please read “Executive Compensation—Long-Term Incentive Plan.” In addition, assumes that no additional unit compensation will be granted for the period presented.

 

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 $47.8 million, or approximately 65%, more than the unaudited pro forma available cash for distribution for the fiscal year ended September 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;

 

   

our North/South expansion project, which involved the installation of additional compression facilities that enables us to provide approximately 325 MMcf/d of interstate transportation service under contracts extending to 2016, which we placed into service in December 2011. 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. This acquisition is expected to contribute approximately $9.6 million of available cash for distribution, including (i) $6.3 million of storage revenue that includes firm storage revenue generated under contracts existing at the time of our acquisition of the facility for 0.9 Bcf of firm storage capacity and contracts that we expect to

 

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enter into with customers effective April 1, 2012 for 0.6 Bcf of firm storage capacity at rates comparable to those charged under existing firm storage contracts, (ii) $4.6 million of transportation revenue that will be generated from services provided under a binding agreement covering 30 MMcf of intrastate firm transportation capacity, (iii) $1.9 million of revenue generated by the provision of interruptible storage services, and (iv) total expenses of $7.7 million, which includes $4.5 million of non-cash depreciation and amortization expense. We expect to sell existing capacity available and otherwise grow revenues by integrating the facility into our existing storage and transportation system, by increasing the attractiveness for storage service by interconnecting to the Millennium Pipeline (thus offering greater transportation flexibility to customers), and, with respect to interruptible services, as a result of greater production volumes in the Marcellus shale. In addition, 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. During the three months ended September 30, 2011, our Seneca Lake facility generated approximately $0.9 million of cash available for distribution, which includes $1.8 million of revenue and approximately $1.9 million of total expenses, including $1.0 million of non-cash depreciation and amortization expense.

 

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 $110.9 million for the fiscal year ended September 30, 2011. 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 82%, or approximately $90.4 million, of our total revenues that were generated from firm storage revenues during the fiscal year ended September 30, 2011. NGL prices are generally positively correlated to crude oil prices rather than natural gas prices, and storage rates are determined based in part on the market price of the commodity to be stored. Accordingly, we expect the rates we charge for natural gas storage to continue to be significantly different from the rates we charge for NGL storage. Furthermore, we have assumed that:

 

Natural Gas

 

   

Firm natural gas storage revenue is forecast to be approximately $87.1 million as compared to approximately $82.1 million provided in the fiscal year ended September 30, 2011. The increase of approximately $5.0 million in revenue as compared to the fiscal year ended September 30, 2011 is primarily the result of the increase in firm storage capacity relating to our 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 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, 2011. We have assumed we will earn storage rates under new and

 

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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 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 $8.3 million of storage revenue generated from firm NGL storage services provided for the fiscal year ended September 30, 2011. 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 $14.0 million, of our total revenues that were generated from transportation revenues during the fiscal year ended September 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 expansion 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 $8.6 million as compared to the fiscal year ended September 30, 2011 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 for the North/South expansion project covering 325 MMcf of interstate wheeling capacity, commencing December 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 6%, or approximately $6.5 million, of our total revenues that were generated from hub services revenues during the fiscal year ended September 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. In particular, we expect production volumes from the Marcellus shale to continue to increase during the forecast period, and that increased production volumes will result in greater demand for transportation capacity on our system as producers look for ways to economically ship increased production volumes to demand markets.

 

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Service Related Costs

 

Our service related costs consist primarily of utility and fuel expenses and the costs to obtain transportation capacity on certain interstate pipelines. We estimate that our service related costs will be approximately $11.8 million for the twelve months ending December 31, 2012, as compared to approximately $15.8 million for the fiscal year ended September 30, 2011. Approximately $2.4 million of the decrease in our service related costs 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. There is not a proportionate decrease in the amount of service related costs because the rate charged for the released capacity is currently substantially lower than the rate charged on the 90 MMcf/d we intend to retain. Approximately $4.8 million decrease in other storage related costs is primarily attributable to historical non-recurring costs such as the rental and operation of certain temporary compressors at our Stagecoach facility required during the historical period. These decreases are offset partially by a $3.5 million increase in utility and fuel expenses due to the placement into service of 875 MMcf/d of new transportation capacity and the acquisition of the Seneca Lake natural gas storage facility. Our service related costs may or may not increase proportionally with our increase in natural gas firm storage capacity due to our ability to offset simultaneous injections and withdrawals on behalf of our storage customers.

 

Operating and Administrative Expenses

 

We estimate that operating and administrative expenses will be approximately $24.7 million for the twelve months ending December 31, 2012, as compared to approximately $15.9 million for the fiscal year ended September 30, 2011. 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, and approximately $2.0 million of expense associated with grants under our long-term incentive plan. In connection with the closing of this offering, the board of directors of our general partner will grant 2,500 restricted units to each of our two independent directors and may grant up to an additional 495,000 restricted units to certain key employees that provide services for us, including executive officers, pursuant to our long-term incentive plan. Restricted units awarded to our independent directors at the closing of this offering will vest ratably over three years beginning on the first anniversary from the date of the grant. Restricted units awarded to key employees at the closing of this offering are expected to vest 25%, 25% and 50% on the third, fourth and fifth anniversaries, respectively, from the date of the grant. Holders of restricted units are entitled to distributions at the initial quarterly distribution rate and have such voting rights as are provided to holders of common units under our partnership agreement. For purposes of our forecast, we have assumed that 500,000 restricted units are granted at the closing of this offering and that no other unit awards are granted during the period. 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.” Our estimate of operating and administrative expenses does not include an estimate of the cost of defending the Anadarko litigation because we cannot reasonably forecast the cost of defending litigation, including the Anadarko litigation. We do not anticipate that the cost of defending the Anadarko litigation will be significantly higher than the costs of defending other legal proceedings arising in the ordinary course of our business, and we believe that Anadarko’s claims have no merit.

 

Depreciation and Amortization

 

We estimate that depreciation and amortization expense will be approximately $55.0 million for the twelve months ending December 31, 2012, as compared to approximately $37.6 million for the fiscal year ended September 30, 2011. Depreciation expense is expected to increase for the twelve months ending December 31, 2012, compared to the fiscal year ended September 30, 2011 due to the recent Seneca Lake acquisition and the expansion projects we expect to place into service in 2011 and 2012.

 

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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 $3.3 million for the fiscal year ended September 30, 2011. 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 $95.0 million for the fiscal year ended September 30, 2011. Capital expenditures related to our MARC I pipeline, North/South expansion project and proposed NGL storage facility in Watkins Glen of approximately $93.9 million were incurred for the fiscal year ended September 30, 2011. We expect to incur in the aggregate an additional $69.5 million related to these projects between September 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.

 

Please also see the table titled “Summary Capital Expenditures” in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Sources of Capital—Capital Requirements.”

 

Financing

 

We estimate that interest expense will be approximately $3.6 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 3.25%. This rate is based on a forecast of LIBOR rates during the period plus the margin and the anticipated commitment fees of 0.3% for the unused portion of our revolving credit facility;

 

   

our borrowing of $82.8 million under our revolving credit facility to repay all of the $300 million of indebtedness outstanding under our promissory note and to fund a cash distribution to NRGY for reimbursement of capital expenditures associated with our assets; and

 

   

interest expense also includes the amortization of debt issuance costs of $0.8 million incurred in connection with our revolving credit facility.

 

We secured a commitment letter from lenders containing the material terms of a new $500 million revolving credit facility that we will enter into at the closing of this offering, with a maturity date five years from the closing of this offering. For the twelve months ending December 31, 2012, assuming borrowings under our revolving credit facility of $176.1 million to fund expansion capital expenditures, $80 million to fund a distribution to NRGY and $2.8 million to repay the remaining balance of our promissory note and $3.9 million of outstanding letters of credit, we expect to have approximately $237.2 million of remaining borrowing capacity under our revolving credit facility at December 31, 2012, and we expect to be in compliance with the financial and other covenants that will be contained in the revolving credit facility. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Sources of Capital—Revolving Credit Facility.”

 

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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 future distributions to our partners 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 $0.37 per unit, or $1.48 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:

 

   

$55 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 $55 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 $55 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. 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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Index to Financial Statements

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

     $0.37         100.0       

Thereafter

     above $0.37         50.0     50.0

 

NRGY’s Right to Reset the 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 $0.50. For purposes of the following tables, the aggregate 5,000 restricted units that will be issued to our independent directors at the closing of this offering are treated as common units.

 

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

Initial quarterly distribution

   $ 0.37         100.0          $ 0.50   

Thereafter

   above $ 0.37         50.0     50.0   above $ 0.50   

 

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 74,330,000 common units outstanding and the distribution to each common unit would be $0.50 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

  $ 0.37      $ 27,502,100      $      $      $      $ 27,502,100   

Thereafter

  above $ 0.37        9,662,900               9,662,900        9,662,900        19,325,800   
   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
    $ 37,165,000      $      $ 9,662,900      $ 9,662,900      $ 46,827,900   
   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

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 93,655,800 common units outstanding and the distribution to each common unit would be $0.50. 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 $9.7 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 $0.50.

 

     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

   $ 0.50      $ 37,165,000       $ 9,662,900       $       $ 9,662,900       $ 46,827,900   

Thereafter

   above $ 0.50                                          
     

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 
      $ 37,165,000       $ 9,662,900       $       $ 9,662,900       $ 46,827,900   
     

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

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 common 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, 2007 and 2008 and for the fiscal year ended September 30, 2007 are derived from our unaudited historical consolidated financial statements that are not included in this prospectus. The selected historical financial data presented as of September 30, 2009 and for the fiscal year ended September 30, 2008 are derived from our audited historical consolidated financial statements that are not included in this prospectus. The selected historical financial data presented as of September 30, 2010 and 2011 and for the fiscal years ended September 30, 2009, 2010 and 2011 are derived from our audited 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, L.P. and its subsidiaries, excluding Tres Palacios Gas Storage and US Salt.

 

The selected pro forma financial data presented as of and for the fiscal year ended September 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 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 $129.8 million as of September 30, 2011;

 

   

our assumption of $300 million of indebtedness from NRGY under our promissory note, which we expect to (i) pay in full using the net proceeds from this offering and borrowings of approximately $2.8 million under our revolving credit facility and (ii) retire immediately following the closing of this offering;

 

   

our 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 of an aggregate 5,000 restricted units to our two independent directors pursuant to our long-term incentive plan;

 

   

the issuance by us to NRGY of 58,325,000 common units and all of our incentive distribution rights; and

 

   

the issuance by us to the public of 16,000,000 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 September 30, 2011. The unaudited pro forma statement of operations data for the fiscal year ended September 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 addition to the 5,000 restricted units granted to our independent directors, we may grant up to an additional 495,000 restricted units at the closing of this offering to certain key employees with an aggregate annual expense of approximately $2.0 million. Please read “Executive Compensation—Long-Term Incentive Plan.” Such incremental 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

 

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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 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,     Year
Ended
September 30,
 
    2007     2008     2009     2010     2011     2011  
    ($ in millions)  

Statement of operations data:

           

Revenue

  $ 56.2      $ 82.7      $ 87.5      $ 94.7      $ 110.9      $ 110.9   

Costs and expenses:

           

Service related costs

    14.4        12.4        17.8        12.0        15.8        15.8   

Operating and administrative

    6.6        11.7        10.8        15.0        15.9        15.9   

Depreciation and amortization

    16.4        24.5        29.2        36.2        37.6        37.6   

(Gain) loss on disposal of assets

    0.2        (1.9            0.9                 
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
    37.6        46.7        57.8        64.1        69.3        69.3   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating income

    18.6        36.0        29.7        30.6        41.6        41.6   

Interest expense, net

                                       (2.4

Other income

           0.8               0.8                 
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income

    18.6        36.8        29.7        31.4        41.6        39.2   

Net income attributable to non-controlling partners

           1.4        1.4        0.8                 
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income attributable to partners

  $ 18.6      $ 35.4      $ 28.3      $ 30.6      $ 41.6      $ 39.2   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Balance sheet data (at end of period):

           

Total assets

  $ 371.3      $ 480.8      $ 561.0      $ 559.5      $ 702.4      $ 706.6   

Total debt

           10.9        8.3                      82.8   

Partners’ capital

    311.1        384.8        414.3        444.8        553.3        600.3   

Other financial data:

           

Adjusted EBITDA

  $ 35.3      $ 57.7      $ 57.7      $ 70.4      $ 81.1      $ 81.1   

Maintenance capital expenditures

    0.1        0.2               0.3        3.3     

Net cash provided by operating activities

    34.3        62.9        59.5        83.5        88.8        88.8   

Net cash used in investing activities

    (103.4     (108.9     (74.1     (49.8     (165.1  

Net cash provided by (used in) financing activities

    68.2        48.9        15.3        (37.3     76.3     

Operating data:

           

Natural gas storage capacity (Bcf)

    26.3        32.5        32.5        39.5        41.0     

% of revenue generated from firm contracts

    91     98     96     98     94  

 

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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,
    Year Ended
September 30,
 
    2007     2008     2009     2010     2011     2011  
    ($ in millions)  

Reconciliation of net income to EBITDA and Adjusted EBITDA:

           

Net income

  $ 18.6      $ 36.8      $ 29.7      $ 31.4      $ 41.6      $ 39.2   

Depreciation and amortization

    16.4        24.5        29.2        36.2        37.6        37.6   

Interest expense, net

                                       2.4   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

EBITDA

  $ 35.0      $ 61.3      $ 58.9      $ 67.6      $ 79.2      $ 79.2   

Long-term incentive and equity compensation expense

    0.1        0.5        0.7        2.7        1.5        1.5   

(Gain) loss on disposal of assets

    0.2        (1.9            0.9                 

Transaction costs

                         0.2        0.4        0.4   

Net income attributable to non-controlling partners

           (1.4     (1.4     (0.8              

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

           (0.8     (0.5     (0.2              
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Adjusted EBITDA

  $ 35.3      $ 57.7      $ 57.7      $ 70.4      $ 81.1      $ 81.1   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

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

           

Net cash provided by operating activities

  $ 34.3      $ 62.9      $ 59.5      $ 83.5      $ 88.8      $ 88.8   

Net changes in working capital balances

    0.9        (3.5     (0.6     (15.0     (9.6     (9.6

Gain (loss) on disposal of assets

    (0.2     1.9               (0.9              
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

EBITDA

  $ 35.0      $ 61.3      $ 58.9      $ 67.6      $ 79.2      $ 79.2   

Long-term incentive and equity compensation expense

    0.1        0.5        0.7        2.7        1.5        1.5   

(Gain) loss on disposal of assets

    0.2        (1.9            0.9                 

Transaction costs

                         0.2        0.4        0.4   

Interest of non-controlling partners in consolidated EBITDA

           (2.2     (1.9     (1.0              
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Adjusted EBITDA

  $ 35.3      $ 57.7      $ 57.7      $ 70.4      $ 81.1      $ 81.1   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

(a)   Consists of interest, tax, depreciation and amortization expense attributable to non-controlling partners, which is determined by allocating based on proportional ownership the interest, taxes, depreciation and amortization of our less than wholly-owned Steuben natural gas storage facility for each period. However, we acquired 100% ownership of the Steuben natural gas storage facility during the year ended September 30, 2010.

 

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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 355 MMcf/d of interstate and intrastate transportation capacity and, upon completion of our MARC I pipeline that is currently under development, we will own a total of 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 October 31, 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;

 

   

our North/South expansion project, which involved the installation of additional compression facilities that enables us to provide approximately 325 MMcf/d of interstate transportation service under contracts extending to 2016, which we placed into service in December 2011;

 

   

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 October 31, 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 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 presented to us or to NRGY 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 an affiliate, Inergy Propane, LLC, or Inergy Propane. Please read “Certain Relationships and Related Party Transactions—Other Transactions with Related Persons.”

 

Transportation Contracts

 

Our North/South expansion project and our New York intrastate pipeline that we acquired in July 2011, together with our MARC I pipeline 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 expense, 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

 

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

 

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

 

     Year Ended
September 30,
     Change  
     2011      2010      In Dollars     Percentage  

Revenues

   $     110.9       $ 94.7       $ 16.2        17.1

Service related costs

     15.8         12.0         3.8        31.7   

Operating and administrative expenses

     15.9         15.0         0.9        6.0   

Depreciation and amortization

     37.6         36.2         1.4        3.9   

Loss on disposal of assets

             0.9         (0.9     (100.0
  

 

 

    

 

 

    

 

 

   

Operating income

     41.6         30.6         11.0        35.9   

Other income

             0.8         (0.8     (100.0
  

 

 

    

 

 

    

 

 

   

Net income

     41.6         31.4         10.2        32.5   

Net income attributable to non-controlling partners

             0.8         (0.8     (100.0
  

 

 

    

 

 

    

 

 

   

Net income attributable to partners

   $ 41.6       $     30.6       $     11.0