S-1/A 1 d779880ds1a.htm S-1/A S-1/A
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As filed with the Securities and Exchange Commission on January 26, 2015

Registration No. 333-198990

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

Amendment No. 6

to

FORM S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

 

 

Columbia Pipeline Partners LP

(Exact Name of Registrant as Specified in its Charter)

 

 

 

Delaware   4922   51-0658510

(State or Other Jurisdiction of

Incorporation or Organization)

 

(Primary Standard Industrial

Classification Code Number)

 

(IRS Employer

Identification Number)

5151 San Felipe St., Suite 2500

Houston, Texas 77056

713-386-3701

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

Carrie J. Hightman

Executive Vice President and Chief Legal Officer

801 East 86th Avenue

Merrillville, Indiana 46410

(877) 647-5990

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

 

 

Copies to:

David P. Oelman

Gillian A. Hobson

Vinson & Elkins L.L.P.

1001 Fannin Street, Suite 2500

Houston, Texas 77002

Tel: (713) 758-2222

 

Joshua Davidson

Hillary H. Holmes

Baker Botts L.L.P.

910 Louisiana Street

Houston, TX 77002

(713) 229-1234

 

 

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

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

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

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

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

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

 

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

 

 

CALCULATION OF REGISTRATION FEE

 

 

Title of each class of

securities to be registered

 

Amount

to be
registered(1)

  Proposed
maximum
offering price
per unit(2)
 

Proposed
Maximum
Aggregate

Offering Price(1)(2)

 

Amount of

Registration Fee(3)

Common units representing limited partner interests

  46,000,000   $21.00   $966,000,000   $122,329.20

 

 

(1) Includes common units issuable upon exercise of the underwriters’ option to purchase additional common units.
(2) Based upon the assumed initial public offering price of $21.00.
(3) The Registrant has previously paid $103,040.00 for the registration of $800,000,000 of proposed maximum aggregate offering price in connection with the Registrant’s Registration Statement on Form S-1 (File No. 333-198990) filed on September 29, 2014.

 

 

 

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

 

 

 

 


Table of Contents

The information in this preliminary 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 becomes effective. This preliminary 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.

 

Subject to Completion, dated January 26, 2015

PROSPECTUS

 

 

 

LOGO

Columbia Pipeline Partners LP

40,000,000 Common Units

Representing Limited Partner Interests

 

 

This is the initial public offering of common units representing limited partner interests of Columbia Pipeline Partners LP. We were formed by NiSource Inc. and, prior to this offering, there has been no public market for our common units. We are offering common units in this offering. We currently expect the initial public offering price to be between $19.00 and $21.00 per common unit. We have applied to list our common units on the New York Stock Exchange under the symbol “CPPL.”

Investing in our common units involves risks. Please read “Risk Factors ” beginning on page 26.

These risks include the following:

 

 

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

 

 

On a pro forma basis we would not have had sufficient cash available for distribution to pay the full minimum quarterly distribution on all units for the year ended December 31, 2013 and for the twelve-month period ended September 30, 2014, with shortfalls on our subordinated units of $11.9 million for the year ended December 31, 2013 and $7.1 million for the twelve-month period ended September 30, 2014.

 

 

CPG OpCo LP (“Columbia OpCo”), a partnership between Columbia Energy Group (“CEG”) and us, will be a restricted subsidiary and a guarantor under the credit facility of Columbia Pipeline Group, Inc. (“HoldCo”) and, if requested by HoldCo, will guarantee future HoldCo indebtedness. Such indebtedness could limit Columbia OpCo’s ability to take certain actions, including incurring indebtedness, making acquisitions and capital expenditures and making distributions to us, which could adversely affect our business, financial condition, results of operations, ability to make distributions to unitholders and value of our common units.

 

 

Our sponsor 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 our sponsor, have limited duties and may have conflicts of interest with us, and they may favor their own interests to our detriment and that of our unitholders.

 

 

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.

 

 

Unitholders will experience immediate and substantial dilution of $11.86 per common unit.

 

 

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 unitholders could lose all or part of their investment.

 

 

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as us not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service were to treat us as a corporation for federal income tax purposes, or we become subject to entity-level taxation for state tax purposes, our cash available for distribution to you would be substantially reduced.

 

 

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

In order to comply with applicable Federal Energy Regulatory Commission (the “FERC”) rate-making policies, we require an owner of our common units to be an Eligible Holder. Eligible Holders are limited partners or types of limited partners whose, or whose owners’, U.S. federal income tax status does not create or is not reasonably likely to create substantial risk of an adverse effect on the rates that can be charged by us on assets that are subject to regulation by FERC or a similar regulatory body, as determined by our general partner with the advice of counsel. If you are not an Eligible Holder, you will not be entitled to receive distributions or allocations of income or loss on your common units and your common units will be subject to redemption.

 

     Per Common Unit      Total  

Public Offering Price

   $                                $                

Underwriting Discount(1)

   $         $     

Proceeds to Columbia Pipeline Partners LP (before expenses)

   $         $     

 

(1) 

Excludes an aggregate structuring fee payable to Barclays Capital Inc. and Citigroup Global Markets Inc. that is equal to 0.5% of the gross proceeds of this offering, or approximately $            . Please read “Underwriting.” The structuring fee will be paid to Barclays Capital Inc. and Citigroup Global Markets Inc. from the gross proceeds of this offering. Please read “Use of Proceeds.”

The underwriters may purchase up to an additional 6,000,000 common units from us at the public offering price, less the underwriting discount, within 30 days from the date of this prospectus to cover over-allotments.

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 or about             , 2015 through the book-entry facilities of The Depository Trust Company.

 

 

Joint Book-Runners

 

Barclays   Citigroup   BofA Merrill Lynch
Goldman, Sachs & Co.   J.P. Morgan   Morgan Stanley   Wells Fargo Securities

Co-Managers

 

BNP PARIBAS   Credit Suisse   RBC Capital Markets   Fifth Third Securities
KeyBanc Capital Markets   MUFG   Mizuho Securities   Scotia Howard Weil   Huntington Investment Company

Prospectus dated         , 2015


Table of Contents

LOGO

 

LOGO


Table of Contents

TABLE OF CONTENTS

 

PROSPECTUS SUMMARY

     1   

Overview

     1   

Business Strategies

     4   

Competitive Strengths

     5   

System Expansion Opportunities

     6   

Our Relationship with Our Sponsor

     8   

Spin-Off

     9   

Risk Factors

     9   

Our Management

     11   

Summary of Conflicts of Interest and Fiduciary Duties

     11   

Principal Executive Offices

     12   

Formation Transactions and Partnership Structure

     12   

Organizational Structure

     13   

The Offering

     15   

Summary Historical and Pro Forma Financial and Operating Data

     21   

Non-GAAP Financial Measures

     24   

RISK FACTORS

     26   

Risks Inherent in Our Business

     26   

Risks Inherent in an Investment in Us

     44   

Tax Risks to Common Unitholders

     54   

USE OF PROCEEDS

     59   

CAPITALIZATION

     60   

DILUTION

     61   

CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

     63   

General

     63   

Subordinated Units

     66   

Unaudited Pro Forma Cash Available for Distribution for the Year Ended December  31, 2013 and Twelve Months Ended September 30, 2014

     66   

Estimated Cash Available for Distribution for the Twelve Months Ending December 31, 2015

     69   

HOW WE MAKE DISTRIBUTIONS TO OUR PARTNERS

     78   

General

     78   

Operating Surplus and Capital Surplus

     78   

Capital Expenditures

     80   

Subordination Period

     81   

Distributions From Operating Surplus During the Subordination Period

     83   

Distributions From Operating Surplus After the Subordination Period

     83   

General Partner Interest

     84   

Incentive Distribution Rights

     84   

Percentage Allocations of Distributions From Operating Surplus

     84   

IDR Holders’ Right to Reset Incentive Distribution Levels

     85   

Distributions From Capital Surplus

     87   

Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels

     88   

Distributions of Cash Upon Liquidation

     88   

SELECTED HISTORICAL AND PRO FORMA FINANCIAL AND OPERATING DATA

     91   

Non-GAAP Financial Measures

     94   

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

     96   

Overview

     96   

Spin-Off

     97   

Factors and Trends That Impact Our Business

     98   

 

i


Table of Contents

How We Evaluate Our Operations

     102   

Items Affecting Comparability of Our Financial Results

     104   

General Trends and Outlook

     105   

Results of the Predecessor’s Operations

     106   

Liquidity and Capital Resources

     109   

Critical Accounting Policies

     114   

Recently Issued Accounting Pronouncements

     116   

Qualitative and Quantitative Disclosures About Market Risk

     116   

Off Balance Sheet Arrangements

     117   

INDUSTRY OVERVIEW

     118   

Transportation and Storage Services Contractual Arrangements

     119   

U.S. Natural Gas Market Fundamentals

     120   

LNG Market Opportunity

     122   

Overview of the Marcellus and Utica Shales

     123   

BUSINESS

     124   

Overview

     124   

Spin-off

     125   

Business Strategies

     126   

Competitive Strengths

     127   

Our Relationship with Our Sponsor

     128   

Columbia OpCo’s Assets and Operations

     128   

FERC Regulation

     142   

Seasonality

     144   

Environmental and Occupational Health and Safety Regulation

     144   

Pipeline Safety and Maintenance

     148   

Title to Properties and Rights-of-Way

     151   

Insurance

     151   

Facilities

     151   

Employees

     151   

Legal Proceedings

     151   

MANAGEMENT

     152   

Management of Columbia Pipeline Partners LP

     152   

Executive Officers and Directors of Our General Partner

     152   

Director Independence

     154   

Committees of the Board of Directors

     154   

EXECUTIVE COMPENSATION AND OTHER INFORMATION

     156   

Compensation Discussion and Analysis

     156   

Long-Term Incentive Plan

     157   

Compensation of Directors

     159   

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

     160   

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

     162   

Historical Transactions

     162   

Ownership of General Partner and Limited Partner Interests

     162   

Distributions and Payments to Our General Partner and Its Affiliates

     162   

Arrangements Governing the Transactions

     164   

Omnibus Agreement

     164   

Contracts with Affiliates

     166   

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

     167   

CONFLICTS OF INTEREST AND FIDUCIARY DUTIES

     168   

Summary of Applicable Duties

     168   

Conflicts of Interest

     168   

Fiduciary Duties

     174   

 

ii


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DESCRIPTION OF THE COMMON UNITS

     177   

The Units

     177   

Restrictions on Ownership of Common Units

     177   

Transfer Agent and Registrar

     177   

Transfer of Common Units

     178   

THE PARTNERSHIP AGREEMENT

     179   

Organization and Duration

     179   

Purpose

     179   

Cash Distributions

     179   

Capital Contributions

     180   

Voting Rights

     180   

Applicable Law; Forum, Venue and Exclusive Jurisdiction; Reimbursement of Litigation Costs

     181   

Limited Liability

     182   

Issuance of Additional Interests

     183   

Amendment of the Partnership Agreement

     183   

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

     185   

Dissolution

     186   

Liquidation and Distribution of Proceeds

     186   

Withdrawal or Removal of Our General Partner

     186   

Transfer of General Partner Interest

     188   

Transfer of Ownership Interests in the General Partner

     188   

Transfer of Subordinated Units and Incentive Distribution Rights

     188   

Change of Management Provisions

     188   

Limited Call Right

     189   

Meetings; Voting

     189   

Voting Rights of Incentive Distribution Rights

     190   

Status as Limited Partner

     190   

Ineligible Holders; Redemption

     190   

Indemnification

     191   

Reimbursement of Expenses

     191   

Books and Reports

     191   

Right to Inspect Our Books and Records

     192   

Registration Rights

     192   

UNITS ELIGIBLE FOR FUTURE SALE

     193   

MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES

     195   

Taxation of the Partnership

     195   

Tax Consequences of Unit Ownership

     197   

Tax Treatment of Operations

     201   

Disposition of Units

     202   

Uniformity of Units

     204   

Tax-Exempt Organizations and Other Investors

     205   

Administrative Matters

     206   

INVESTMENT IN COLUMBIA PIPELINE PARTNERS LP BY EMPLOYEE BENEFIT PLANS

     209   

UNDERWRITING

     210   

VALIDITY OF OUR COMMON UNITS

     214   

EXPERTS

     214   

WHERE YOU CAN FIND MORE INFORMATION

     214   

FORWARD-LOOKING STATEMENTS

     215   

INDEX TO FINANCIAL STATEMENTS

     F-1   

APPENDIX A—FORM OF AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP OF COLUMBIA PIPELINE PARTNERS LP

     A-1   

APPENDIX B—ELIGIBLE HOLDER STATUS

     B-1   

APPENDIX C—GLOSSARY OF TERMS

     C-1   

 

iii


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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. We have not, and the underwriters have not, authorized any other person to provide you with information different from that contained in this prospectus and any free writing prospectus. If anyone provides you with different or inconsistent information, you should not rely on it. We are not, and the underwriters are not, making an offer to sell these securities in any jurisdiction where an offer or sale is not permitted.

This prospectus contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. Please read “Forward-Looking Statements” and “Risk Factors.”

 

 

INDUSTRY AND MARKET DATA

The market and statistical data included in this prospectus regarding the natural gas industry, including descriptions of trends in the market and our position and the position of our competitors within the industry, is based on a variety of sources, including independent industry publications, government publications and other published independent sources, information obtained from customers, distributors, suppliers and trade and business organizations, commissioned reports and publicly available information, as well as our good faith estimates, which have been derived from management’s knowledge and experience in the industry in which we operate. Although we have not independently verified the accuracy or completeness of the third-party information included in this prospectus, based on management’s knowledge and experience, we believe that these third-party sources are reliable and that the third-party information included in this prospectus or in our estimates is accurate and complete. While we are not aware of any misstatements regarding the market, industry or similar data presented herein, such data involve risks and uncertainties and are subject to change based on various factors, including those discussed under the headings “Forward-Looking Statements” and “Risk Factors” in this prospectus.

 

iv


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PROSPECTUS SUMMARY

This summary highlights information contained elsewhere in this prospectus. You should read the entire prospectus carefully, including the historical and pro forma financial statements and the notes to those financial statements, before investing in our common units. The information presented in this prospectus assumes an initial public offering price of $20.00 per common unit (the mid-point of the price range set forth on the cover page of this prospectus) and, unless otherwise indicated, that the underwriters’ option to purchase additional common units is not exercised. You should read “Risk Factors” for information about important risks that you should consider before buying our common units.

Unless the context otherwise requires, references in this prospectus to “Columbia Pipeline Partners,” “we,” “our,” “us” and the “Partnership” refer to Columbia Pipeline Partners LP and its subsidiaries, including CPG OpCo LP, or “Columbia OpCo,” which is a newly created limited partnership formed to own all of our assets. All references in this prospectus to the “Predecessor,” “our predecessor,” “we,” “our,” “us” or like terms when used in a historical context refer to the accounting predecessor to Columbia Pipeline Partners LP. The Predecessor is comprised of substantially all of the subsidiaries in NiSource’s Columbia Pipeline Group Operations segment, including its equity method investments in Hardy Storage Company, LLC, Millennium Pipeline Company, L.L.C. and Pennant Midstream, LLC. References in this prospectus to “NiSource” refer to NiSource Inc., the ultimate parent of Columbia Pipeline Partners LP. References in this prospectus to “our general partner” refer to CPP GP LLC. References in this prospectus to “our sponsor” or “CEG” refer to Columbia Energy Group, a wholly owned subsidiary of NiSource, which historically owned substantially all of the natural gas transmission and storage assets of NiSource. References in this prospectus to “HoldCo” refer to Columbia Pipeline Group, Inc., a recently formed Delaware corporation, through which NiSource will hold its interest in us and our general partner.

On September 26, 2014, the NiSource board of directors approved in principle the spin-off of NiSource’s natural gas pipeline and related businesses through a distribution to NiSource stockholders of all of the outstanding common stock of HoldCo. The spin-off is expected to take place in the second half of 2015, subject to satisfaction of various conditions. There is no assurance that the spin-off will in fact occur. In the event the spin-off does occur, HoldCo will continue to indirectly own our general partner and the limited partner interests in us that are not owned by the public. Even if the spin-off is not consummated, we expect our future involvement with NiSource will be principally conducted through CEG.

Columbia Pipeline Partners LP

Overview

We are a fee-based, growth-oriented Delaware limited partnership formed by NiSource to own, operate and develop a portfolio of pipelines, storage and related midstream assets. Our business and operations will be conducted through Columbia OpCo, a recently formed partnership between CEG and us. At the completion of this offering, our assets will consist of a 14.6% limited partner interest in Columbia OpCo, as well as the non-economic general partner interest in Columbia OpCo. Through our ownership of Columbia OpCo’s general partner, we will control all of Columbia OpCo’s assets and operations.

Columbia OpCo owns substantially all of the natural gas transmission and storage assets of CEG, including approximately 15,000 miles of strategically located interstate pipelines extending from New York to the Gulf of Mexico and one of the nation’s largest underground natural gas storage systems, with approximately 300 MMDth of working gas capacity, as well as related gathering and processing assets. For the year ended December 31, 2013, 93% of Columbia OpCo’s revenue, excluding revenues generated from cost recovery under certain regulatory tracker mechanisms, which we refer to as “tracker-related revenues,” was generated under firm revenue contracts. As of December 31, 2013, these contracts had a weighted average remaining contract life of 5.2 years.

 

 

1


Table of Contents

We expect the revenues generated from Columbia OpCo’s businesses will increase as we execute on our significant portfolio of organic growth opportunities, which include estimated capital costs of approximately $4.9 billion for identified projects that we expect will be completed by the end of 2018. Please read “—System Expansion Opportunities” for additional information about our organic growth opportunities. Additionally, we expect to increase our ownership interest in Columbia OpCo over time pursuant to our preemptive right to purchase additional limited partner interests in Columbia OpCo in connection with its issuance of any new equity interests.

Interstate Pipeline and Storage Assets. Through our ownership interests in Columbia OpCo, we own the following natural gas transportation and storage assets, which are regulated by the Federal Energy Regulatory Commission (the “FERC”):

 

   

Columbia Gas Transmission, LLC (“Columbia Gas Transmission”). Columbia OpCo owns 100% of the ownership interests in Columbia Gas Transmission, which is an interstate natural gas pipeline system that transports and stores natural gas from the Marcellus and Utica shales and other producing basins to the midwest, mid-Atlantic and northeast regions. The system consists of approximately 11,200 miles of natural gas transmission pipeline, 89 compressor stations with 617,185 horsepower of installed capacity and approximately 3,400 underground storage wells with approximately 290 MMDth of working gas capacity. Columbia Gas Transmission’s operations are located in Delaware, Kentucky, Maryland, New Jersey, New York, North Carolina, Ohio, Pennsylvania, Virginia and West Virginia.

 

   

Columbia Gulf Transmission, LLC (“Columbia Gulf”). Columbia OpCo owns 100% of the ownership interests in Columbia Gulf, an interstate natural gas pipeline system with approximately 3,400 miles of natural gas transmission pipeline and 11 compressor stations with approximately 470,200 horsepower of installed capacity. Interconnected to virtually every major natural gas pipeline system operating in the Gulf Coast, Columbia Gulf provides significant access to both diverse gas supplies and markets. Prompted by the rapid development of the Marcellus and Utica shales, Columbia Gulf has recently executed binding agreements for several capital projects to make the system bi-directional, which will ultimately reverse the historical flow on the system. Once these projects are completed, the system will be able to receive Marcellus and Utica supplies through upstream pipelines such as Columbia Gas Transmission, and transport those supplies to pipeline interconnects and markets along the Gulf Coast, including liquefied natural gas (“LNG”) export facilities that are currently in development. Columbia Gulf’s operations are located in Kentucky, Louisiana, Mississippi, Tennessee, Texas and Wyoming.

 

   

Millennium Pipeline Joint Venture (“Millennium Pipeline”). Columbia OpCo owns a 47.5% ownership interest in Millennium Pipeline Company, L.L.C., which transports an average of 1 MMDth/d of natural gas primarily sourced from the Marcellus shale to markets across southern New York and the lower Hudson Valley, as well as to the New York City market through its pipeline interconnections. Millennium Pipeline has access to the Northeast Pennsylvania Marcellus shale natural gas supply and is pursuing growth opportunities to expand its system. The Millennium Pipeline system consists of approximately 253 miles of natural gas transmission pipeline and three compressor stations with over 43,000 horsepower of installed capacity. Columbia Gas Transmission acts as operator of Millennium Pipeline and DTE Millennium Company and National Grid Millennium LLC each own an equal remaining share of Millennium Pipeline.

 

   

Hardy Storage Joint Venture (“Hardy Storage”). Columbia OpCo owns a 49% ownership interest in Hardy Storage Company, LLC, which owns an underground natural gas storage field in Hardy and Hampshire counties in West Virginia. Columbia Gas Transmission serves as operator of Hardy Storage. Hardy Storage has a working storage capacity of approximately 12 MMDth. Columbia Hardy Corporation, a subsidiary of CEG, and Piedmont Natural Gas Company, Inc. own a 1% and 50% ownership interest, respectively, in Hardy Storage.

 

 

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Table of Contents

Gathering, Processing and Other Assets. Through our ownership interests in Columbia OpCo, we own the following gathering, processing and other assets:

 

   

Columbia Midstream Group, LLC (“Columbia Midstream”). Columbia OpCo owns 100% of the ownership interests in Columbia Midstream, which provides natural gas producer services including gathering, treating, conditioning, processing and liquids handling in the Appalachian Basin. Columbia Midstream owns approximately 104 miles of natural gas gathering pipeline and one compressor station with 6,800 horsepower of installed capacity and is currently building out infrastructure to support the growing production in the Utica and Marcellus shale plays.

 

   

Pennant Midstream, LLC (“Pennant”). Columbia OpCo owns a 50% ownership interest in Pennant, which owns approximately 43 miles of wet natural gas gathering pipeline infrastructure, a gas processing facility and a natural gas liquids (“NGLs”) pipeline supporting natural gas production in the Utica shale. Columbia Midstream and an affiliate of Hilcorp Energy Company (“Hilcorp”) jointly own Pennant, with Columbia Midstream serving as the operator of Pennant and its facilities.

 

   

Columbia Energy Ventures, LLC (“CEVCO”) and Other. Columbia OpCo owns 100% of the ownership interests in CEVCO, which manages Columbia OpCo’s mineral rights positions in the Marcellus and Utica shales. CEVCO owns production rights to over 450,000 acres and has sub-leased the production rights in four storage fields and has also contributed its production rights in one other field. In addition, Columbia OpCo owns 100% of the ownership interests in CNS Microwave, Inc. (“CNS Microwave”), which provides ancillary communication services to us and third parties.

The following table sets forth selected data for Columbia OpCo’s primary assets as of December 31, 2013:

 

     Miles of Pipeline      Total Annual
Throughput
(MMDth)
     % of
Transportation
Revenue
Generated Under
Firm Contracts
    Weighted Average
Remaining
Contract Life

(years)
 

Pipeline Assets:

          

Columbia Gas Transmission

     11,161         1,354         99     5.7   

Columbia Gulf

     3,400         643         95     3.7   

Millennium Pipeline(1)

     253         362         99     6.5   

 

     Working
Storage
Capacity
(MMDth)
     Total  Annual
Withdrawal
(MMDth)
     Total  Annual
Injection
(MMDth)
     % of
Storage
Revenue
Generated
Under Firm
Contracts
    Weighted Average
Remaining
Contract Life

(years)
 

Storage Assets:

             

Columbia Gas Transmission

     287         260         236         96     4.5   

Hardy Storage(1)

     12         11         11         100     9.3   

 

     Miles of Pipeline      Processing
Capacity (MMcf/d)
     % of
Transportation
Revenue
Generated Under
Firm Contracts
    Weighted Average
Remaining
Contract Life

(years)
 

Gathering & Processing:

          

Columbia Midstream

     104                   N/A                   100     7.7   

Pennant(1)

     43                   200                   100     10.0   

 

(1) 

Table data represents 100% of the assets shown. Columbia OpCo owns a 47.5%, 49% and 50% ownership interest, respectively, in Millennium Pipeline, Hardy Storage and Pennant. CEG owns a 1% ownership interest in Hardy Storage.

 

 

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Cash Available for Distribution(1)

The following chart sets forth the estimated contribution to our forecasted cash available for distribution for the twelve months ended December 31, 2015 from each of Columbia OpCo’s primary assets:

 

LOGO

 

 

(1) 

Represents a percentage of cash available for distribution for the twelve months ended December 31, 2015 for Columbia OpCo. Please read “Cash Distribution Policy and Restrictions on Distributions” for important information as to the assumptions we have made regarding our financial forecast and for a reconciliation of cash available for distribution to net income. Our forecast, including the percentages shown, is a forward-looking statement and should be read together with our historical financial statements and accompanying notes included elsewhere in this prospectus, our unaudited pro forma combined financial statements and accompanying notes included elsewhere in this prospectus, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Risk Factors.”

Business Strategies

Our principal business objective is to increase the quarterly cash distribution that we pay to our unitholders over time while ensuring the ongoing stability of our cash flows. We expect to achieve this objective through the following business strategies:

Capitalize on organic expansion opportunities. Our assets are strategically located within close proximity to growing production from the Marcellus and Utica shales and growing demand centers, providing us with substantial organic expansion opportunities. We expect the revenues generated from Columbia OpCo’s businesses will increase as we execute on our significant portfolio of organic growth opportunities, which include estimated capital costs of approximately $4.9 billion for identified projects that we expect will be completed by the end of 2018. We intend to leverage our management team’s expertise in constructing, developing and optimizing our assets in order to increase and diversify our customer base, increase natural gas supply on our system and maximize volume throughput.

Increase our ownership interest in Columbia OpCo. We intend to increase cash flows by increasing our ownership interest in Columbia OpCo over the next several years pursuant to our preemptive right to purchase any newly issued equity interests in Columbia OpCo. We expect Columbia OpCo to issue a significant amount of

 

 

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new equity interests over the next several years to fund approximately $4.9 billion in estimated capital costs for organic growth projects that we expect will be completed by the end of 2018, and we expect to exercise our preemptive right to purchase these newly issued equity interests to the extent we have financing available. We also have a right of first offer with respect to acquiring CEG’s retained 85.4% limited partner interest in Columbia OpCo if CEG decides to sell such interest. We do not expect CEG to sell its retained limited partner interest in Columbia OpCo in the near term.

Maintain and grow stable cash flows supported by long-term, fee-based contracts. We will continue to pursue opportunities to increase the fee-based component of our contract portfolio to minimize our direct commodity price exposure. We will focus on obtaining additional long-term firm commitments from customers, which may include reservation-based charges, volume commitments and acreage dedications. Substantially all of the $4.9 billion in estimated capital costs for organic growth projects that we expect Columbia OpCo to complete by the end of 2018 are supported by long-term service contracts and binding precedent agreements.

Target a conservative and flexible capital structure. We intend to target credit metrics consistent with the profile of investment grade midstream energy companies although we do not expect to immediately seek a rating on our debt. Furthermore, we intend to maintain a balanced capital structure while financing the capital required to (i) contribute substantially all of the capital required to finance Columbia OpCo’s organic expansion projects, (ii) increase our ownership interest in Columbia OpCo and (iii) pursue potential third-party acquisitions.

Competitive Strengths

We believe that we will be able to successfully execute our business strategies because of the following competitive strengths:

Strategically-located assets. As a result of the geographic location of our operations, we are uniquely positioned to capitalize on both the growing natural gas production volumes in the Marcellus and Utica shales and the increasing demand for transportation, storage and related midstream services from new and existing customers. In addition, our assets provide a unique footprint from the Marcellus/Utica region to the Gulf of Mexico, where the majority of the natural gas liquefaction facilities for LNG export have been announced, positioning us to capitalize on the growing LNG export market.

Integrated service offerings, providing increased revenue opportunities. We provide a comprehensive package of services to natural gas producers, including natural gas gathering, processing, compression, transportation and storage. Our ability to move producers’ natural gas and NGLs from the wellhead to market allows us to earn revenue from multiple services related to a single supply of natural gas and take advantage of incremental revenue opportunities that present themselves along the value chain. Providing multiple services benefits us in attracting new customers while providing us with a better understanding of each customer’s needs and the marketplace. In addition, our ability to source and transport natural gas to market also allows us to satisfy our commercial and industrial customers’ demand for natural gas. We believe the integrated nature of our operations and the broad range of services we provide to customers allows us to compete effectively with other pipeline, storage and midstream companies that operate in our marketplace.

Stable and predictable cash flows. We generate a high percentage of our transportation and storage services revenue from reservation charges under long-term, fee-based contracts, which mitigates the risk of revenue fluctuations due to changes in near-term supply and demand conditions and commodity prices. For the year ended December 31, 2013, approximately 93% of Columbia OpCo’s revenue, excluding tracker-related revenues, was generated under firm revenue contracts. As of December 31, 2013, these contracts had a weighted average remaining contract life of 5.2 years. Furthermore, a significant portion of our cash flows are generated from contracts with creditworthy customers including local distribution companies (“LDCs”), municipal utilities, direct industrial users, electric power generators, marketers, producers and LNG exporters.

 

 

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Financial flexibility to pursue growth opportunities. We have entered into a new $500 million credit facility, which will become effective at the closing of this offering and is guaranteed by NiSource, HoldCo, CEG, OpCo GP and Columbia OpCo. Following HoldCo’s receipt of a rating by Moody’s and S&P, NiSource will be released from its guarantee of our credit facility. This facility, which will initially be undrawn, when combined with our expected ability to access the capital markets, should enable us to fund our organic capital investment projects, purchases of additional equity in Columbia OpCo and third-party acquisitions.

Our relationship with our Sponsor. Our relationship with CEG provides us with access to CEG’s extensive operational and commercial expertise. CEG owns our general partner, a majority of our limited partner interests and all of our incentive distributions rights (“IDRs”), as well as a retained 85.4% limited partner interest in Columbia OpCo. As a result of these ownership interests, we believe that CEG is incentivized to promote and support our business plan and to pursue projects that enhance the overall value of our business.

Experienced management team with a proven record of asset operation, construction, development and integration expertise. Our management team has an average of approximately 25 years of experience in the energy industry and a proven record of successfully managing, operating, developing, building, acquiring and integrating transportation, storage and other midstream assets. Our management team has established strong relationships with producers, marketers, LDCs and other end-users of natural gas throughout the upstream and midstream industries, which we believe will be beneficial to us in pursuing organic expansion opportunities. Our management team is also committed to maintaining and continually improving the safety, reliability and efficiency of our operations, which we believe is key to attracting new customers and maintaining relationships with our current customers, regulators and the communities in which we operate. We believe our management team provides us with a strong foundation for evaluating growth opportunities and maintaining the integrity and efficiency of Columbia OpCo’s assets and operations.

System Expansion Opportunities

According to an ICF International (“ICF”) study from June 2014, aggregate gas production from the Marcellus and Utica shales is projected to grow to 34 MMDth/d by 2035. Columbia OpCo’s pipelines have already begun to experience increased throughput associated with the recent increase in production from the Marcellus and Utica shales. Substantially all of Columbia Gas Transmission’s expansion projects are supported by long-term firm transportation agreements providing for the transportation of natural gas primarily from the Marcellus and Utica shales totaling over 2.75 MMDth/d of capacity. In addition, Columbia Gulf, acting as a conduit to transport Marcellus and Utica shale gas, as well as gas from other supply basins to southern markets and LNG terminals, has entered into binding precedent agreements for approximately 2.3 MMDth/d of capacity. Certain of these projects are subject to limited conditions precedent. The unique location and capabilities of Columbia OpCo’s pipeline assets place it in a strategically advantageous position to continue to capitalize on expected growth in production from the Marcellus and Utica shales.

To further capitalize on these and other positive trends, Columbia OpCo is pursuing the following significant projects:

 

Project

  Total
Estimated
Capital Costs

($  millions)(1)
  Expected
In-Service
Date
  

Description

Transportation and Storage

      

Giles County

  25   In service    Adds 12.9 miles of 8-inch pipeline and other facilities to provide 46,000 Dth/d of new firm service, which will be provided to a third party located off its Line KA system and into Columbia Gas of Virginia’s system

 

 

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Project

  Total
Estimated
Capital Costs

($  millions)(1)
  Expected
In-Service
Date
  

Description

Line 1570 Expansion

  18   In service    Replaces approximately 19 miles of 20-inch pipeline with 24-inch pipeline and adds two compressors to increase capacity by 99,000 Dth/d

West Side Expansion (Columbia Gas Transmission)

  87   In service    Increases supply takeaway from the Marcellus shale to Leach with piping modifications and compression to add 444,000 Dth/d of capacity

West Side Expansion (Columbia Gulf)(2)

  113   In service    Adds compressor station modifications along Line 100, replaces horsepower of 30,750 at Alexandria, and enhances existing interconnects to provide 540,000 Dth/d of takeaway capacity from Leach, which accesses various Gulf Coast markets

Chesapeake LNG

  33   Second quarter
2015
   Replaces existing LNG peak shaving facilities for 120,000 Dth/d of peak deliverability

East Side Expansion

  275   Third quarter
2015
   Expands facilities along Line 1278 to transport Marcellus production to mid-Atlantic markets with 312,000 Dth/d of additional capacity

Kentucky Power Plant

  24   Second quarter
2016
   Adds 2.7 miles of 16-inch greenfield pipeline from Columbia Gas Transmission’s Line P to a third-party power plant, and other related facilities to provide 72,000 Dth/d of new capacity

Utica Access

  51   Fourth quarter
2016
   Adds 4.7 miles of 20-inch pipeline and bi-directional launchers and receivers to deliver up to 205,000 Dth/d of Utica supply to Columbia Gas Transmission’s highly liquid trading pool, commonly referred to as the “TCO Pool”

Leach XPress

  1,420   Fourth quarter
2017
   Installation of approximately 124 miles of 36-inch pipeline from Majorsville to the Crawford compressor station (“Crawford CS”) located on the Columbia Gas Transmission system; 27 miles of 36-inch pipeline from Crawford CS to the McArthur compressor station located on the Columbia Gas Transmission system; and approximately 101,700 horsepower across multiple sites to provide approximately 1,500,000 Dth/d of capacity out of the Marcellus and Utica production regions to the Leach compressor station (“Leach CS”) located on the Columbia Gulf system, TCO Pool, and other markets on Columbia Gas Transmission system

Rayne XPress

  330   Fourth quarter
2017
   Across three major phases, Columbia Gulf will complete compressor station modifications along the mainline from the Rayne compressor station (“Rayne CS”) located on the Columbia Gulf system to Leach CS, replacement of 27,000 horsepower at Rayne CS, and add two greenfield compressor stations totaling 35,000 horsepower to create over 1 MMDth/d of southbound capacity away from Texas Eastern Transmission and Columbia Gas Transmission receipts

 

 

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Project

  Total
Estimated
Capital Costs
($ millions)(1)
  Expected
In-Service
Date
  

Description

Cameron Access

  310   First quarter
2018
   Adds a new 26-mile 36-inch pipeline; a new compressor station; and enhances existing compression to create 800,000 Dth/d of additional capacity into the Cameron LNG terminal

WB XPress

  870   Fourth quarter

2018

   Transports approximately 1.3 MMDth/d of Marcellus shale production on the Columbia Gas Transmission system to pipeline interconnects and East Coast markets, which includes access to the Cove Point LNG terminal

Gathering and Processing

      

Washington County Gathering

  120   2015 – 2018    Constructs a field gathering system with compression to feed natural gas into Line 1570

Big Pine Expansion

  65   Third quarter
2015
   9 miles of 20-inch pipeline extension, up to 6,000 horsepower compression in the western Pennsylvania shale production region

Modernization

      

Modernization Program

  1,200   Oct 2014 –
Oct 2017
   Various system enhancements to address reliability and integrity pursuant to Columbia Gas Transmission modernization settlement; please read “Business—Columbia OpCo’s Assets and Operations—Columbia Gas Transmission—Tariff Rates.”

Total

  4,941     

 

(1) 

Represents the project cost expected to be incurred prior to the in service date.

(2)

The Alexandria Compression portion of Columbia Gulf’s West Side Expansion (approximately $75 million in capital costs) will be placed in service in the third quarter of 2015.

These projects are subject to risks, including unexpected costs or delays. For more information about our system expansion projects, please read “Business—Columbia OpCo’s Assets and Operations” and “Risk Factors—Risks Inherent in Our Business.”

Our Relationship with Our Sponsor

One of our principal strengths is our relationship with CEG. CEG was originally formed as a Delaware corporation in 1926 and, since its acquisition by NiSource in 2000, has owned and operated substantially all of the natural gas transmission and storage assets of NiSource. CEG’s Columbia Pipeline Group has achieved a brand name in the energy infrastructure industry and developed strong relationships with producers, marketers and other end-users of natural gas throughout the upstream and midstream industries. In addition, over the past five years, CEG has implemented internal expansion capital projects totaling over $1.3 billion, of which approximately $1.1 billion was invested over the 2010 to 2013 period. We intend to utilize the significant experience of CEG’s management team to execute our growth strategy, including the construction, development and integration of additional energy infrastructure assets. NiSource is a publicly traded energy holding company whose subsidiaries provide natural gas, electricity and other products and services to approximately 3.8 million customers located within a corridor that runs from the Gulf Coast through the midwest to New England.

Following the completion of this offering, CEG will own our general partner, 6,811,398 of our common units, all of our subordinated units and our incentive distribution rights and 85.4% of the limited partner interests

 

 

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in Columbia OpCo. Given CEG’s significant ownership interest in us following this offering, we believe CEG will be motivated to promote and support the successful execution of our business strategies, including the growth of our partnership; however, we can provide no assurances that we will benefit from our relationship with CEG. While our relationship with CEG and its subsidiaries is a significant strength, it is also a source of potential conflicts. Please read “Conflicts of Interest and Fiduciary Duties.”

Spin-off

On September 26, 2014, the NiSource board of directors approved in principle the spin-off of NiSource’s natural gas pipeline and related businesses through a distribution to NiSource stockholders of all of the outstanding common stock of HoldCo, which is expected to have an investment grade rating. The spin-off is expected to take place in the second half of 2015, subject to satisfaction of various conditions. There is no assurance that the spin-off will in fact occur or that HoldCo will receive an investment grade rating. In the event the spin-off does occur, HoldCo will continue to indirectly own our general partner, 85.4% of the limited partner interests in Columbia OpCo and the limited partner interests in us that are not owned by the public. Even if the spin-off is not consummated, we expect our future involvement with NiSource will be principally conducted through CEG, our sponsor. Successful completion of the spin-off could impact our business and operations in a number of positive ways, including increased focus of management and resources on our business and operations. However, the spin-off could adversely impact our business by reducing potential access to financial support from HoldCo and CEG or as a result of recruitment and retention employee issues, increased costs associated with HoldCo becoming a standalone public entity and potential limits on our business operations as a result of certain covenants we agree to make in our omnibus agreement in connection with the tax sharing agreement that HoldCo may enter into with NiSource in connection with the spin-off. Please read “Business — Spin-Off.”

Risk Factors

An investment in our common units involves risks. You should carefully consider the risks described in “Risk Factors” and the other information in 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 costs and expenses, including cost reimbursements to our general partner and its affiliates, to enable us to pay the minimum quarterly distribution to our unitholders.

 

   

On a pro forma basis we would not have had sufficient cash available for distribution to pay the full minimum quarterly distribution on all units for the year ended December 31, 2013 and for the twelve-month period ended September 30, 2014, with shortfalls on our subordinated units of $11.9 million for the year ended December 31, 2013 and $7.1 million for the twelve-month period ended September 30, 2014.

 

   

Columbia OpCo will be a restricted subsidiary and a guarantor under HoldCo’s credit facility and, if requested by HoldCo, will guarantee future HoldCo indebtedness. Such indebtedness could limit Columbia OpCo’s ability to take certain actions, including incurring indebtedness, making acquisitions and capital expenditures and making distributions to us, which could adversely affect our business, financial condition, results of operations, ability to make distributions to unitholders and value of our common units.

 

   

Columbia OpCo will initially be party to a money pool agreement with NiSource Finance Corp. (“NiSource Finance”), which will provide Columbia OpCo with access to short-term borrowings to fund expansion capital expenditures and working capital needs. After the spin-off, the money pool is expected to be supported by HoldCo’s credit facility as a source of external funding for all participants. If there were insufficient capacity under the HoldCo credit facility to support the financing of Columbia OpCo’s needs, it could have a material adverse effect on us.

 

 

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The amount of cash we have available for distribution to holders of our units 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 assumptions underlying our forecast 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 those estimates.

 

   

Our only asset is a 14.6% interest in Columbia OpCo, over which we have operating control. Because our interest in Columbia OpCo represents our only cash-generating asset, our cash flow will depend entirely on the performance of Columbia OpCo and its ability to distribute cash to us.

 

   

Our future business opportunities may be limited as a result of our agreement with HoldCo to refrain from taking any action that would prevent HoldCo from complying with the tax sharing agreement that it may enter into with NiSource in connection with the spin-off.

 

   

We depend on certain key customers for a significant portion of our revenues. The loss of any of these key customers could result in a decline in our revenues and cash available to make distributions to you.

 

   

Our operations are subject to environmental laws and regulations that may expose us to significant costs and liabilities and changes in these laws could have a material adverse effect on our results of operations.

 

   

Our operations are subject to operational hazards and unforeseen interruptions. If a significant accident or event occurs that results in a business interruption or shutdown for which we are not adequately insured, our operations and financial results could be materially adversely affected.

 

   

The credit and risk profiles of our general partner and its ultimate owner, NiSource, and, following the spin-off, HoldCo, or Columbia OpCo’s guarantee of HoldCo’s debt, could adversely affect our credit ratings and risk profile, which could increase our borrowing costs or hinder our ability to raise capital.

 

   

If we are unable to make acquisitions on economically acceptable terms, our future growth would be limited, and any acquisitions we make may reduce, rather than increase, our cash generated from operations on a per unit basis.

Risks Inherent in an Investment in Us

 

   

Our sponsor 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 our sponsor, have limited duties and may have conflicts of interest with us, and they may favor their own interests to our detriment and that of our unitholders.

 

   

The board of directors of our general partner may modify or revoke our cash distribution policy at any time at its discretion. Our partnership agreement does not require us to pay any distributions at all.

 

   

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

 

   

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.

 

   

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

 

   

Unitholders will experience immediate and substantial dilution of $11.86 per common unit.

 

   

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 unitholders could lose all or part of their investment.

 

 

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Unitholders may have liability to repay distributions that were wrongfully distributed to them.

 

   

If we fail to develop or maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential unitholders could lose confidence in our financial reporting, which would harm our business and the trading price of our units.

Tax Risk Factors to Common Unitholders

 

   

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as us not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service (“IRS”) were to treat us as a corporation for federal income tax purposes, or we become subject to entity-level taxation for state tax purposes, our cash available for distribution to you would be substantially reduced.

 

   

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

 

   

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

Our Management

We are managed and operated by the board of directors and executive officers of our general partner, CPP GP LLC, a wholly owned subsidiary of CEG. As a result of owning our general partner, our sponsor will have the right to appoint all of the members of the board of directors of our general partner, including at least three directors meeting the independence standards established by the New York Stock Exchange (“NYSE”). At least one of our independent directors will be appointed prior to the date our common units are listed for trading on the NYSE. Our unitholders will not be entitled to elect our general partner or its directors or otherwise directly participate in our management or operations. For more information about the executive officers and directors of our general partner, please read “Management.”

Summary of Conflicts of Interest and Fiduciary Duties

Our general partner has a contractual duty to manage us in a manner that it believes is not adverse to our interest. However, the officers and directors of our general partner have fiduciary duties to manage our general partner in a manner beneficial to our sponsor, the owner of our general partner. As a result, conflicts of interest may arise in the future between us or our unitholders, on the one hand, and our sponsor and our general partner, on the other hand.

Our partnership agreement limits the liability of and replaces the fiduciary duties owed by our general partner to our unitholders. Our partnership agreement also restricts the remedies available to our unitholders for actions that might otherwise constitute a breach of fiduciary or other duties by our general partner or its directors or officers. Our partnership agreement permits the board of directors of our general partner to form a conflicts committee of independent directors and to submit to that committee matters that the board believes may involve conflicts of interest. Any matters approved by the conflicts committee will be conclusively deemed to be approved by us and all of our partners and not a breach by our general partner of any duties it may owe us or our unitholders. By purchasing a common unit, the purchaser agrees to be bound by the terms of our partnership agreement, and each 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 Delaware law.

For a more detailed description of the conflicts of interest and duties of our general partner and its directors and officers, please read “Conflicts of Interest and Fiduciary Duties.” For a description of other relationships with our affiliates, please read “Certain Relationships and Related Party Transactions.”

 

 

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Principal Executive Offices

Our principal executive offices are located at 5151 San Felipe St., Suite 2500, Houston, Texas 77056, and our telephone number is 713-386-3701. Our website address will be http://www.columbiapipelinepartners.com. We intend to make our periodic reports and other information filed with or furnished to the U.S. Securities and Exchange Commission (“SEC”), available, free of charge, through our website, as soon as reasonably practicable after those reports and such other information is 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 are a Delaware limited partnership formed by NiSource to own and operate certain of the businesses that have historically been conducted by our sponsor.

At or prior to the closing of this offering:

 

   

CEG, our sponsor, will assume the liability for approximately $1.2 billion of intercompany debt owed to NiSource Finance by certain subsidiaries in the Columbia Pipeline Group Operations segment, and NiSource Finance will novate the $1.2 billion of intercompany debt from the subsidiaries to CEG;

 

   

CEG will contribute substantially all of the subsidiaries in the Columbia Pipeline Group Operations segment to Columbia OpCo;

 

   

we will receive gross proceeds of $800.0 million from the issuance and sale of 40,000,000 common units at an assumed initial offering price of $20.00 per unit;

 

   

CEG (which will own all of Columbia OpCo’s limited partner interests) will contribute an approximate 8.4% limited partner interest in Columbia OpCo to us;

 

   

in exchange for CEG’s contribution, we will issue to CEG 6,811,398 common units, all 46,811,398 subordinated units, and all of our incentive distribution rights;

 

   

we will use $45.0 million of the proceeds from this offering to pay the underwriting discount, structuring fee and estimated offering expenses;

 

   

we will use $755.0 million of the proceeds from this offering to purchase from Columbia OpCo an additional approximate 6.2% limited partner interest in Columbia OpCo, resulting in us owning a 14.6% limited partner interest in Columbia OpCo;

 

   

Columbia OpCo will use $500.0 million of the proceeds it receives from us to make a distribution to CEG as a reimbursement of preformation capital expenditures with respect to the assets contributed to Columbia OpCo and the remaining proceeds it receives from us to fund expansion capital expenditures;

 

   

we have entered into a $500 million revolving credit facility, which will become effective at the closing of this offering and is guaranteed by NiSource, HoldCo, CEG, OpCo GP and Columbia OpCo. Following HoldCo’s receipt of a rating by Moody’s and S&P, NiSource will be released from its guarantee of our credit facility;

 

   

Columbia OpCo and its subsidiaries will enter into an intercompany money pool agreement (the “money pool”) initially with NiSource Finance and, following the spin-off, with HoldCo, under which (i) the participants may pool their funds for investments and short-term borrowings by any participant; and (ii) $750 million of borrowing capacity will be reserved for Columbia OpCo and its subsidiaries to fund expansion capital expenditures and working capital needs, with no amounts drawn at the closing of this offering; and

 

   

we and Columbia OpCo will enter into an omnibus agreement and a service agreement with CEG and its affiliates.

 

 

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We have granted the underwriters a 30-day option to purchase up to an aggregate of 6,000,000 additional common units. Any net proceeds received from the exercise of this option will be used to purchase an additional percentage limited partner interest in Columbia OpCo; Columbia OpCo will use such cash to fund expansion capital expenditures. The amount of the additional interest in Columbia OpCo purchased will depend on the number of common units issued pursuant to the exercise of such option, and will be calculated at approximately 0.16% purchased for each one million of additional common units purchased by the underwriters. If the underwriters exercise their option to purchase additional common units in full, we would purchase an additional 1.0% limited partner interest in Columbia OpCo.

Organizational Structure

The following is a simplified diagram of our ownership structure after giving effect to this offering and the related transactions.

 

LOGO

 

 

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     Units      %  

Columbia Pipeline Partners

     

Public Common Units

     40,000,000         42.7 %(1) 

Interests of CEG:

     

Common Units

     6,811,398         7.3 %(1) 

Subordinated Units

     46,811,398         50.0

Non-Economic General Partner Interest

     —           0.0 %(2) 

Incentive Distribution Rights

     —           —      (3) 
  

 

 

    

 

 

 

Total

     93,622,796         100.0

 

(1) 

Assumes no exercise of the underwriters’ option to purchase additional common units. Please read “—Formation Transactions and Partnership Structure” for a description of the impact of an exercise of the option on the common unit ownership percentages.

(2) 

Our general partner owns a non-economic general partner interest in us. Please read “How We Make Distributions to Our Partners—General Partner Interest.”

(3) 

Incentive distribution rights represent a variable interest in distributions and thus are not expressed as a fixed percentage. Please read “How We Make Distributions to Our Partners—Incentive Distribution Rights.” Distributions with respect to the incentive distribution rights will be classified as distributions with respect to equity interests. Incentive distribution rights will be issued to CEG.

 

 

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The Offering

 

Common units offered to the public

40,000,000 common units.

 

  46,000,000 common units if the underwriters exercise their option to purchase additional common units in full.

 

Units outstanding after this offering

46,811,398 common units and 46,811,398 subordinated units, each representing an aggregate 50.0% limited partner interest in us (52,811,398 common units and 46,811,398 subordinated units if the underwriters exercise their option to purchase additional common units in full). In addition, our general partner will own a non-economic general partner interest in us.

 

Use of proceeds

We intend to use the estimated net proceeds of approximately $755.0 million from this offering (based on an assumed initial offering price of $20.00 per common unit, the mid-point of the price range set forth on the cover page of this prospectus), after deducting the $36.0 million underwriting discount, the structuring fee of $4.0 million paid to Barclays Capital Inc. and Citigroup Global Markets Inc., and $5.0 million in offering expenses, to purchase an additional approximate 6.2% limited partner interest in Columbia OpCo, and Columbia OpCo will use $500.0 million of these net proceeds to make a distribution to CEG as a reimbursement of preformation capital expenditures with respect to the assets contributed to Columbia OpCo. The remaining proceeds it receives from us will be used to fund expansion capital expenditures. The approximate 6.2% interest in Columbia OpCo purchased with the proceeds from this offering, when combined with an approximate 8.4% interest in Columbia OpCo contributed to us in connection with the formation transactions, will result in our ownership of a 14.6% limited partner interest in Columbia OpCo following the closing of the offering.

 

  If the underwriters exercise their option to purchase additional common units in full, the additional net proceeds will be approximately $114.0 million (based on an assumed initial offering price of $20.00 per common unit, the mid-point of the price range set forth on the cover page of this prospectus). The net proceeds from any exercise of such option will be used to purchase an additional percentage limited partner interest in Columbia OpCo and Columbia OpCo will use such cash to fund expansion capital expenditures. The amount of the additional interest in Columbia OpCo purchased will depend on the number of common units issued pursuant to the exercise of such option, and will be calculated at approximately 0.16% additional limited partner interest in Columbia OpCo purchased for each one million of additional common units purchased by the underwriters. If the underwriters exercise their option to purchase additional common units in full, we would purchase an additional 1.0% limited partner interest in Columbia OpCo and our total ownership interest in Columbia OpCo would be 15.6%. Please read “Use of Proceeds.”

 

 

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Cash distributions

Within 60 days after the end of each quarter, beginning with the quarter ending March 31, 2015 we expect to make a minimum quarterly distribution of $0.1675 per common unit and subordinated unit ($0.67 per common unit and subordinated unit on an annualized basis) to unitholders of record on the applicable record date. For the first quarter that we are publicly traded, we will pay a prorated distribution covering the period from the completion of this offering through March 31, 2015, based on the actual length of that period.

 

  In connection with the closing of this offering, the board of directors of our general partner will adopt a policy pursuant to which distributions for each quarter will be paid to the extent we have sufficient cash after establishment of cash reserves and payment of fees and expenses, including payments to our general partner and its affiliates. Our ability to pay the minimum quarterly distribution is subject to various restrictions and other factors described in more detail in “Cash Distribution Policy and Restrictions on Distributions.”

 

  Our partnership agreement generally provides that we will distribute cash each quarter during the subordination period in the following manner:

 

   

first, to the holders of common units, until each common unit has received the minimum quarterly distribution of $0.1675, plus any arrearages from prior quarters;

 

   

second, to the holders of subordinated units, until each subordinated unit has received the minimum quarterly distribution of $0.1675; and

 

   

third, to the holders of common and subordinated units, pro rata, until each unit has received a distribution of $0.192625.

 

  If cash distributions to our unitholders exceed $0.192625 per common unit and subordinated unit in any quarter, our unitholders and CEG, as the holder of our IDRs, will receive distributions according to the following percentage allocations:

 

     Marginal Percentage Interest
in Distributions
 

Total Quarterly Distribution

Target Amount

   Unitholders     CEG
(as holder
of IDRs)
 

above $0.192625 up to $0.209375

     85.0     15.0

above $0.209375 up to $0.25125

     75.0     25.0

above $0.25125

     50.0     50.0

 

  We refer to the additional increasing distributions to our general partner as “incentive distributions.” Please read “How We Make Distributions to Our Partners—Incentive Distribution Rights.”

 

 

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  On a pro forma basis, assuming we had completed this offering and the related formation transactions on January 1, 2013, our cash available for distribution for the twelve months ended September 30, 2014 and the year ended December 31, 2013 was approximately $55.6 million and $50.8 million, respectively. The amount of cash we will need to pay the minimum quarterly distribution for four quarters on our common units and subordinated units to be outstanding immediately after this offering will be approximately $62.7 million (or an average of approximately $15.7 million per quarter). As a result, we would not have had sufficient cash available for distribution to pay the full minimum quarterly distribution on all units for the year ended December 31, 2013 and for the twelve-month period ended September 30, 2014, with shortfalls on our subordinated units of $11.9 million for the year ended December 31, 2013 and $7.1 million for the twelve-month period ended September 30, 2014. Please read “Cash Distribution Policy and Restrictions on Distributions—Unaudited Pro Forma Cash Available for Distribution for the Year Ended December 31, 2013 and Twelve Months Ended September 30, 2014.”

 

  We believe, based on our financial forecast and related assumptions included in “Cash Distribution Policy and Restrictions on Distributions,” that we will have sufficient cash available for distribution to make cash distributions for the twelve months ending December 31, 2015, at the minimum quarterly distribution rate of $0.1675 per unit per quarter ($0.67 per unit on an annualized basis) on all common units and subordinated units outstanding immediately after the closing of this offering. However, our actual results of operations, cash flows and financial condition during the forecast period may vary from the forecast. In addition, we do not have a legal or contractual obligation to pay quarterly distributions at the minimum quarterly distribution rate or at any other rate and there is no guarantee that we will pay distributions to our unitholders in any quarter. Please read “Cash Distribution Policy and Restrictions on Distributions.”

 

Subordinated units

Our sponsor will initially own all of our subordinated units. The principal difference between our common units and subordinated units is that for any quarter during the subordination period, holders of the subordinated units will not be entitled to receive any distribution from operating surplus until the common units have received the minimum quarterly distribution for such quarter plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. Subordinated units will not accrue arrearages.

 

Conversion of subordinated units

The subordination period will end on the first business day after we have earned and paid an aggregate amount of at least $0.67 (the minimum quarterly distribution on an annualized basis) multiplied by the total number of outstanding common and subordinated units for each of three consecutive, non-overlapping four-quarter periods ending on or after March 31, 2018 and there are no outstanding arrearages on our common units.

 

 

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  Notwithstanding the foregoing, the subordination period will end on the first business day after we have paid an aggregate amount of at least $1.005 (150.0% of the minimum quarterly distribution on an annualized basis) multiplied by the total number of outstanding common and subordinated units and we have earned that amount plus the related distribution on the IDRs, for any four-quarter period ending on or after March 31, 2016 and there are no outstanding arrearages on our common units.

 

  When the subordination period ends, all subordinated units will convert into common units on a one-for-one basis, and all common units will thereafter no longer be entitled to arrearages.

 

CEG’s right to reset the target distribution levels    

CEG, as the initial holder of our IDRs, will have the right, at any time when there are no subordinated units outstanding and we have made distributions at or above 150.0% of the minimum quarterly distribution for the prior four consecutive whole fiscal quarters, to reset the initial target distribution levels at higher levels based on our cash distributions at the time of the exercise of the reset election. If CEG transfers all or a portion of our IDRs in the future, then the holder or holders of a majority of our IDRs will be entitled to exercise this right. Following a reset election, the minimum quarterly distribution will be adjusted to equal the distribution for the quarter immediately preceding the reset, and the target distribution levels will be reset to correspondingly higher levels based on the same percentage increases above the reset minimum quarterly distribution as the initial target distribution levels were above the minimum quarterly distribution.

 

  If the target distribution levels are reset, the holders of our IDRs will be entitled to receive common units. The number of common units to be issued will equal the number of common units that would have entitled the holders of our IDRs to an aggregate quarterly cash distribution for the quarter prior to the reset election equal to the distribution on the IDRs for the quarter prior to the reset election. Please read “How We Make Distributions to Our Partners—IDR Holders’ Right to Reset Incentive Distribution Levels.”

 

Issuance of additional units

Our partnership agreement authorizes us to issue an unlimited number of additional units without the approval of our 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 unitholders will have only limited voting rights on matters affecting our business. Our 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

 

 

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units, including any units owned by our general partner and its affiliates, voting together as a single class. Upon completion of this offering, our sponsor will own an aggregate of 57.3% of our outstanding units (or 53.8% of our outstanding units, if the underwriters exercise their option to purchase additional common units in full). This will give our sponsor the ability to prevent the removal of our general partner. In addition, any vote to remove our general partner during the subordination period must provide for the election of a successor general partner by the holders of a majority of the common units and a majority of the subordinated units, voting as separate classes. This will provide our sponsor the ability to prevent the removal of our general partner. Please read “The Partnership Agreement—Voting Rights.”

 

Limited call right

If at any time our general partner and its affiliates own more than 80% 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 price of the common units over the 20 trading days preceding the date three days before notice of exercise of the call right is first mailed and (2) the highest per-unit price paid by our general partner or any of its affiliates for common units during the 90-day period preceding the date such notice is first mailed. Please read “The Partnership Agreement—Limited Call Right.”

 

Eligible Holders and redemption

Only Eligible Holders are entitled to own our units and to receive distributions or be allocated income or loss from us. Eligible Holders are limited partners whose, or whose owners’, federal income tax status does not have or is not reasonably likely to have a material adverse effect on the rates that can be charged by us on assets that are subject to regulation by FERC or a similar regulatory body, as determined by our general partner with the advice of counsel.

 

  We have the right (which we may assign to any of our affiliates), but not the obligation, to redeem all of the common units of any holder that is an Ineligible Holder or that has failed to certify or has falsely certified that such holder is an Eligible Holder. The purchase price for such redemption would be equal to the lesser of the holder’s purchase price and the then-current market price of the units. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner.

 

  Please read “Description of the Common Units—Transfer of Common Units” and “The Partnership Agreement—Non-Taxpaying Holders; Redemption.”

 

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, 2017 you will be allocated, on a cumulative basis, an

 

 

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amount of federal taxable income for that period that will be less than 20% of the cash distributed to you with respect to that period. For example, if you receive an annual distribution of $0.67 per unit, we estimate that your average allocable federal taxable income per year will be no more than approximately $0.14 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” for the basis of this estimate.

 

Material federal income tax consequences

For a discussion of the material federal income tax consequences that may be relevant to prospective unitholders who are individual citizens or residents of the U.S., please read “Material U.S. Federal Income Tax Consequences.”

 

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.”

 

Exchange listing

We have applied to list our common units on the NYSE under the symbol “CPPL.”

 

 

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Summary Historical and Pro Forma Financial and Operating Data

The following table shows summary historical financial and operating data of the predecessor of Columbia Pipeline Partners LP (the “Predecessor”) and pro forma financial data of the Partnership for the periods and as of the dates indicated.

The historical financial statements of the Predecessor reflect 100% of the Predecessor’s operations. The assets of the Partnership on the closing date of the offering will consist only of the acquired interest in Columbia OpCo. Columbia OpCo’s assets will consist of the following wholly owned subsidiaries of the Predecessor: Columbia Gas Transmission, Columbia Gulf, Columbia Midstream and CEVCO, as well as equity method investments in Hardy Storage, Millennium Pipeline and Pennant.

The summary historical financial data presented as of December 31, 2013 and 2012 and for the years ended December 31, 2013, 2012, and 2011 are derived from the audited financial statements of the Predecessor, which are included elsewhere in this prospectus. The summary historical financial data presented as of September 30, 2014 and for the nine months ended September 30, 2014 and 2013 are derived from the unaudited financial statements of the Predecessor, which are included elsewhere in this prospectus. The summary financial data presented as of December 31, 2011 and September 30, 2013 are derived from the unaudited financial statements of the Predecessor, which are not included elsewhere in this prospectus.

The summary pro forma financial data as of September 30, 2014 and for the fiscal year ended December 31, 2013 and the nine months ended September 30, 2014 are derived from the unaudited pro forma combined financial statements of the Partnership. The unaudited pro forma combined statements of operations for the year ended December 31, 2013 and for the nine months ended September 30, 2014 assume this offering and related transactions occurred on January 1, 2013. The unaudited pro forma combined balance sheet as of September 30, 2014 assumes the offering and related transactions occurred on September 30, 2014. The pro forma financial data give pro forma effect to:

 

   

the assumption by CEG, the Partnership’s sponsor, of the liability for approximately $1.2 billion of intercompany debt owed to NiSource Finance by certain subsidiaries in the Columbia Pipeline Group Operations segment, and the novation by NiSource Finance of that $1.2 billion of intercompany debt from the subsidiaries to CEG;

 

   

the contribution by CEG of substantially all of the subsidiaries in the Columbia Pipeline Group Operations segment to Columbia OpCo;

 

   

the receipt by the Partnership of gross proceeds of $800.0 million from the issuance and sale of 40,000,000 common units to the public at an assumed initial offering price of $20.00 per unit in this offering, the midpoint of the price range on the cover of this prospectus;

 

   

the contribution by CEG (which will own all of Columbia OpCo’s limited partner interests) of an approximate 8.4% limited partner interest in Columbia OpCo to us;

 

   

in exchange for CEG’s contribution, the issuance by the Partnership to CEG of 6,811,398 common units, all 46,811,398 subordinated units, and all of our incentive distribution rights;

 

   

the use by the Partnership of $45.0 million of the proceeds from the offering to pay the underwriting discount, structuring fee and estimated offering expenses;

 

   

the use by the Partnership of $755.0 million of proceeds from the offering to purchase from Columbia OpCo an additional approximate 6.2% limited partner interest in Columbia OpCo, resulting in the Partnership owning a 14.6% limited partner interest in Columbia OpCo;

 

   

the use by Columbia OpCo of $500.0 million of the proceeds it receives from us to make a distribution to CEG as a reimbursement of preformation capital expenditures with respect to the assets contributed to Columbia OpCo and the remaining proceeds it receives from us to fund expansion capital expenditures;

 

 

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the entry by the Partnership into a $500 million revolving credit facility, which is guaranteed by NiSource, HoldCo, CEG, OpCo GP and Columbia OpCo and under which no amounts will be drawn at the closing of this offering. Following HoldCo’s receipt of a rating by Moody’s and S&P, NiSource will be released from its guarantee of our credit facility;

 

   

the entry by Columbia OpCo and its subsidiaries into the money pool with NiSource Finance with $750 million of reserved borrowing capacity, under which no amounts will be drawn at the closing of this offering; and

 

   

the entry by the Partnership and Columbia OpCo into an omnibus agreement and a service agreement with CEG and its affiliates.

We have not given pro forma effect to incremental general and administrative expenses of approximately $5 million that we expect to incur annually as a result of operating as a publicly traded partnership, such as expenses associated with annual and quarterly reporting; tax return and Schedule K-1 preparation and distribution expenses; Sarbanes-Oxley compliance expenses; expenses associated with listing on the NYSE; independent auditor fees; legal fees; investor relations expenses; registrar and transfer agent fees; director and officer insurance expenses; and director and officer compensation expenses.

For a detailed discussion of the summary historical financial information contained in the following 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,” “Business—Our Relationship with Our Sponsor” and the audited and unaudited historical financial statements of the Predecessor and our unaudited pro forma combined financial statements included elsewhere in this prospectus. Among other things, the historical and unaudited pro forma combined financial statements include more detailed information regarding the basis of presentation for the information in the following table.

 

 

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The following table presents the non-GAAP financial measure of Adjusted EBITDA, which we use in our business as an important supplemental measure of our performance. Adjusted EBITDA is defined as net income before interest expense, income taxes, and depreciation and amortization, plus distributions of earnings received from equity investees, less income from unconsolidated affiliates and other, net. Adjusted EBITDA is not calculated or presented in accordance with generally accepted accounting principles (“GAAP”). We explain this measure under “—Non-GAAP Financial Measures” below and reconcile it to its most directly comparable financial measures calculated and presented in accordance with GAAP.

 

    Columbia Pipeline Partners LP
Predecessor Historical
    Columbia Pipeline Partners  LP
Pro Forma
 
    Year Ended December 31,     Nine Months
Ended September 30,
    Nine  Months
Ended

September 30,
2014
    Year Ended
December 31,

2013
 
    2013     2012     2011         2014             2013          
    (in millions, except per unit and operating data)  

Statement of Operations Data:

             

Total Operating Revenues

  $ 1,179.4      $ 1,000.4      $ 1,005.6      $ 1,006.5      $ 857.6      $ 1,005.4      $ 1,176.7   

Operating Expenses:

             

Operation and maintenance

    507.1        374.2        377.9        477.1        366.7        454.6        481.4   

Operation and maintenance—affiliated

    118.1        105.6        98.3        89.6        82.4        111.1        142.5   

Depreciation and amortization

    106.9        99.3        130.0        87.7        78.9        87.2        106.1   

(Gain)/loss on sale of assets

    (18.6     (0.6     0.1        (20.8     (11.3     (20.8     (18.6

Property and other taxes

    62.2        59.2        56.6        50.3        46.6        50.1        61.9   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total Operating Expenses

  $ 775.7      $ 637.7      $ 662.9      $ 683.9      $ 563.3      $ 682.2      $ 773.3   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Equity Earnings in Unconsolidated Affiliates

    35.9        32.2        14.6        32.9        25.6        32.9        35.8   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating Income

  $ 439.6      $ 394.9      $ 357.3      $ 355.5      $ 319.9      $ 356.1      $ 439.2   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Other Income (Deductions)

             

Interest expense—affiliated

    (37.9     (29.5     (29.8     (39.1     (27.6     (5.7     (1.8

Other, net

    17.6        1.5        1.2        8.0        15.3        8.0        22.6   

Income taxes

    152.4        136.9        125.6        119.7        112.4        0.2        0.2   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net Income

  $ 266.9      $ 230.0      $ 203.1      $ 204.7      $ 195.2      $ 358.2      $ 459.8   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Less:

             

Net income attributable to non-controlling interests

              (305.9     (392.7
           

 

 

   

 

 

 

Net income attributable to Columbia Pipeline Partners LP

            $ 52.3      $ 67.1   
           

 

 

   

 

 

 

 

 

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    Columbia Pipeline Partners LP
Predecessor Historical
    Columbia Pipeline Partners  LP
Pro Forma
 
    Year Ended December 31,     Nine Months
Ended September 30,
    Nine Months
Ended
September 30,
   

Year

Ended
December 31,

 
    2013     2012     2011         2014             2013         2014     2013  
    (in millions, except per unit and operating data)  

Limited partner interests in net income:

             

Common units

            $ 26.2      $ 33.6   

Subordinated units

            $ 26.1      $ 33.5   

Net income per limited partner unit (basic and diluted):

             

Common units

            $ 0.56      $ 0.72   

Subordinated units

            $ 0.56      $ 0.72   

Balance Sheet Data (at period end):

             

Total assets

  $ 7,261.8      $ 6,623.2      $ 6,142.6      $ 7,806.8      $ 6,997.5      $ 8,014.5     

Net property, plant and equipment

    4,303.4        3,741.5        3,398.7        4,790.1        4,143.5        4,770.4     

Long-term debt-affiliated, excluding amounts due within one year

    819.8        754.7        294.7        1,370.9        754.7        511.6     

Total liabilities

    3,361.9        2,883.7        2,430.6        3,701.4        3,167.2        1,320.8     

Total partners’ net equity

    3,899.9        3,739.5        3,712.0        4,105.4        3,830.3        6,693.7     

Statement of Cash Flow Data:

             

Net cash from (used for):

             

Operating activities

  $ 454.0      $ 474.9      $ 435.3      $ 446.6      $ 316.5       

Investing activities

    (797.4     (455.5     (307.2     (618.6     (527.6    

Financing activities

    343.1        (18.8     (128.1     172.1        210.6       

Other Data:

             

Adjusted EBITDA

  $ 542.7      $ 496.9      $ 491.5      $ 437.9      $ 392.2      $ 438.0      $ 541.6   

Adjusted EBITDA attributable to non-controlling interest

            $ (374.1   $ (462.5

Adjusted EBITDA attributable to Columbia Pipeline Partners LP

            $ 63.9      $ 79.1   

Maintenance capital expenditures

    132.7        209.6        220.0        90.1        80.3       

Expansion capital expenditures

    664.8        280.0        81.5        536.3        476.2       

Operating Data:(1)

             

Contracted firm capacity (MMDth/d)

    12.9        13.2        13.2        12.8        12.7       

Throughput (MMDth)

    1,997.3        2,200.0        2,393.7        1,497.2        1,492.1       

Natural gas storage capacity (MMDth)

    287        283        282        287        287       

 

(1) 

Excludes equity investments.

Non-GAAP Financial Measures

Adjusted EBITDA

We define Adjusted EBITDA as net income before interest expense, income taxes, and depreciation and amortization, plus distributions of earnings received from equity investees, less income from unconsolidated affiliates and other, net.

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 the viability of acquisitions and other capital expenditure projects and the returns on investment of various investment 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

 

 

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Adjusted EBITDA are Net Income and Net Cash Flows from Operating Activities. Our non-GAAP financial measure of Adjusted EBITDA should not be considered as an alternative to GAAP net income or net cash flows from operating activities. Adjusted EBITDA has important limitations as an analytical tool because it excludes some but not all items that affect net income and net cash flows from operating activities. 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 tables present a reconciliation of Adjusted EBITDA to the most directly comparable GAAP financial measures, on a historical basis and pro forma basis, as applicable, for each of the periods indicated.

 

     Columbia Pipeline Partners LP
Predecessor Historical
     Columbia Pipeline Partners LP
Pro Forma
 
     Year Ended December 31,     Nine Months
Ended September 30,
     Nine  Months
Ended

September 30,
2014
     Year Ended
December 31,

2013
 
     2013      2012      2011         2014              2013            
     (in millions)  

Net Income

   $ 266.9       $ 230.0       $ 203.1      $ 204.7       $ 195.2       $ 358.2       $ 459.8   

Add:

                   

Interest expense—affiliated

     37.9         29.5         29.8        39.1         27.6         5.7         1.8   

Income taxes

     152.4         136.9         125.6        119.7         112.4         0.2         0.2   

Depreciation and amortization

     106.9         99.3         130.0        87.7         78.9         87.2         106.1   

Distributions of earnings received from equity investees

     32.1         34.9         18.8        27.6         19.0         27.6         32.1   

Less:

                   

Other, net

     17.6         1.5         1.2        8.0         15.3         8.0         22.6   

Equity earnings in unconsolidated affiliates

     35.9         32.2         14.6        32.9         25.6         32.9         35.8   
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

    

 

 

    

 

 

 

Adjusted EBITDA

   $ 542.7       $ 496.9       $ 491.5      $ 437.9       $ 392.2       $ 438.0       $ 541.6   
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

    

 

 

    

 

 

 

Less:

                   

Adjusted EBITDA attributable to non-controlling interest

                   374.1         462.5   
                

 

 

    

 

 

 

Adjusted EBITDA attributable to Columbia Pipeline Partners LP

                 $ 63.9       $ 79.1   
                

 

 

    

 

 

 

 

     Columbia Pipeline Partners LP
Predecessor Historical
 
     Year Ended December 31,     Nine Months Ended
September 30,
 
     2013     2012     2011         2014             2013      
     (in millions)  

Net Cash Flows from Operating Activities

   $ 454.0      $ 474.9      $ 435.3      $ 446.6      $ 316.5   

Interest expense—affiliated

     37.9        29.5        29.8        39.1        27.6   

Current taxes

     (27.5     92.2        48.8        50.2        (39.3

Other adjustments to operating cash flows

     6.1        1.4        (4.1     14.3        (2.4

Changes in assets and liabilities

     72.2        (101.1     (18.3     (112.3     89.8   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Adjusted EBITDA

   $ 542.7      $ 496.9      $ 491.5      $ 437.9      $ 392.2   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

 

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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 costs and expenses, including cost reimbursements to our general partner and its affiliates, to enable us to pay the minimum quarterly distribution to our unitholders.

We may not have sufficient cash each quarter to pay the full amount of our minimum quarterly distribution of $0.1675 per unit, or $0.67 per unit per year, which will require us to have cash available for distribution of approximately $15.7 million per quarter, or $62.7 million per year, based on the number of common and subordinated units that will be outstanding after the completion of this offering. On a pro forma basis, assuming we had completed this offering on January 1, 2013, our cash available for distribution for the twelve months ended September 30, 2014 and the year ended December 31, 2013 would have been approximately $55.6 million and $50.8 million, respectively.

We may not have sufficient available cash from operating surplus each quarter to enable us to make cash distributions at the initial distribution rate under our cash distribution policy. The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which will fluctuate based on, among other things:

 

   

the rates we charge for our transmission, storage and gathering services;

 

   

the level of firm transmission and storage capacity sold and volumes of natural gas we transport, store and gather for our customers;

 

   

regional, domestic and foreign supply and perceptions of supply of natural gas; the level of demand and perceptions of demand in our end-use markets; and actual and anticipated future prices of natural gas and other commodities (and the volatility thereof), which may impact our ability to renew and replace firm transmission and storage agreements;

 

   

legislative or regulatory action affecting the demand for natural gas, the supply of natural gas, the rates we can charge, how we contract for services, our existing contracts, operating costs and operating flexibility;

 

   

the imposition of requirements by state agencies that materially reduce the demand of Columbia OpCo’s customers, such as LDCs and power generators, for its pipeline services;

 

   

the commodity price of natural gas, which could reduce the quantities of natural gas available for transport;

 

   

the creditworthiness of our customers;

 

   

the level of Columbia OpCo’s operating and maintenance and general and administrative costs;

 

   

the level of capital expenditures Columbia OpCo incurs to maintain its assets;

 

   

regulatory and economic limitations on the development of LNG export terminals in the Gulf Coast region;

 

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successful development of LNG export terminals in the eastern or northeastern U.S., which could reduce the need for natural gas to be transported on the Columbia Gulf pipeline system;

 

   

changes in insurance markets and the level, types and costs of coverage available, and the financial ability of our insurers to meet their obligations;

 

   

changes in, or new, statutes, regulations or governmental policies by federal, state and local authorities with respect to protection of the environment;

 

   

changes in accounting rules and/or tax laws or their interpretations;

 

   

nonperformance or force majeure by, or disputes with or changes in contract terms with, major customers, suppliers, dealers, distributors or other business partners; and

 

   

changes in, or new, statutes, regulations, governmental policies and taxes, or their interpretations.

In addition, the actual amount of cash we will have available for distribution will depend on other factors, including:

 

   

the level and timing of capital expenditures we or Columbia OpCo makes;

 

   

construction costs;

 

   

fluctuations in our or Columbia OpCo’s working capital needs;

 

   

our or Columbia OpCo’s ability to borrow funds and access capital markets;

 

   

our or Columbia OpCo’s debt service requirements and other liabilities;

 

   

restrictions contained in our or Columbia OpCo’s existing or future 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.”

On a pro forma basis we would not have had sufficient cash available for distribution to pay the full minimum quarterly distribution on all units for the year ended December 31, 2013 and for the twelve-month period ended September 30, 2014, with shortfalls on our subordinated units of $11.9 million for the year ended December 31, 2013 and $7.1 million for the twelve-month period ended September 30, 2014.

The amount of pro forma cash available for distribution for the year ended December 31, 2013 and for the twelve months ended September 30, 2014 would have been approximately $50.8 million and $55.6 million, respectively. This amount would have been sufficient to pay 100% of the minimum quarterly distribution on all common units for that period. On a pro forma basis, we would have experienced a shortfall of approximately $7.1 million for the twelve-month period ended September 30, 2014 and $11.9 million for the year ended December 31, 2013 relative to the aggregate minimum quarterly distribution for that period. For a calculation of our ability to make distributions to unitholders based on our pro forma results for the year ended December 31, 2013 and the twelve months ended September 30, 2014, please read “Cash Distribution Policy and Restrictions on Distributions.”

Columbia OpCo will be a restricted subsidiary and a guarantor under HoldCo’s credit facility and, if requested by HoldCo, will guarantee future HoldCo indebtedness. Such indebtedness could limit Columbia OpCo’s ability to take certain actions, including incurring indebtedness, making acquisitions and capital expenditures and making distributions to us, which could adversely affect our business, financial condition, results of operations, ability to make distributions to unitholders and value of our common units.

All of our cash will be generated from cash distributions from Columbia OpCo. In connection with the spin-off, HoldCo’s new credit facility will become effective and is expected to have customary covenants and

 

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restrictions on HoldCo and Columbia OpCo, as a restricted subsidiary and a guarantor of the credit facility. In addition, HoldCo expects to issue a significant amount of new senior indebtedness and use the proceeds to fund a distribution to NiSource. If requested by HoldCo, Columbia OpCo will guarantee such indebtedness. Under the omnibus agreement, at HoldCo’s request Columbia OpCo will guarantee future indebtedness of HoldCo. There is no agreement between HoldCo and Columbia OpCo limiting the amount of HoldCo indebtedness that Columbia OpCo will be obligated to guarantee. The amount of HoldCo indebtedness in general, as well as the amount that is guaranteed by Columbia OpCo, may limit the ability of Columbia OpCo to borrow to fund its operations, capital expenditures or growth strategy. Furthermore, to the extent that Columbia OpCo is required to guarantee such indebtedness, Columbia OpCo could be subject to significant operating and financial restrictions. For example, these restrictions could include covenants limiting Columbia OpCo’s ability to:

 

   

make investments and other restricted payments;

 

   

incur additional indebtedness or issue preferred stock;

 

   

create liens;

 

   

sell all or substantially all of its assets or consolidate or merge with or into other companies; and

 

   

engage in transactions with affiliates.

These covenants or any more restrictive covenants agreed to by HoldCo in the future could adversely affect Columbia OpCo’s ability to finance future business opportunities and make cash distributions to us. A breach by HoldCo of any of these covenants could result in a default in respect of the related debt. If a default occurred, the relevant lenders could elect to declare the debt, together with accrued interest and other fees, to be immediately due and payable and proceed against any collateral securing that debt, including Columbia OpCo and its assets. In addition, any acceleration of debt under HoldCo’s bank syndicated credit facility could constitute a default under other HoldCo debt, which Columbia OpCo may also guarantee. If HoldCo’s lenders or other debt creditors were to proceed against Columbia OpCo’s assets, the value of our ownership interests in Columbia OpCo could be significantly reduced which could adversely affect the value of our common units.

HoldCo would not owe us or our unitholders any fiduciary duty in allocating exceptions or baskets to covenants and financial ratios among itself and its guarantors or in amending its debt agreements to include provisions more burdensome to our operations and financing capabilities.

Columbia OpCo will initially be party to a money pool agreement with NiSource Finance, which will provide Columbia OpCo with access to short-term borrowings to fund expansion capital expenditures and working capital needs. After the spin-off, the money pool is expected to be supported by HoldCo’s credit facility as a source of external funding for all participants. If there were insufficient capacity under the HoldCo credit facility to support the financing of Columbia OpCo’s needs, it could have a material adverse effect on us.

After the spin-off, Columbia OpCo and its subsidiaries will enter into an intercompany money pool agreement with HoldCo, under which borrowing capacity of $750 million has been reserved for Columbia OpCo and its subsidiaries to fund expansion capital expenditures and working capital needs. The ability of HoldCo to make loans under the money pool will be subject to financial covenants in its credit facility. Therefore, Columbia OpCo’s capacity to borrow under the money pool may be adversely impacted by the level of borrowings by HoldCo under its credit agreement and by adverse changes in HoldCo’s financial condition or results of operations, which will be beyond the control of Columbia OpCo and us. In the event HoldCo were to default under its credit facility, HoldCo could lose access to this facility, and thus may not be able to fund a request by Columbia OpCo under the money pool. If Columbia OpCo is unable to obtain needed capital or financing on satisfactory terms to fund its organic growth projects, the amount of cash that Columbia OpCo is able to distribute to us may be reduced, which could adversely affect our business, financial condition, results of operations, ability to make distributions to unitholders and value of our common units.

 

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The amount of cash we have available for distribution to holders of our units 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 be unable to pay cash distributions during periods when we record net income.

The assumptions underlying our forecast 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 those estimates.

The forecast of cash available for distribution set forth in “Cash Distribution Policy and Restrictions on Distributions” includes our forecast of our results of operations, Adjusted EBITDA and cash available for distribution for the twelve months ending December 31, 2015. Our ability to pay the full minimum quarterly distribution in the forecast period is based on a number of assumptions that may not prove to be correct, which are discussed in “Cash Distribution Policy and Restrictions on Distributions.”

We estimate that our total cash available for distribution for the twelve-month period ending December 31, 2015 will be approximately $69.0 million, as compared to approximately $50.8 million for the year ended December 31, 2013 and approximately $55.6 million for the twelve-month period ended September 30, 2014, in each case on a pro forma basis. A majority of this expected increase in cash available for distribution is attributable to revenues from additional firm capacity subscriptions associated with our West Side Expansion and Line 1570 projects. To the extent these and our other expansion projects are not placed into service on schedule or we are not able to subscribe additional firm transmission capacity, our revenues during the forecast period will be adversely affected.

Our forecast of cash available for distribution has been prepared by management, and we have not received an opinion or report on it from any independent registered public accountants. The assumptions underlying our forecast of cash available for distribution are inherently uncertain and are subject to significant business, economic, financial, regulatory and competitive risks and uncertainties that could cause cash available for distribution to differ materially from that which is forecasted. If we do not achieve our forecasted results, our unit price could decline materially and we may not be able to pay the minimum quarterly distribution or any amount on our common units or subordinated units. Please read “Cash Distribution Policy and Restrictions on Distributions.”

Our only asset is a 14.6% interest in Columbia OpCo, over which we have operating control. Because our interest in Columbia OpCo represents our only cash-generating asset, our cash flow will depend entirely on the performance of Columbia OpCo and its ability to distribute cash to us.

We are a holding company with no material operations and only limited assets, and the source of our earnings and cash flow will consist exclusively of cash distributions from Columbia OpCo. Therefore, our ability to make quarterly distributions to our unitholders will be completely dependent on the performance of Columbia OpCo and its ability to distribute funds to us.

Columbia OpCo’s limited partnership agreement requires it to distribute all of its available cash each quarter, less the amounts of cash reserves that its general partner determines are necessary or appropriate in its reasonable discretion to provide for the proper conduct of Columbia OpCo’s business, to enable it to make distributions to us so that we can make timely distributions or to comply with applicable law or any of Columbia OpCo’s debt or other agreements. For a description of additional restrictions and factors that may affect our ability to make cash distributions, please read “Cash Distribution Policy and Restrictions on Distributions.”

 

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The amount of cash Columbia OpCo generates from its operations will fluctuate from quarter to quarter based on, among other things:

 

   

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

 

   

regulatory action affecting the supply of or demand for natural gas, its operations, the rates it can charge, how it contracts for services, its existing contracts, its operating costs or its operating flexibility;

 

   

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

 

   

prevailing economic conditions.

In addition, the actual amount of cash Columbia OpCo will have available for distribution to its partners, including us, also will depend on other factors, such as:

 

   

the level of capital expenditures it makes;

 

   

its debt service requirements and other liabilities;

 

   

restrictions contained in its debt agreements, including HoldCo’s new credit facility;

 

   

its ability to borrow funds;

 

   

fluctuations in its working capital needs;

 

   

the cost of acquisitions, if any; and

 

   

the amount of cash reserves established by it.

Our future business opportunities may be limited as a result of our agreement with HoldCo to refrain from taking any action that would prevent HoldCo from complying with the tax sharing agreement that it may enter into with NiSource in connection with the spin-off.

Under the omnibus agreement, we will agree to refrain from taking any action that would prevent HoldCo from complying with the tax sharing agreement that HoldCo may enter into with NiSource in connection with the spin-off. Under such tax sharing agreement, HoldCo will likely agree to take certain actions, or refrain from taking action, to ensure that the spin-off qualifies for tax-free status under Section 355 of the Internal Revenue Code of 1986, as amended (the “Code”), such as issuing or redeeming common stock or other securities, or permitting its subsidiaries to do so. In compliance with our obligations under the omnibus agreement, we also will agree not to take any action that could cause HoldCo to violate one of the covenants in the tax sharing agreement. For example, subject to certain limited exceptions, HoldCo is expected to agree that, for the two years following the spin-off, HoldCo will not permit CEG to enter into a transaction that would result in CEG no longer owning our general partner or that would result in CEG owning less than 55% of Columbia OpCo. The tax sharing agreement will be executed after the closing of the offering and the execution of the omnibus agreement, and may contain covenants more restrictive on Columbia OpCo than we currently anticipate. As a result, certain of our business opportunities and plans may be restricted or limited, such as our ability to acquire additional interests in Columbia OpCo, our ability to sell the general partner of Columbia OpCo, our ability to direct Columbia OpCo to sell assets outside the ordinary course of business and our ability to direct Columbia OpCo to dispose of business assets relied upon to satisfy the “active trade or business” requirement of Section 355 of the Code for the two-period period following the spin-off, which may adversely impact our financial condition, results of operations and ability to make distributions to you. Please read “Business—Spin-off.”

Expansion projects that are expected to be accretive may nevertheless reduce our cash from operations on a per unit basis.

Even if we complete expansion projects that we believe will be accretive, these expansion projects may nevertheless reduce our cash from operations on a per unit basis. Any expansion project involves potential risks, including, among other things:

 

   

service interruptions or increased downtime associated with our projects, including the reversal of Columbia Gulf’s pipelines;

 

   

a decrease in our liquidity as a result of our using a significant portion of our available cash or borrowing capacity to finance the project or acquisition;

 

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an inability to complete expansion projects on schedule or within the budgeted cost due to the unavailability of required construction personnel or materials, accidents, weather conditions or an inability to obtain necessary permits, among other factors;

 

   

the assumption of unknown liabilities when making acquisitions for which we are not indemnified or for which our indemnity is inadequate;

 

   

the diversion of our management’s attention from other business concerns;

 

   

mistaken assumptions about the overall costs of equity or debt, demand for our services, supply volumes, reserves, revenues and costs, including synergies and potential growth;

 

   

an inability to successfully integrate the businesses we build;

 

   

an inability to receive cash flows from a newly built asset until it is operational; and

 

   

unforeseen difficulties operating in new product areas or new geographic areas.

If any expansion projects or acquisitions we ultimately complete are not accretive to our distributable cash flow per unit, our ability to make distributions to you may be reduced.

We depend on certain key customers for a significant portion of our revenues. The loss of any of these key customers could result in a decline in our revenues and cash available to make distributions to you.

We rely on certain key customers for a significant portion of our revenues. Columbia Gas of Ohio, an affiliated party, and Washington Gas Light Company accounted for approximately 14%, and 9% of our contracted revenues, respectively, for the year ended December 31, 2013. Columbia Gas of Ohio and Washington Gas Light accounted for approximately 12% and 8% of our contracted revenues, respectively, for the nine months ended September 30, 2014. The loss of all or even a portion of the contracted volumes of these or other customers, as a result of competition, creditworthiness, inability to negotiate extensions or replacements of contracts or otherwise, could have a material adverse effect on our financial condition, results of operations and ability to make distributions to you, unless we are able to contract for comparable volumes from other customers at favorable rates.

The expansion of our existing assets and construction of new assets is subject to regulatory, environmental, political, legal and economic risks, which could adversely affect our results of operations and financial condition, and reduce our cash from operations on a per unit basis.

One of the ways we intend to grow our business is through the expansion of our existing assets and construction of new energy infrastructure assets. The construction of additions or modifications to our existing pipelines, and the construction of other new energy infrastructure assets, involve numerous regulatory, environmental, political and legal uncertainties beyond our control and will require the expenditure of significant capital that we may be unable to raise. If 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 expand a new pipeline, the construction may occur over an extended period of time, and we will not receive any material increases in revenues until the project is completed. We may also construct facilities to capture anticipated future growth in production or demand in regions such as the Marcellus and Utica shale production areas, which may not materialize or where contracts are later cancelled. Since we are not engaged in the exploration for and development of natural gas reserves, we do not possess reserve expertise and we often do not have access to third-party estimates of potential reserves in an area prior to constructing facilities in such area. To the extent we rely on estimates of future production in our decision to construct additions to our systems, such estimates may prove to be inaccurate because there are numerous uncertainties inherent in estimating quantities of future production. As a result, new pipelines may not be able to attract enough throughput to achieve our expected investment return, which could adversely affect our results of operations and financial condition. The construction of new pipelines may also require us to obtain new

 

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rights-of-way, and it may become more expensive for us to obtain these new rights-of-way or to renew existing rights-of-way. If the cost of renewing or obtaining new rights-of-way increases, our cash flows could be adversely affected.

Certain of our internal growth projects may require regulatory approval from federal and state authorities prior to construction, including any extensions from or additions to our transmission and storage system. 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. Such authorization may not be granted or, if granted, such authorization may include burdensome or expensive conditions.

A substantial portion of Columbia OpCo’s organic growth projects are supported by binding precedent agreements that are subject to certain conditions, which, if not satisfied, would permit the customer to opt out of the agreement.

A substantial portion of Columbia OpCo’s $4.9 billion in estimated capital costs for organic growth projects are supported by a combination of (i) service agreements, which are long-term legally binding obligations that secure Columbia OpCo’s revenue streams, and (ii) binding precedent agreements, which are subject to certain conditions to their effectiveness, which, if not satisfied, would enable either Columbia OpCo or the customer to terminate the agreement. These conditions include, among others, the receipt of governmental approvals and the achievement of certain in-service dates. If the conditions in a precedent agreement are not satisfied and the customer elects to terminate the agreement, the underlying project and the related revenue streams could be at risk, which could have a material adverse effect on our financial condition, results of operations and our ability to make distributions to unitholders.

Any significant decrease in production of natural gas in our areas of operation could adversely affect our business and operating results and reduce our cash available for distribution to unitholders.

Our business is dependent on the continued availability of natural gas production and reserves in our areas of operation. Low prices for natural gas or regulatory limitations could adversely affect development of additional reserves and production that is accessible by our pipeline and storage assets. Production from existing wells and natural gas supply basins with access to our systems will naturally decline over time. The amount of natural gas reserves underlying these wells may also be less than anticipated, and the rate at which production from these reserves declines may be greater than anticipated. Additionally, the competition for natural gas supplies to serve other markets could reduce the amount of natural gas supply for our customers or lower natural gas prices could cause producers to determine in the future that drilling activities in areas outside of our current areas of operation are strategically more attractive to them. For example, in response to historically low natural gas prices, a number of large natural gas producers have recently announced their intention to re-evaluate and/or reduce their drilling programs in certain areas. A reduction in the natural gas volumes supplied by producers could result in reduced throughput on our systems and adversely impact our ability to grow our operations and increase cash distributions to our unitholders. Accordingly, to maintain or increase the contracted capacity or the volume of natural gas transported, stored and gathered on our systems and cash flows associated therewith, our customers must continually obtain adequate supplies of natural gas.

The primary factors affecting our ability to obtain sources of natural gas include (i) the level of successful drilling activity near our systems and (ii) our ability to compete for volumes from successful new wells. We have no control over the level of drilling activity in our areas of operation, the amount of reserves associated with wells connected to our gathering system or the rate at which production from a well declines. In addition, we have no control over producers or their drilling or production decisions, which are affected by, among other things, the availability and cost of capital, prevailing and projected energy prices, demand for hydrocarbons, levels of reserves, geological considerations, environmental or other governmental regulations, the availability of drilling permits, the availability of drilling rigs, and other production and development costs.

 

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Fluctuations in energy prices can also greatly affect the development of new natural gas reserves. In general terms, the prices of natural gas, oil and other hydrocarbon products fluctuate in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control. These factors include worldwide economic conditions; weather conditions and seasonal trends; the levels of domestic production and consumer demand; the availability of imported LNG; the ability to export LNG; the availability of transportation systems with adequate capacity; the volatility and uncertainty of regional pricing differentials and premiums; the price and availability of alternative fuels; the effect of energy conservation measures; the nature and extent of governmental regulation and taxation; and the anticipated future prices of natural gas, LNG and other commodities. Declines in natural gas prices could have a negative impact on exploration, development and production activity and, if sustained, could lead to a material decrease in such activity. Sustained reductions in exploration or production activity in our areas of operation would lead to reduced utilization of our systems. Because of these factors, even if new natural gas reserves are known to exist in areas served by our assets, producers may choose not to develop those reserves.

A portion of the cash available for distribution to our unitholders is derived from royalty payments we receive on our mineral rights positions through our working interests and overriding royalty interests. We are not the operator of the wells from which we receive royalty payments and therefore, we are not able to control the timing of exploration or development efforts, or associated costs.

Through our subsidiary, CEVCO, we own production rights to over 450,000 acres in the Marcellus and Utica shale areas and have sub-leased the production rights in four storage fields and have also contributed our production rights in one other field. We do not currently operate any of these properties and do not have plans to develop the capacity to operate any of our properties. As owner of both non-operating working interests and overriding royalty interests, we are dependent on contract operators to develop our properties. Our ability to achieve targeted returns on capital in drilling or acquisition activities and to achieve production growth rates will be materially affected by decisions made by our contract operators over which we have little or no control. Such decisions include:

 

   

the timing and amount of capital expenditures;

 

   

the timing of initiating the drilling and recompleting of wells;

 

   

the extent of operating costs;

 

   

selection of technology and drilling and completion methods; and

 

   

the rate of production of reserves, if any.

If the royalty payments we receive from our sublessees are reduced, our ability to make cash distributions to our unitholders could be adversely affected.

Our revenues from CEVCO royalty interests will decrease if production on our sub-leased production rights declines, which would reduce the amount of cash we have available for distribution to our unitholders.

The amount of the royalty payments we receive on our sub-leased production rights depends in part on the amount of production on our properties. In addition, the royalty payments vary with the natural gas liquids and oil content of the production. For example, “dry gas” wells produce mainly natural gas, or methane, as opposed to “wet gas” wells, which produce methane along with other byproducts such as ethane, which may result in additional revenue streams from such production. During 2013 and 2012, natural gas prices remained relatively low, leading some producers to announce significant reductions to their drilling plans in dry gas areas. A significant reduction in the level of production on our properties could adversely affect on our ability to make distributions to our unitholders. Similarly, increased dry gas production attributable to our royalty interest would generally result in less revenue for us than the production of wet gas (i.e., production that includes oil and natural gas liquids). As a result, any significant decline in production volumes or decrease in wet gas production would reduce our royalty payments, which could adversely affect our ability to make distributions to our unitholders.

 

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Our operations are subject to environmental laws and regulations that may expose us to significant costs and liabilities and changes in these laws could have a material adverse effect on our results of operations.

Our natural gas transportation activities are subject to stringent and complex federal, state and local environmental laws and regulations. As with the industry generally, compliance with current and anticipated environmental laws and regulations increases our overall cost of business, including our capital costs to construct, maintain and upgrade pipelines and other facilities. For instance, we may be required to obtain and maintain permits and other approvals issued by various federal, state and local governmental authorities; monitor for, limit or prevent releases of materials from our operations in accordance with these permits and approvals; install pollution control equipment or replace aging pipelines and other facilities; limit or prohibit construction activities in sensitive areas such as wetlands, wilderness or urban areas or areas inhabited by endangered or threatened species; and incur potentially substantial new obligations or liabilities for any pollution or contamination that may result from our operations. Under a September 15, 1999 FERC order approving an April 5, 1999 settlement, Columbia Gas Transmission remediates polychlorinated biphenyls (“PCBs”) at specific gas transmission facilities pursuant to a 1995 Administrative Order on Consent (subsequently modified in 1996 and 2007) (“AOC”) and recovers a portion of those costs in rates. Columbia Gas Transmission’s ability to recover these costs will cease on January 31, 2015. As of September 30, 2014, Columbia Gas Transmission has recorded $2.8 million to cover costs associated with PCB remediation related to this AOC.

Moreover, new, modified or stricter environmental laws, regulations or enforcement policies could be implemented that significantly increase our or our customer’s compliance costs, pollution mitigation costs, or the cost of any remediation of environmental contamination that may become necessary, and these costs could be material. Our compliance with such new or amended legal requirements could result in our incurring significant additional expense and operating restrictions with respect to our operations, which may not be fully recoverable from customers and, thus, could reduce net income. Our customers, to whom we provide our services, may similarly incur increased costs or restrictions that may limit or decrease those customers’ operations and have an indirect material adverse effect on our business. For example, a number of state and regional legal initiatives have emerged in recent years that seek to reduce greenhouse gas (“GHG”) emissions and the U.S. Environmental Protection Agency (“EPA”), based on its findings that emissions of greenhouse gases present a danger to public health and the environment, has adopted regulations under existing provisions of the federal Clean Air Act (“CAA”) that, among other things, restrict emissions of GHGs and require the monitoring and reporting of GHG emissions from specified onshore and offshore production sources and onshore processing sources in the U.S. on an annual basis. Such regulations or any new federal laws restricting emissions of GHGs from customer operations could delay or curtail their activities and, in turn, adversely affect our business. In another example, the EPA has asserted limited regulatory authority over hydraulic fracturing, and has indicated it might seek to further expand its regulation of hydraulic fracturing while the U.S. Congress, certain state agencies, and some local governments have from time to time considered or adopted and implemented legal requirements that have imposed, and in the future could continue to impose, new or more stringent permitting, disclosure or well construction requirements on hydraulic fracturing activities, which requirements could cause our customers to incur potentially significant added costs to comply with such requirements and experience delays or curtailment in the pursuit of exploration, development or production activities, which could reduce demand for our transportation services.

Failure to comply with environmental laws and regulations, or the permits issued under them, may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial or compliance obligations and the issuance of injunctions limiting or preventing some or all of our operations. In addition, strict joint and several liabilities may be imposed under certain environmental laws, which could cause us to become liable for the conduct of others or for consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. Private parties may also have the right to pursue legal actions against us to enforce compliance, as well as to seek damages for non-compliance, with environmental laws and regulations or for personal injury or property damage that may result from environmental and other impacts of our operations. We may not be able to recover some or any of these costs through insurance or

 

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increased revenues, which may have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to you. Please read “Business—Environmental and Occupational Health and Safety Regulation” for more information.

We may incur significant costs and liabilities as a result of pipeline integrity management program testing and any necessary pipeline repair, or preventative or remedial measures.

The United States Department of Transportation (“DOT”) has adopted regulations requiring pipeline operators to develop integrity management programs for transportation pipelines located where a leak or rupture could do the most harm in “high consequence areas.” The regulations require operators to:

 

   

perform ongoing assessments of pipeline integrity;

 

   

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

 

   

improve data collection, integration and analysis;

 

   

repair and remediate the pipeline as necessary; and

 

   

implement preventive and mitigating actions.

In addition, the DOT is examining the possibility of expanding integrity management principles beyond high consequence areas.

We have incurred costs of approximately $181 million ($96 million in capital costs and $85 million in expenses) between 2007 and 2013 associated with the assessment of our pipelines to implement the integrity management program. In addition, we currently anticipate we will incur an annual average capital cost of $28 million (and an average annual operating and maintenance cost of $22 million) for the years 2014 through 2016 to implement the program.

There may be additional costs associated with any other major repairs, remediation or preventative or mitigating actions that may be determined to be necessary as a result of the testing program, which could be substantial. In addition, any additional regulatory requirements that are enacted could significantly increase the amount of these expenditures. Should we fail to comply with DOT regulations, we could be subject to penalties and fines. Please read “Business—Pipeline Safety and Maintenance” for more information.

We may incur significant costs from time to time in order to comply with DOT regulations regarding the design, strength and testing of our pipelines if the population density near any particular portion of our pipelines increases beyond specified levels.

DOT regulations govern the design strength and testing of our pipelines. The required design strength and testing of the pipe depends upon the population density near the pipeline. In the event the population density around any specific section of our pipelines increases above levels established by the DOT, we may be required to upgrade the section of our pipelines traversing through the area with pipe of higher strength or, in some cases, retest the pipe, unless a waiver from the DOT is obtained. While the majority of our pipelines are located in remote areas, the possibility exists that we could be required to incur significant expenses in the future in response to increases in population density near sections of our pipelines.

We may incur significant costs and liabilities to comply with new DOT regulations that are anticipated to be issued in the future.

The Natural Gas Pipeline Safety Act (“NGPSA”) was amended on January 3, 2012 when the president signed the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (“2011 Pipeline Safety Act”). The DOT issued an advanced notice of proposed rulemaking in August of 2011 that addressed approximately 15

 

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specific topics associated with the legislation. The topics included the role of valves in mitigating consequences, metal loss evaluation and response, pressure testing to address manufacturing and construction threats, expanding integrity management principles, underground storage of natural gas and leak detection systems, among other topics. In addition, the DOT is working on other rulemaking topics such as operator verification of records confirming the maximum allowable operating pressure of certain pipelines and integrity verification of previously untested pipelines or pipelines with other potential integrity issues, as well as others. There may be additional costs and liabilities associated with many of these pending future requirements. We continue to monitor regulatory developments associated with these pending regulations to help anticipate potential future operational and financial risks associated with the implementation of any new regulations.

Federal and state legislative and regulatory initiatives relating to pipeline safety that require the use of new or more stringent safety controls or result in more stringent enforcement of applicable legal requirements could subject us to increased capital costs, operational delays and costs of operation.

The 2011 Pipeline Safety Act is the most recent federal legislation to amend the NGPSA and Hazardous Liquid Pipeline Safety Act pipeline safety laws, requiring increased safety measures for natural gas and hazardous liquids transportation pipelines. Among other things, the 2011 Pipeline Safety Act directs the Secretary of Transportation to promulgate rules or standards relating to expanded integrity management requirements, automatic or remote-controlled valve use, excess flow valve use, leak detection system installation, testing to confirm that the material strength of certain pipelines are above 30% of specified minimum yield strength, and operator verification of records confirming the maximum allowable pressure of certain interstate gas transmission pipelines. The 2011 Pipeline Safety Act also increases the maximum penalty for violation of pipeline safety regulations from $100,000 to $200,000 per violation per day of violation and also from $1 million to $2 million for a related series of violations. The safety enhancement requirements and other provisions of the 2011 Pipeline Safety Act as well as any implementation of Pipeline Hazardous Materials Safety Administration (“PHMSA”) rules thereunder or any issuance or reinterpretation of guidance by PHMSA or any state agencies with respect thereto could require us to install new or modified safety controls, pursue additional capital projects, or conduct maintenance programs on an accelerated basis, any or all of which tasks could result in our incurring increased operating costs that could be significant and have a material adverse effect on our results of operations or financial position.

In this climate of increasingly stringent regulation, pipeline failures or failures to comply with applicable regulations could result in shut-downs, capacity constraints or operational limitations to our pipelines. Should any of these risks materialize, it could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.

Our natural gas transportation and storage operations are subject to extensive regulation by the FERC.

Our business operations are subject to extensive regulation by the FERC, including the types and terms of services we may offer to our customers, construction of new facilities, creation, modification or abandonment of services or facilities, recordkeeping and relationships with affiliated companies. Compliance with these requirements can be costly and burdensome and the FERC action in any of these areas could adversely affect our ability to compete for business, construct new facilities, offer new services or recover the full cost of operating our pipelines. This regulatory oversight can result in longer lead times to develop and complete any future project than competitors that are not subject to the FERC’s regulations. We cannot give any assurance regarding the likely future regulations under which we will operate our natural gas transportation and storage business or the effect such regulation could have on our business, financial condition and results of operations.

Rate regulation could limit our ability to recover the full cost of operating our pipelines, including a reasonable return, and our ability to make distributions to you.

The rates we can charge for our natural gas transportation and storage operations are regulated by the FERC pursuant to the Natural Gas Act of 1938 (“NGA”). Under the NGA, we may only charge rates that have been

 

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determined to be just and reasonable by the FERC and are prohibited from unduly preferring or unreasonably discriminating against any person with respect to our rates or terms and conditions of service. The FERC establishes both the maximum and minimum rates we can charge. The basic elements that the FERC considers are the costs of providing service, the volumes of gas being transported or stored, the rate design, the allocation of costs between services, the capital structure and the rate of return a natural gas company is permitted to earn.

We may not be able to recover all of our costs through existing or future rates. Proposed rate increases may be challenged by protest and allowed to go into effect subject to refund. Even if a rate increase is permitted by the FERC to become effective, the rate increase may not be adequate. To the extent our costs increase in an amount greater than our revenues increase, or there is a lag between our cost increases and our ability to file for and obtain rate increases, our operating results would be negatively affected.

Our existing rates may be challenged by complaint or sua sponte by the FERC. In recent years, the FERC has exercised this authority with respect to several other pipeline companies. In a potential proceeding involving the challenge of our existing rates, the FERC may, on a prospective basis, order refunds of amounts collected if it finds the rates to have been shown not to be just and reasonable or to have been unduly discriminatory. Any successful challenge against our rates could have an adverse impact on our revenues associated with providing transportation and storage services. In addition, future changes to laws, regulations and policies may impair our ability to recover costs and the ability to make distributions to you.

Certain of our gas pipeline services are subject to long-term, fixed-price “negotiated rate” contracts that are not subject to adjustment, even if our cost to perform such services exceeds the revenues received from such contracts.

Under FERC policy, a regulated service provider and a customer may mutually agree to sign a contract for service at a “negotiated rate” which may be above or below the FERC regulated, cost-based recourse rate for that service. These “negotiated rate” contracts are not generally subject to adjustment for increased costs which could be produced by inflation or other factors relating to the specific facilities being used to perform the services. Any shortfall of revenue as result of these “negotiated rate” contracts could decrease our cash flow.

We are exposed to costs associated with lost and unaccounted for volumes.

A certain amount of natural gas is naturally lost in connection with its transportation across a pipeline system, and under our contractual arrangements with our customers we are entitled to retain a specified volume of natural gas in order to compensate us for such lost and unaccounted for volumes as well as the natural gas used to run our compressor stations, which we refer to as fuel usage. The level of fuel usage and lost and unaccounted for volumes on our transmission and storage system and our gathering system may exceed the natural gas volumes retained from our customers as compensation for our fuel usage and lost and unaccounted for volumes pursuant to our contractual agreements. The FERC-approved tariffs of our transmission and storage companies provide for annual filings to adjust the amount of gas retained from customers to eliminate any overages or shortfalls from the prior year. Our gathering companies have contracts that provide for specified levels of fuel retainage, so they may find it necessary to purchase natural gas in the market to make up for the difference, which exposes us to commodity price risk. Future exposure to the volatility of natural gas prices as a result of gas imbalances on our gathering systems could have a material adverse effect on our business, financial condition, results of operations and ability to make quarterly cash distributions to our unitholders.

We could be subject to penalties and fines if we fail to comply with FERC regulations.

Should the FERC find that we have failed to comply with all applicable FERC-administered statutes, rules, regulations, and orders, or the terms of our tariffs on file with the FERC, we could be subject to substantial penalties and fines. Under the Energy Policy Act of 2005 (“EPAct 2005”), the FERC has civil penalty authority under the NGA and Natural Gas Policy Act of 1978 (“NGPA”) to impose penalties for violations of up to $1,000,000 per day for each violation, to revoke existing certificate authority and to order disgorgement of profits associated with any violation.

 

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Certain of our assets may become subject to FERC regulation.

The distinction between federally unregulated gathering facilities and FERC-regulated transmission pipelines under the NGA has been the subject of substantial litigation and the FERC currently determines whether facilities are gathering facilities on a case-by-case basis. Consequently, the classification and regulation of our gathering facilities could change based on future determinations by the FERC, the courts or Congress. If more of our gas gathering operations become subject to FERC jurisdiction, the result may adversely affect the rates we are able to charge and the services we currently provide, and may include the potential for a termination of our gathering agreements with our customers.

We do not own all of the land on which our pipelines are located, which could disrupt our operations.

We do not own all of the land on which our pipelines are located, and we are therefore subject to the possibility of more onerous terms and/or increased costs to retain necessary land use rights required to conduct our operations. We obtain the rights to construct and operate our pipelines on land owned by third parties and governmental agencies for a specific period of time. In certain instances, our rights-of-way may be subordinate to that of government agencies, which could result in costs or interruptions to our service. Restrictions on our ability to use our rights-of-way, through our inability to renew right-of-way contracts or otherwise, could have a material adverse effect on our business, results of operations and financial condition and our ability to make cash distributions to you.

Our operations are subject to operational hazards and unforeseen interruptions. If a significant accident or event occurs that results in a business interruption or shutdown for which we are not adequately insured, our operations and financial results could be materially adversely affected.

Our operations are subject to many hazards inherent in the transportation and storage of natural gas, including:

 

   

aging infrastructure, mechanical or other performance problems;

 

   

damage to pipelines, facilities and related equipment caused by hurricanes, tornadoes, floods, fires and other natural disasters, explosions and acts of terrorism;

 

   

inadvertent damage from third parties, including from construction, farm and utility equipment;

 

   

leaks of natural gas and other hydrocarbons or losses of natural gas as a result of the malfunction of equipment or facilities;

 

   

operator error;

 

   

environmental hazards, such as natural gas leaks, product and waste spills, pipeline and tank ruptures, and unauthorized discharges of products, wastes and other pollutants into the surface and subsurface environment, resulting in environmental pollution; and

 

   

explosions and blowouts.

These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage and may result in curtailment or suspension of our related operations or services. A natural disaster or other hazard affecting the areas in which we operate could have a material adverse effect on our operations.

Debt that we or Columbia OpCo incur in the future may limit our or Columbia OpCo’s flexibility to obtain additional financing and to pursue other business opportunities.

We have entered into a new $500 million credit facility, which will become effective at the closing of this offering and is guaranteed by NiSource, HoldCo, CEG, OpCo GP and Columbia OpCo. Following HoldCo’s receipt of a rating by Moody’s and S&P, NiSource will be released from its guarantee of our credit facility. Columbia OpCo and its subsidiaries will enter into an intercompany money pool agreement initially with NiSource Finance, and following the spin-off, with HoldCo with $750 million of reserved borrowing

 

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capacity, which will be undrawn at the time of closing. In addition, Columbia OpCo, CEG and OpCo GP will guarantee HoldCo’s credit facility as well as future HoldCo indebtedness if requested. Our existing and future level of debt, as well as Columbia OpCo’s future level of debt, could have important consequences to us, including the following:

 

   

our ability and Columbia OpCo’s 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;

 

   

the funds that we or Columbia OpCo have available for operations and cash distributions to unitholders will be reduced by that portion of our and Columbia OpCo’s respective cash flow required to make principal and interest payments on outstanding debt; and

 

   

our debt level could make us more vulnerable than our competitors with less debt to competitive pressures or a downturn in our business or the economy generally.

Our ability to service our debt and Columbia OpCo’s 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. In addition, our ability to service debt under our revolving credit facility will depend on market interest rates, since we anticipate that the interest rates applicable to our borrowings will fluctuate with movements in interest rate markets. If our operating results are not sufficient to service our current or 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, restructuring or refinancing our debt, or seeking additional equity capital. We may not be able to effect any of these actions on satisfactory terms, or at all.

Restrictions in our new or any future credit facility could adversely affect our business, financial condition, results of operations, ability to make distributions to unitholders and the value of our common units.

We have entered into a new credit facility, which will become effective at the closing of this offering. Our new credit facility, or any future credit facility we or Columbia OpCo may enter into, is likely to limit our ability and Columbia OpCo’s ability to, among other things:

 

   

make distributions if any default or event of default occurs;

 

   

make other restricted distributions or dividends on account of the purchase, redemption, retirement, acquisition, cancellation or termination of partnership interests;

 

   

incur additional indebtedness or guarantee other indebtedness;

 

   

grant liens or make certain negative pledges;

 

   

make certain loans or investments;

 

   

engage in transactions with affiliates;

 

   

transfer, sell or otherwise dispose of all or substantially all of our or Columbia OpCo’s assets; or

 

   

enter into a merger, consolidate, liquidate, wind up or dissolve.

Furthermore, any new or future credit facility may also contain covenants requiring us or Columbia OpCo to maintain certain financial ratios and tests. Our ability and Columbia OpCo’s ability to comply with the covenants and restrictions contained in our credit facility may be affected by events beyond our control, including prevailing economic, financial and industry conditions. If market or other economic conditions deteriorate, our ability and Columbia OpCo’s ability to comply with these covenants may be impaired. If we or Columbia OpCo violates any of the restrictions, covenants, ratios or tests in our credit facility, the lenders will be able to accelerate the maturity of all borrowings under the credit facility and demand repayment of amounts outstanding, our lenders’ commitment to make further loans to us may terminate and Columbia OpCo will be prohibited from making any distribution to us and, ultimately, to you. We might not have, or be able to obtain, sufficient funds to

 

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make these accelerated payments. Any subsequent replacement of our credit facility or any new indebtedness could have similar or greater restrictions. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.” Any interruption of distributions to us from our subsidiaries may limit our ability to satisfy our obligations and to make distributions to you.

The credit and risk profiles of our general partner and its ultimate owner, NiSource, and, following the spin-off, HoldCo, or Columbia OpCo’s guarantee of HoldCo debt, 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 NiSource, and, following the spin-off, HoldCo, or Columbia OpCo’s guarantee of HoldCo debt, may be factors considered in credit evaluations of us. This is because our general partner controls our business activities, including our cash distribution policy, acquisition strategy and business risk profile. Another factor that may be considered is the financial condition of NiSource, and, following the spin-off, HoldCo, including the degree of its financial leverage and its dependence on cash flow from the partnership to service its indebtedness.

If we seek a credit rating in the future, our credit rating may be adversely affected by our guarantee of HoldCo debt and the leverage of our general partner or NiSource, and, following the spin-off, HoldCo, as credit rating agencies such as Standard & Poor’s Ratings Services and Moody’s Investors Service may consider the leverage and credit profile of NiSource, and, following the spin-off, HoldCo, and their respective affiliates because of their ownership interest in and control of us and the strong operational links between NiSource, and, following the spin-off, HoldCo, and us. Any adverse effect on our credit rating could increase our cost of borrowing or hinder our ability to raise financing in the capital markets, which could impair our ability to grow our business and make distributions to unitholders.

If third-party pipelines and other facilities interconnected to our pipelines and facilities become unavailable to transport natural gas, our revenues and cash available for distribution could be adversely affected.

We depend upon third-party pipelines and other facilities that provide delivery options to and from our pipelines. For example, our pipelines interconnect with virtually every major interstate pipeline in the eastern portion of the U.S. and a significant number of intrastate pipelines. Because we do not own these third-party pipelines or facilities, their continuing operation is not within our control. If these pipeline connections were to become unavailable for current or future volumes of natural gas due to repairs, damage, lack of capacity or any other reason, our ability to operate efficiently and continue shipping natural gas to end markets could be restricted, thereby reducing our revenues. Any temporary or permanent interruption at any key pipeline interconnect which causes a material reduction in volumes transported on our pipelines could have a material adverse effect on our business, results of operations, financial condition and ability to make distributions to you.

The current Columbia Gulf and Columbia Gas Transmission pipeline infrastructure is aging, which may adversely affect our business, results of operations, financial condition and ability to make distributions.

The Columbia Gulf and Columbia Gas Transmission pipeline systems have been in operation for many years, with some portions of these pipelines being more than 50 years old. Segments of the Columbia Gulf and Columbia Gas Transmission pipeline systems are located in or near areas determined to be high consequence areas. We implement integrity management testing of the pipelines that we operate, including the Columbia Gulf and Columbia Gas Transmission pipelines, and we repair, remediate or replace segments on those pipelines as necessary when anomaly conditions are identified during the integrity testing process or are determined to have occurred during the course of operations. Nonetheless, we also are currently investing significant capital over the next several years to replace aging infrastructure, including replacement of the relatively older pipe found on the Columbia Gulf and Columbia Gas Transmission systems. If, due to their age, these pipeline sections were to become unexpectedly unavailable for current or future volumes of natural gas because of repairs, damage, spills or leaks, or any other reason, it could result in a material adverse impact on our business, financial condition and results of operation as well as our ability to make distributions to our unitholders.

 

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LNG export terminals may not be developed in the Gulf Coast region or may be developed outside our areas of operations.

We are in the process of reversing the flow of the Columbia Gulf pipeline system in order to supply new and developing LNG export facilities located along the Gulf Coast. However, we may not realize expected increases in future natural gas demand from LNG exports due to factors including:

 

   

new projects may fail to be developed;

 

   

new projects may not be developed at their announced capacity;

 

   

development of new projects may be significantly delayed;

 

   

new projects may be built in locations that are not connected to our system; or

 

   

new projects may not influence sources of supply on our system.

Similarly, the development of new, or the expansion of existing, LNG facilities outside our areas of operations could reduce the need for customers to transport natural gas on our assets. This could reduce the amount of natural gas transported by our pipeline.

We are exposed to the credit risk of our customers and our credit risk management may not be adequate to protect against such risk.

We are subject to the risk of loss resulting from nonpayment and/or nonperformance by our customers. Our credit procedures and policies may not be adequate to fully eliminate customer credit risk. If we fail to adequately assess the creditworthiness of existing or future customers, unanticipated deterioration in their creditworthiness and any resulting increase in nonpayment and/or nonperformance by them and inability to re-market the resulting capacity could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to you. We may not be able to effectively re-market such capacity during and after insolvency proceedings involving a customer.

If we are unable to make acquisitions from our sponsor or third parties on economically acceptable terms, our future growth would be limited, and any acquisitions we make may reduce, rather than increase, our cash generated from operations on a per unit basis.

Our strategy to grow our business and increase distributions to unitholders is dependent on our ability to make acquisitions that result in an increase in our cash available for distribution per unit. If we are unable to make acquisitions of additional interests in Columbia OpCo from CEG on acceptable terms, or we are unable to obtain financing for these acquisitions on economically acceptable terms, our future growth and ability to increase distributions will be limited. In addition, we may be unable to make acquisitions from third parties as an alternative avenue to growth. Furthermore, even if we do consummate acquisitions that we believe will be accretive, they may in fact result in a decrease in our cash available for distribution per unit. Any acquisition involves potential risks, some of which are beyond our control, including, among other things:

 

   

mistaken assumptions about revenues and costs, including synergies;

 

   

the inability to successfully integrate the businesses we acquire;

 

   

the inability to hire, train or retain qualified personnel to manage and operate our business and newly acquired assets;

 

   

the assumption of unknown liabilities;

 

   

limitations on rights to indemnity from the seller;

 

   

mistaken assumptions about the overall costs of equity or debt;

 

   

the diversion of management’s attention from other business concerns;

 

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unforeseen difficulties in connection with operating in new product areas or new geographic areas; and

 

   

customer or key employee losses at the acquired businesses.

If we consummate any future acquisitions, our capitalization and results of operations may change significantly, and unitholders will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of our funds and other resources.

A terrorist attack or armed conflict could harm our business.

Terrorist activities, anti-terrorist efforts and other armed conflicts involving the U.S., whether or not targeted at our assets or the assets of our customers, could adversely affect the U.S. and global economies and could prevent us from meeting financial and other obligations. We could experience loss of business, delays or defaults in payments from customers or disruptions of fuel supplies and markets if domestic and global utilities are direct targets or indirect casualties of an act of terror or war. Terrorist activities and the threat of potential terrorist activities and any resulting economic downturn could adversely affect our results of operations, impair our ability to raise capital or otherwise adversely impact our ability to realize certain business strategies.

A failure in Columbia OpCo’s computer systems or a cyber-attack on any of its facilities or any third parties’ facilities upon which Columbia OpCo relies may adversely affect its ability to operate.

Columbia OpCo relies on technology to run its businesses, which depend on financial and operational computer systems to process information critically important for conducting various elements of its business, including the generation, transmission and distribution of electricity, operation of its gas pipelines and storage facilities and the recording and reporting of commercial and financial transactions to regulators, investors and other stakeholders. Any failure of Columbia OpCo’s computer systems, or those of its customers, suppliers or others with whom it does business, could materially disrupt Columbia OpCo’s ability to operate its businesses and could result in a financial loss and possibly do harm to Columbia OpCo’s reputation.

Additionally, Columbia OpCo’s information systems experience ongoing, often sophisticated, cyber-attacks by a variety of sources with the apparent aim to breach Columbia OpCo’s cyber-defenses. Although Columbia OpCo attempts to maintain adequate defenses to these attacks and works through industry groups and trade associations to identify common threats and assess Columbia OpCo’s countermeasures, a security breach of Columbia OpCo’s information systems could (i) impact the reliability of Columbia OpCo’s transmission and storage systems and potentially negatively impact Columbia OpCo’s compliance with certain mandatory reliability standards, (ii) subject Columbia OpCo to harm associated with theft or inappropriate release of certain types of information such as system operating information, personal or otherwise, relating to Columbia OpCo’s customers or employees or (iii) impact Columbia OpCo’s ability to manage its businesses.

Sustained extreme weather conditions and climate change may negatively impact Columbia OpCo’s operations.

Columbia OpCo conducts its operations across a wide geographic area subject to varied and potentially extreme weather conditions, which may from time to time persist for sustained periods of time. Despite preventative maintenance efforts, persistent weather related stress on Columbia OpCo’s infrastructure may reveal weaknesses in its systems not previously known to it or otherwise present various operational challenges across all business segments. Although Columbia OpCo makes every effort to plan for weather related contingencies, adverse weather may affect its ability to conduct operations in a manner that satisfies customer expectations or contractual obligations. Columbia OpCo endeavors to minimize such service disruptions, but may not be able to avoid them altogether.

There is also a concern that climate change may exacerbate the risks to physical infrastructure arising from significant physical effects, such as increased severity and frequency of storms, droughts and floods as well as

 

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associated with heat and other extreme weather conditions. Climate change and the costs that may be associated with its impacts have the potential to affect Columbia OpCo’s business in many ways, including increasing the cost Columbia OpCo incurs in providing its products and services, impacting the demand for and consumption of its products and services (due to change in both costs and weather patterns), and affecting the economic health of the regions in which Columbia OpCo operates.

Growing competition in the gas transportation and storage industries could result in the failure by customers to renew existing contracts.

As a consequence of the increase in competition and the shift in natural gas production areas, customers such as LDCs and other end users may be reluctant to enter into long-term service contracts. The renewal or replacement of existing contracts with Columbia OpCo’s customers at rates sufficient to maintain current or projected revenues and cash flows depends on a number of factors beyond its control, including competition from other pipelines and gatherers, the proximity of supplies to the markets, and the price of, and demand for, natural gas. The inability of Columbia OpCo to renew or replace its current contracts as they expire and respond appropriately to changing market conditions could materially impact its financial results and cash flows.

Failure to retain and attract key executive officers and other skilled professional and technical employees could have an adverse impact on Columbia OpCo’s operations.

Our business is dependent on CEG’s and our general partner’s ability to attract, retain and motivate employees. Competition for skilled employees in some areas is high and CEG and our general partner may experience difficulty in recruiting and retaining employees in light of the proposed spin-off. The inability to recruit and retain these employees could adversely affect our business and future operating results. CEG seeks to mitigate some of this risk by training its management on how to attract and select the needed talent and also measures its level of employee engagement annually, developing action plans where necessary to improve CEG’s workplace, but there is no assurance that such mitigation measures will be effective.

Columbia OpCo’s insurance policies do not cover all losses, costs or liabilities that it may experience, and insurance companies that currently insure companies in the energy industry may cease to do so or substantially increase premiums.

Columbia OpCo’s assets are insured at the entity level for certain property damage, business interruption and third-party liabilities, which includes pollution liabilities. All of the insurance policies relating to Columbia OpCo’s assets and operations are subject to policy limits. In addition, the waiting period under the business interruption insurance policies ranges from 30 to 45 days. Columbia OpCo does not maintain insurance coverage against all potential losses and could suffer losses for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. Changes in the insurance markets subsequent to the September 11, 2001 terrorist attacks and Hurricanes Katrina, Rita, Gustav and Ike have made it more difficult and more expensive to obtain certain types of coverage, and Columbia OpCo may elect to self-insure portions of its asset portfolio. The occurrence of an event that is not fully covered by insurance, or failure by one or more insurers to honor its coverage commitments for an insured event, could have a material adverse effect on Columbia OpCo’s business, financial condition and results of operations. Insurance companies may reduce the insurance capacity they are willing to offer or may demand significantly higher premiums to cover Columbia OpCo’s assets and operations. If significant changes in the number or financial solvency of insurance underwriters for the energy industry occur, Columbia OpCo may be unable to obtain and maintain adequate insurance at a reasonable cost. The unavailability of full insurance coverage to cover events in which Columbia OpCo suffers significant losses could have a material adverse effect on our business, financial condition and results of operation, and therefore on our ability to pay cash distributions.

 

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Risks Inherent in an Investment in Us

Our sponsor 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 our sponsor, have limited duties and may have conflicts of interest with us, and they may favor their own interests to our detriment and that of our unitholders.

Following the offering, our sponsor 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 us in a manner that it believes is not adverse to our interest, the executive officers and directors of our general partner have a fiduciary duty to manage our general partner in a manner beneficial to our sponsor. Therefore, conflicts of interest may arise between our sponsor or any of its affiliates, including our general partner, on the one hand, and us or any of our 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:

 

   

our general partner is allowed to take into account the interests of parties other than us, such as our sponsor, in exercising certain rights under our partnership agreement;

 

   

neither our partnership agreement nor any other agreement requires our sponsor to pursue a business strategy that favors us;

 

   

our partnership agreement replaces the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing its duties, limits our general partner’s liabilities and restricts the remedies available to our unitholders for actions that, without such limitations, might constitute breaches of fiduciary duties;

 

   

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

 

   

our general partner determines the amount and timing of asset purchases and sales, borrowings, issuances of additional partnership securities and the level of reserves, each of which can affect the amount of cash that is distributed to our unitholders;

 

   

our general partner determines the amount and timing of any cash expenditure and whether an expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus. Please read “How We Make Distributions to Our Partners—Capital Expenditures” for a discussion of when a capital expenditure constitutes a maintenance capital expenditure or an expansion capital expenditure. This determination can affect the amount of cash from operating surplus that is distributed to our unitholders which, in turn, may affect the ability of the subordinated units to convert into common units. Please read “How We Make Distributions to Our Partners—Subordination Period”;

 

   

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 a distribution on the subordinated units, to make incentive distributions or to accelerate the expiration of the subordination period;

 

   

in determining whether to request a guarantee from Columbia OpCo, HoldCo may elect to act in a manner that protects HoldCo’s credit rating or credit availability to our detriment or to the detriment of Columbia OpCo, or may take actions that increase the risk that HoldCo would default on its debt obligations and therefore increase the likelihood that the Columbia OpCo guarantee would be called on.

 

   

our partnership agreement permits us to distribute up to $62 million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus. This cash may be used to fund distributions on our subordinated units or the incentive distribution rights;

 

   

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

 

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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 may exercise its right to call and purchase common units if it and its affiliates own more than 80% of the common units;

 

   

our general partner controls the enforcement of obligations that it and its affiliates owe to us;

 

   

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

 

   

CEG may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to CEG’s incentive distribution rights without the approval of the conflicts committee of the board of directors of our general partner or the unitholders. This election may result in lower distributions to the common unitholders in certain situations.

In addition, we may compete directly with our sponsor and entities in which it has an interest for acquisition opportunities and potentially will compete with these entities for new business or extensions of the existing services provided by us. Please read “—Our sponsor and other affiliates of our general partner may compete with us” and “Conflicts of Interest and Fiduciary Duties.”

The board of directors of our general partner may modify or revoke our cash distribution policy at any time at its discretion. Our partnership agreement does not require us to pay any distributions at all.

The board of directors of our general partner will adopt a cash distribution policy pursuant to which we intend to distribute quarterly at least $0.1675 per unit on all of our units to the extent we have sufficient cash after the establishment of cash reserves and the payment of our expenses, including payments to our general partner and its affiliates. However, the board may change such policy at any time at its discretion and could elect not to pay distributions for one or more quarters. Please read “Cash Distribution Policy and Restrictions on Distributions.”

In addition, our partnership agreement does not require us to pay any distributions at all. Accordingly, investors are cautioned not to place undue reliance on the permanence of such a policy in making an investment decision. Any modification or revocation of our cash distribution policy could substantially reduce or eliminate the amounts of distributions to our unitholders. The amount of distributions we make, if any, and the decision to make any distribution at all will be determined by the board of directors of our general partner, whose interests may differ from those of our common unitholders. Our general partner has limited duties to our unitholders, which may permit it to favor its own interests or the interests of our sponsor to the detriment of our common unitholders.

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

Our general partner intends to limit its liability under contractual arrangements between us and third parties 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 unitholders.

 

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We expect to distribute a significant portion of our cash available for distribution to our partners, which could limit our ability to grow and make acquisitions.

We plan to distribute most of our cash available for distribution, which may cause our growth to proceed at a slower pace than that of businesses that reinvest their cash to expand ongoing operations. To the extent we issue additional common units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are 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 strategy would result in increased interest expense, which, in turn, may impact the cash that we have available to distribute to our unitholders.

If you are not an Eligible Holder, your common units may be subject to redemption.

We have adopted certain requirements regarding those investors who may own our common and subordinated units. Eligible Holders are limited partners or types of limited partners (a) whose, or whose owners’, U.S. federal income tax status does not, in the determination of our general partner, create or is not reasonably likely to create substantial risk of an adverse effect on the rates that can be charged by us on assets that are subject to regulation by FERC or a similar regulatory body, as determined by our general partner with the advice of counsel or (b) whose nationality, citizenship or other related status would not, in the determination of the General Partner, create a substantial risk of cancellation or forfeiture of any property in which we have an interest, as determined by our general partner with the advice of counsel. If you are not an Eligible Holder, in certain circumstances as set forth in our partnership agreement, your units may be redeemed by us at the then-current market price. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner. Please read “The Partnership Agreement—Ineligible Holders; Redemption.”

Our partnership agreement replaces our general partner’s fiduciary duties to us and holders of our units.

Our partnership agreement contains provisions that eliminate and replace the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner, or otherwise free of fiduciary duties to us and our 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 call right;

 

   

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

 

   

whether to exercise its registration rights;

 

   

whether to elect to reset target distribution levels; and

 

   

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

By purchasing a common unit, a unitholder is treated as having consented to the provisions in the partnership agreement, including the provisions discussed above. Please read “Conflicts of Interest and Fiduciary Duties—Fiduciary Duties.”

 

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Our partnership agreement restricts the remedies available to us and holders of our units 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 unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our partnership agreement provides that:

 

   

whenever our general partner makes a determination or takes, or declines to take, any other action in its capacity as our general partner, our general partner is generally required to make such determination, or take or decline to take such other action, not in bad faith, meaning that they did not believe that the decision was adverse to the interest of the partnership 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;

 

   

our general partner and its officers and directors will not be liable for monetary damages or otherwise to us or our limited partners resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that such losses or liabilities were the result of conduct in which our general partner or its officers or directors engaged in bad faith, meaning that they believed that the decision was adverse to the interest of the partnership, or engaged in willful misconduct or fraud or, with respect to any criminal conduct, with knowledge that such conduct was unlawful; and

 

   

our general partner will not be in breach of its obligations under the partnership agreement or its duties to us or our limited partners if a transaction with an affiliate or the resolution of a 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 and its affiliates.

In connection with a situation involving a transaction with an affiliate or a conflict of interest, other than one where our general partner is permitted to act in its sole discretion, any determination by our general partner must not be made in bad 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. Any matters approved by the conflicts committee will be conclusively deemed approved by all of our partners and not a breach by our general partner of any duties it may owe us or our common unitholders. Please read “Conflicts of Interest and Fiduciary Duties.”

Our sponsor 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, engaging in activities incidental to its ownership interest in us and providing management, advisory, and administrative services to its affiliates or to other persons. However, affiliates of our general partner, including our sponsor, are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us. In addition, our sponsor may compete with us for investment opportunities and 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 our sponsor. 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

 

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opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. This may create actual and potential conflicts of interest between us and affiliates of our general partner and result in less than favorable treatment of us and our unitholders. Please read “Conflicts of Interest and Fiduciary Duties.”

CEG may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to its incentive distribution rights, without the approval of the conflicts committee of its board of directors or the holders of our common units. This could result in lower distributions to holders of our common units.

CEG has the right, as the initial holder of our incentive distribution rights, at any time when there are no subordinated units outstanding and we have made cash distributions in excess of the then-applicable third target distribution for each of the prior four consecutive fiscal quarters and the aggregate amount of cash distributions during such four-quarter period does exceed adjusted operating surplus generated during such four-quarter period, to reset the initial target distribution levels at higher levels based on our distributions at the time of the exercise of the reset election. Following a reset election, a baseline distribution amount will be calculated equal to an amount equal to the prior cash distribution per common unit for the fiscal quarter immediately preceding the reset election (such amount is referred to as the “reset minimum quarterly distribution”) and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution.

If CEG elects to reset the target distribution levels, it will be entitled to receive a number of common units. The number of common units to be issued to CEG will equal the number of common units that would have entitled the holder to an aggregate quarterly cash distribution for the quarter prior to the reset election equal to the distribution on the incentive distribution rights for the quarter prior to the reset election. We anticipate that CEG would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion. It is possible, however, that CEG 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 target distribution levels. This risk could be elevated if our incentive distribution rights are transferred to a third party. 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 in connection with resetting the target distribution levels. CEG may transfer all or a portion of the incentive distribution rights in the future. After any such transfer, the holder or holders of a majority of our incentive distribution rights will be entitled to exercise the right to reset the target distribution levels. Please read “How We Make Distributions to Our Partners—IDR Holders’ Right to Reset Incentive Distribution Levels.”

Our partnership agreement will designate the Court of Chancery of the State of Delaware as the exclusive forum for certain types of actions and proceedings that may be initiated by our unitholders, which would limit our unitholders’ ability to choose the judicial forum for disputes with us or our general partner’s directors, officers or other employees. Our partnership agreement also provides that any unitholder bringing an unsuccessful action will be obligated to reimburse us for any costs we have incurred in connection with such unsuccessful action.

Our partnership agreement will provide that, with certain limited exceptions, the Court of Chancery of the State of Delaware will be the exclusive forum for any claims, suits, actions or proceedings (1) arising out of or relating in any way to our partnership agreement (including any claims, suits or actions to interpret, apply or enforce the provisions of our partnership agreement or the duties, obligations or liabilities among limited partners or of limited partners to us, or the rights or powers of, or restrictions on, the limited partners or us), (2) brought in a derivative manner on our behalf, (3) asserting a claim of breach of a duty owed by any director, officer or other employee of our general partner, or owed by our general partner, to us or the limited partners, (4) asserting a claim

 

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arising pursuant to any provision of the Delaware Revised Uniform Limited Partnership Act (the “Delaware Act”) or (5) asserting a claim against us governed by the internal affairs doctrine. In addition, if any unitholder brings any of the aforementioned claims, suits, actions or proceedings and such person does not obtain a judgment on the merits that substantially achieves, in substance and amount, the full remedy sought, then such person shall be obligated to reimburse us and our affiliates for all fees, costs and expenses of every kind and description, including but not limited to all reasonable attorneys’ fees and other litigation expenses, that the parties may incur in connection with such claim, suit, action or proceeding. By purchasing a common unit, a unitholder is irrevocably consenting to these limitations, provisions and potential reimbursement obligations regarding claims, suits, actions or proceedings and submitting to the exclusive jurisdiction of the Court of Chancery of the State of Delaware (or such other court) in connection with any such claims, suits, actions or proceedings. These provisions may have the effect of discouraging lawsuits against us and our general partner’s directors and officers. For additional information about the exclusive forum provision of our partnership agreement and the potential obligation to reimburse us for all fees, costs and expenses incurred in connection with claims, suits, actions or proceedings initiated by a unitholder that are not successful, please read “The Partnership Agreement—Applicable Law; Forum, Venue and Exclusive Jurisdiction; Reimbursement of Litigation Costs.”

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.

Compared to the holders of common stock in a corporation, unitholders have limited voting rights and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders will have no right on an annual or ongoing basis to elect our general partner or its board of directors. The board of directors of our general partner, including the independent directors, is chosen entirely by our sponsor, as a result of it owning our general partner, and not by our unitholders. Please read “Management—Management of Columbia Pipeline Partners LP” and “Certain Relationships and Related Party Transactions.” Unlike publicly traded corporations, we will not conduct annual meetings of our 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 unitholders are dissatisfied with the performance of our general partner, they will have limited ability to remove our general partner. Unitholders initially will be unable to remove our general partner without its consent because our general partner and its affiliates 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 outstanding common and subordinated units voting together as a single class is required to remove our general partner. Following the closing of this offering, our sponsor will own an aggregate of 57.3% of our common and subordinated units (or 53.8% of our common and subordinated units, if the underwriters exercise their option to purchase additional common units in full). In addition, any vote to remove our general partner during the subordination period must provide for the election of a successor general partner by the holders of a majority of the common units and a majority of the subordinated units, voting as separate classes. This will provide our sponsor the ability to prevent the removal of our general partner.

Unitholders will experience immediate and substantial dilution of $11.86 per common unit.

The assumed initial public offering price of $20.00 per common unit (the mid-point of the price range set forth on the cover page of this prospectus) exceeds our pro forma net tangible book value of $8.14 per common unit. Based on the assumed initial public offering price of $20.00 per common unit, unitholders will incur immediate and substantial dilution of $11.86 per common unit. This dilution results primarily because the assets contributed to us by affiliates of our general partner are recorded at their historical cost in accordance with GAAP, and not their fair value. Please read “Dilution.”

 

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Our general partner interest or the control of our general partner may be transferred to a third party without unitholder consent.

Our general partner may transfer its general partner interest to a third party without the consent of our unitholders. Furthermore, our partnership agreement does not restrict the ability of the owner of our general partner to transfer its membership interests in our general partner to a third party. The new owner of our general partner would then be in a position to replace the board of directors and executive officers of our general partner with its own 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 unitholders.

The incentive distribution rights may be transferred to a third party without unitholder consent.

CEG may transfer the incentive distribution rights to a third party at any time without the consent of our unitholders. If CEG transfers the incentive distribution rights to a third party, CEG would not have the same incentive to grow our partnership and increase quarterly distributions to unitholders over time. For example, a transfer of incentive distribution rights by CEG could reduce the likelihood of it accepting offers made by us relating to assets owned by CEG, as it would have less of an economic incentive to grow our business, which in turn would impact our ability to grow our asset base.

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 80% of the common units, our general partner will have the right, which it may assign to any of its affiliates or to us, but not the obligation, 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 price of the common units over the 20 trading days preceding the date three days before notice of exercise of the call right is first mailed and (2) the highest per-unit price paid by our general partner or any of its affiliates for common units during the 90-day period preceding the date such notice is first 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 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 causing us to issue additional common units and then 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 Securities Exchange Act of 1934, as amended (the “Exchange Act”). Upon completion of this offering, and assuming no exercise of the underwriters’ option to purchase additional common units, our sponsor will own an aggregate of 57.3% of our common and subordinated units. At the end of the subordination period, assuming no additional issuances of units (other than upon the conversion of the subordinated units), our sponsor will own 57.3% 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 unitholder approval, which would dilute existing 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 unitholders. The issuance of additional common units or other equity interests of equal or senior rank will have the following effects:

 

   

our existing unitholders’ proportionate ownership interest in us will decrease;

 

   

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

 

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because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;

 

   

the ratio of taxable income to distributions may increase;

 

   

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

 

   

the market price of the common units may decline.

There are no limitations in our partnership agreement on our ability to issue units ranking senior to the common units.

In accordance with Delaware law and the provisions of our partnership agreement, we may issue additional partnership interests that are senior to the common units in right of distribution, liquidation and voting. The issuance by us of units of senior rank may (i) reduce or eliminate the amount of cash available for distribution to our common unitholders; (ii) diminish the relative voting strength of the total common units outstanding as a class; or (iii) subordinate the claims of the common unitholders to our assets in the event of our liquidation.

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 our sponsor or other large holders.

After this offering, we will have 46,811,398 common units and 46,811,398 subordinated units outstanding, which includes the 40,000,000 common units we are selling in this offering that may be resold immediately in the public market. All of the subordinated units will convert into common units on a one-for-one basis at the end of the subordination period. All of the 6,811,398 common units that are issued to our sponsor 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 by our sponsor or other large holders of a substantial number of our common units 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 our sponsor. 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.

Our general partner’s discretion in establishing cash reserves may reduce the amount of cash we have available to distribute to unitholders.

Our partnership agreement requires our general partner to deduct from operating surplus the cash reserves that it determines are necessary to fund our future operating expenditures. In addition, the partnership agreement permits the general partner to reduce available cash by establishing cash reserves for the proper conduct of our business, to comply with applicable law or agreements to which we are a party or to provide funds for future distributions to partners. These cash reserves will affect the amount of cash we have available to distribute to unitholders.

 

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Cost 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 unitholders. The amount and timing of such reimbursements will be determined by our general partner.

We are obligated under our partnership agreement to reimburse our general partner and its affiliates for all expenses they incur and payments they make on our behalf. Our partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our partnership agreement provides that our general partner will determine 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 cash available for distribution to our unitholders. Please read “Cash Distribution Policy and Restrictions on Distributions.”

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 unitholders could lose all or part of their investment.

Prior to this offering, there has been no public market for the common units. After this offering, there will be only 40,000,000 publicly traded common units. We do not know the extent to which investor interest will lead to the development of a trading market or how liquid that market might be. Unitholders may not be able to resell their common units at or above the initial public offering price. Additionally, the lack of liquidity may result in wide bid-ask spreads, contribute to significant fluctuations in the market price of the common units and limit the number of investors who are able to buy the common units.

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

 

   

our quarterly distributions;

 

   

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

 

   

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

 

   

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

 

   

general economic conditions;

 

   

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

 

   

future sales of our common units; and

 

   

the other factors described in these “Risk Factors.”

Unitholders’ liability may not be limited if a court finds that unitholder action constitutes control of our business.

A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law, and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. A unitholder could be liable for any and all of our obligations as if a unitholder were a general partner if a court or government agency

 

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were to determine that (i) we were conducting business in a state but had not complied with that particular state’s partnership statute; or (ii) a unitholder’s right to act with other unitholders to remove or replace our general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business. For a discussion of the implications of the limitations of liability on a unitholder, please read “The Partnership Agreement—Limited Liability.”

Unitholders may have liability to repay distributions that were wrongfully distributed to them.

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Act we may not make a distribution to our 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. 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.

If we fail to establish and maintain effective internal control over financial reporting, our ability to accurately report our financial results could be adversely affected.

We are not currently required to comply with the SEC’s rules implementing Section 404 of the Sarbanes Oxley Act of 2002, and are therefore not required to make a formal assessment of the effectiveness of our internal control over financial reporting for that purpose. Upon becoming a publicly traded partnership, we will be required to comply with the SEC’s rules implementing Sections 302 and 404 of the Sarbanes Oxley Act of 2002, which will require our management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of our internal control over financial reporting. Though we will be required to disclose material changes made to our internal controls and procedures on a quarterly basis, we will not be required to make our first annual assessment of our internal control over financial reporting pursuant to Section 404 until the year following our first annual report required to be filed with the SEC. To comply with the requirements of being a publicly traded partnership, we will need to implement additional internal controls, reporting systems and procedures and hire additional accounting, finance and legal staff.

If we fail to develop or maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential unitholders could lose confidence in our financial reporting, which would harm our business and the trading price of our units.

Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We cannot be certain that our efforts to develop and maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations under Section 404 of the Sarbanes Oxley Act of 2002. Any failure to develop or maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our units.

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

We have applied to list our common units on the NYSE. Because we will be a publicly traded partnership, the NYSE does not require us to have a majority of independent directors on our general partner’s board of directors or to establish a compensation committee or a nominating and corporate governance committee. Accordingly,

 

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unitholders will not have the same protections afforded to certain corporations that are subject to all of the NYSE corporate governance requirements. Please read “Management—Management of Columbia Pipeline Partners LP.”

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, 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. The amount of our expenses or reserves for expenses, including the costs of being a publicly traded partnership, will reduce the amount of cash we have for distribution to our unitholders. As a result, the amount of cash we have available for distribution to our unitholders will be affected by the costs associated with being a public company.

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 also expect to incur significant expense in order to obtain director and officer liability insurance. Because of the limitations in coverage for directors, it may be more difficult for us to attract and retain qualified persons to serve on the board of directors of our general partner or as executive officers.

We estimate that we will incur approximately $5 million of incremental costs per year associated with being a publicly traded partnership; however, it is possible that our actual incremental costs of being a publicly traded partnership will be higher than we currently estimate.

Tax Risks to Common Unitholders

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

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as us not being subject to a material amount of entity-level taxation by individual states. If the IRS were to treat us as a corporation for federal income tax purposes, or we become subject to entity-level taxation for state tax purposes, 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.

Despite the fact that we are organized as a limited partnership under Delaware law, we will be treated as a corporation for U.S. federal income tax purposes unless we satisfy a “qualifying income” requirement. Based upon our current operations, we believe we satisfy the qualifying income requirement. However, we have not requested, and do not plan to request, a ruling from the IRS on this or any other matter affecting us. Failing to meet the qualifying income requirement or a change in current law could cause us to be treated as a corporation for U.S. federal income tax purposes or otherwise subject us to taxation as an entity.

If we were treated as a corporation for federal income tax purposes, we would pay U.S. federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%. Distributions to you

 

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would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution to you would be substantially reduced. In addition, 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 the cash available for distribution to you. Therefore, treatment of us as a corporation or the assessment of a material amount of entity-level taxation would result in a material reduction in the anticipated cash flow and after-tax return to the unitholders, likely causing a substantial reduction in the value of our common units.

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

The tax treatment of publicly traded partnerships or an investment in our units could be subject to potential legislative, judicial or administrative changes or differing interpretations, possibly applied 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 changes or differing interpretations at any time. For example, from time to time, members of Congress propose and consider substantive changes to the existing U.S. federal income tax laws that affect publicly traded partnerships. One such legislative proposal would have eliminated the qualifying income exception to the treatment of all publicly traded partnerships as corporations upon which we rely for our treatment as a partnership for U.S. federal income tax purposes. 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. Any modification to U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible for us to meet the qualifying income requirement to be treated as a partnership for U.S. federal income tax purposes. For a discussion of the importance of our treatment as a partnership for federal income purposes, please read “Material U.S. Federal Income Tax Consequences—Taxation of the Partnership—Partnership Status” for a further discussion.

If the IRS were to contest the federal income tax positions we take, it may adversely impact the market for our common units, and the costs of any such contest would reduce our cash available for distribution to our unitholders.

The IRS may adopt positions that differ from the conclusions of our counsel expressed in this prospectus or from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel’s conclusions or the positions we take. A court may not agree with some or all of our counsel’s conclusions or 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. Moreover, the costs of any contest between us and the IRS will result in a reduction in our cash available for distribution to our unitholders and thus will be borne indirectly by our unitholders.

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

You will be required to pay 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 due from you with respect to that income.

 

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Tax gain or loss on 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 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 our 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 (known as 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 subject to withholding taxes imposed at the highest effective tax rate applicable to such non-U.S. persons, and each non-U.S. person 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.

We will treat each purchaser of 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.

Because we cannot match transferors and transferees of common units, and for other reasons, 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 adopted.

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 unitholders.

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

 

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deduction among our unitholders. Please read “Material U.S. Federal Income Tax Consequences—Disposition of Units—Allocations Between Transferors and Transferees.”

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

Because there are no specific rules governing the U.S. federal income tax consequence of loaning a partnership interest, a unitholder whose units are the subject of a securities loan may be considered as having disposed of the loaned units. In that case, the unitholder may no longer be treated for tax purposes as a partner with respect to those 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, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a securities loan are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.

We may adopt certain valuation methodologies that could result in a shift of income, gain, loss and deduction between the general partner and the unitholders. The IRS may challenge this treatment, which could adversely affect the value of the common units.

When we issue additional units or engage in certain other transactions, we will determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and the general partner, which may be unfavorable to such unitholders. Moreover, under our valuation methods, subsequent purchasers of common units may have a greater portion of their Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain, loss and deduction between the general partner and certain of our unitholders.

A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.

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 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, CEG will indirectly own 57.3% of the total interests in our capital and profits. Therefore, a transfer by CEG of all or a portion of its interests in us could, in conjunction with the trading of common units held by the public, result in a termination of our partnership for federal income tax purposes. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest will be counted only once.

Our termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns for one calendar year and could result in a significant deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a calendar year, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in taxable income for the unitholder’s taxable year that

 

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includes our termination. Our termination would not affect our classification as a partnership for federal income tax purposes, but it would result in our being treated as a new partnership for U.S. federal income tax purposes following the termination. If we were treated as a new partnership, we would be required to make new tax elections and could be subject to penalties if we were unable to determine that a termination occurred. The IRS recently announced a relief procedure whereby if a publicly traded partnership that has technically terminated requests and the IRS grants special relief, among other things, the partnership may be permitted to provide only a single Schedule K-1 to unitholders for the two short tax periods included in the year in which the termination occurs. 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.

You will likely be subject to state and local taxes and income tax return filing requirements in jurisdictions 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 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. We will initially own assets and conduct business in several states, each of which currently imposes a personal income tax and also imposes income taxes on corporations and other entities. You may be required to file state and local income tax returns and pay state and local income taxes in these states. Further, you may be subject to penalties for failure to comply with those requirements. 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 $755.0 million from this offering (based on an assumed initial offering price of $20.00 per common unit, the mid-point of the price range set forth on the cover page of this prospectus), after deducting the estimated underwriting discount, the structuring fee of $4.0 million paid to Barclays Capital Inc. and Citigroup Global Markets Inc., and offering expenses, to purchase an additional approximate 6.2% limited partner interest in Columbia OpCo. The approximate 6.2% interest in Columbia OpCo purchased with the proceeds from this offering, when combined with an approximate 8.4% interest in Columbia OpCo contributed to us in connection with the formation transactions, will result in our ownership of a 14.6% limited partner interest in Columbia OpCo following the closing of the offering.

Columbia OpCo will use $500.0 million of the net proceeds it receives from us to make a distribution to CEG as a reimbursement of preformation capital expenditures with respect to the assets contributed to Columbia OpCo and the remaining proceeds it receives from us to fund expansion capital expenditures. We would expect the remaining net proceeds of $255.0 million to be completely utilized during the twelve months ended December 31, 2015, for these purposes.

If the underwriters exercise their option to purchase 6,000,000 additional common units in full, the additional net proceeds would be approximately $114.0 million (based upon the mid-point of the price range set forth on the cover page of this prospectus). The net proceeds from any exercise of such option will be used to purchase an additional percentage limited partner interest in Columbia OpCo, and Columbia OpCo will use such cash to fund growth projects and for general partnership purposes. The amount of the additional interest in Columbia OpCo purchased will depend on the number of common units issued pursuant to the exercise of such option, and will be calculated at approximately 0.16% additional limited partner interest in Columbia OpCo purchased for each one million of additional common units purchased by the underwriters. If the underwriters exercise their option to purchase additional common units in full, we would purchase an additional 1.0% limited partner interest in Columbia OpCo and our total ownership interest in Columbia OpCo would be 15.6%.

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 discount, structuring fee and offering expenses payable by us, to increase or decrease, respectively, by approximately $38.0 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 concomitant $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 $57.9 million. Similarly, each decrease of 1.0 million common units offered by us, together with a concomitant $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 $56.1 million. If we increase or decrease the number of common units offered, we will proportionately increase or decrease, respectively, the percentage interest in Columbia OpCo which we will purchase with the net proceeds of this offering. Columbia OpCo may concomitantly increase or reduce, as applicable, the amount of CEG reimbursement for capital expenditures. As a result, cash available for distribution per unit is expected to remain unchanged regardless of the changes in the number of common units offered.

 

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CAPITALIZATION

The following table shows our capitalization as of September 30, 2014:

 

   

on a historical basis for the Predecessor;

 

   

on a historical basis for the Predecessor, as adjusted to reflect the removal of amounts related to Crossroads Pipeline Company, Columbia Pipeline Group Services Company and Central Kentucky Transmission Company that were included in the Predecessor but are not being contributed to the Partnership, as well as the inclusion of CNS Microwave, Inc., which was not part of the Predecessor; and

 

   

on a pro forma basis to reflect the 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 combined 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, 2014  
    Predecessor
Historical
    Predecessor
Historical,

 As  Adjusted 
    Pro Forma  
    (in millions)  

Cash and cash equivalents

  $ 0.4      $ 0.3      $ 255.3   
 

 

 

   

 

 

   

 

 

 

Long-term debt—affiliated

  $ 1,370.9      $ 1,370.9      $ 511.6   

Parent net investment/partners’ net equity

     

Net parent investment

    4,122.3        4,113.0        —     

Accumulated other comprehensive loss

    (16.9     (17.0     —     

Common units—public(1)

    —          —          650.1   

Common units—CEG(1)

    —          —          50.8   

Subordinated units—CEG(1)

    —          —          349.4   

Noncontrolling interest(1)(2)

    —          —          5,643.4   

Total parent net investment/partners’ net equity

    4,105.4        4,096.0        6,693.7   
 

 

 

   

 

 

   

 

 

 

Total capitalization

  $ 5,476.3      $ 5,466.9      $ 7,205.3   
 

 

 

   

 

 

   

 

 

 

 

(1) 

Pro forma amounts reflect the capital attributable to our limited and general partners. Pro forma partners’ net equity reflects an increase of $1,127.9 million to eliminate certain historical current and deferred income taxes that will not be borne by the Partnership and an increase of $1,214.8 million for the assumption of debt by CEG. Pro forma partners’ net equity also assumes offering proceeds of $755.0 million, net of the underwriting discount, structuring fee and other expenses of the initial public offering of $36.0 million, $4.0 million and $5.0 million, respectively, all of which were allocated to the public common units. Pro forma partners’ net equity further reflects an increase of $540.9 million for the initial contribution from CEG for an approximate 8.4% interest in Columbia OpCo. Pro forma partners’ net equity also includes an adjustment of $245.6 million to the limited partner equity accounts for the excess of consideration paid by us to purchase our additional limited partner interest in Columbia OpCo with net proceeds from this offering over the historical carrying value of the additional interest. Pro forma partners’ net equity also gives effect to a $500.0 million decrease in the Noncontrolling interest of Columbia OpCo for the distribution to CEG for the reimbursement of preformation capital expenditures.

(2) 

Reflects the noncontrolling interest held by CEG in Columbia OpCo.

 

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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 mid-point of the price range set forth on the cover page of this prospectus), on a pro forma basis as of September 30, 2014, after giving effect to the offering of common units and the related transactions, our net tangible book value would have been approximately $761.9 million, or $8.14 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   

Predecessor historical as adjusted net tangible book value per common unit before the offering(1)

   $ 6.99     

Increase in net tangible book value per common unit attributable to the offering(2)

   $ 3.77     

Decrease in net tangible book value per common unit attributable to the excess of the consideration paid by us to purchase our additional limited partner interest in Columbia OpCo with the net proceeds from this offering over the historical carrying value of the additional interest acquired in Columbia OpCo’s net assets(3)

   $ (2.62  

Less: Pro forma net tangible book value per common unit after the offering(4)

     $ 8.14   
    

 

 

 

Immediate dilution in net tangible book value per common unit to purchasers in the offering(5)(6)

     $ 11.86   
    

 

 

 

 

(1) 

Determined by dividing the Predecessor historical as adjusted net tangible book value of the 8.4% limited partner interest in Columbia OpCo ($375.0 million) by the number of units (6,811,398 common units and 46,811,398 subordinated units) to be issued prior to the offering to CEG for its contribution of the 8.4% limited partner interest in Columbia OpCo to us. The Predecessor historical as adjusted net tangible book value of $375.0 million is determined by subtracting (A) $165.9 million (an 8.4% interest in the Predecessor’s $1,975.5 million of goodwill) from (B) $540.9 million (the book value of the 8.4% limited partner interest in Columbia OpCo that CEG contributes to the Partnership). For more information regarding the calculation of book value, please refer to Note 2(i) in the Notes to Unaudited Pro Forma Combined Financial Statements.

(2) 

Determined by adding the (A) pro forma net tangible book value per common unit after the offering ($8.14) to the (B) decrease in net tangible book value per common unit attributable to the excess consideration ($2.62) and subtracting (C) the Predecessor historical as adjusted net tangible book value per common unit before the offering ($6.99).

(3) 

Determined by dividing (A) the excess consideration paid by us to purchase the additional interest in Columbia OpCo of $245.6 million by (B) the total number of units outstanding after the offering (46,811,398 common units and 46,811,398 subordinated units). For more information regarding the calculation of the excess consideration, please refer to Note 2(l) in the Notes to Unaudited Pro Forma Combined Financial Statements.

(4) 

Determined by dividing our pro forma net tangible book value of $761.9 million, after giving effect to the use of proceeds of the offering, by the total number of units outstanding after the offering (46,811,398 common units and 46,811,398 subordinated units). The Partnership’s pro forma net tangible book value of $761.9 million is determined by subtracting (A) $288.4 million (a 14.6% interest in the Predecessor’s $1,975.5 million of goodwill) from (B) $1,050.3 million (the Partnership’s net book value after the offering). For more information regarding the calculation of book value, please refer to Note 2(l) in the Notes to Unaudited Pro Forma Combined Financial Statements.

(5) 

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 $38.0 million, or approximately $0.41 per common unit, and dilution per common unit to investors in this offering by approximately $0.59 per common unit, after deducting the estimated underwriting discount, structuring fee

 

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  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 concomitant $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 $819.2 million, or $8.75 per common unit, and dilution per common unit to investors in this offering would be $12.25 per common unit. Similarly, a decrease of 1.0 million common units offered by us, together with a concomitant $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 $705.0 million, or $7.53 per common unit, and dilution per common unit to investors in this offering would be $11.47 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.
(6) 

Assumes no exercise of the underwriters’ option to purchase additional common units from us. After giving effect to the full exercise of the underwriters’ option to purchase 6,000,000 additional common units from us, the pro forma net tangible book value per common unit after the offering would be $9.28, resulting in an immediate dilution in net tangible book value to purchasers in the offering of $10.72 per common unit.

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

 

     Units     Total Consideration  
     Number      Percent     Amount      Percent  
                  (in millions)         

CEG(1)(2)(3)

     53,622,796         57.3   $ 40.9         4.9

Purchasers in the offering(4)

     40,000,000         42.7   $ 800.0         95.1
  

 

 

    

 

 

   

 

 

    

 

 

 

Total

     93,622,796         100   $ 840.9         100
  

 

 

    

 

 

   

 

 

    

 

 

 

 

(1) 

Upon the completion of the transactions contemplated by this prospectus, CEG will own 6,811,398 common units and all 46,811,398 of our subordinated units.

(2) 

The assets contributed by CEG will be recorded at historical cost. The pro forma book value of the consideration provided by CEG as of September 30, 2014 would have been approximately $540.9 million.

(3)

Book value of the consideration provided by CEG, as of September 30, 2014, after giving effect to the net proceeds of the offering is as follows (in millions):

 

CEG’s initial contribution to us of certain limited partner interests and all of the general partner interests in Columbia OpCo(i)

   $ 540.9   

Less:

  

Distribution to CEG as a reimbursement of preformation capital expenditures(ii)

     (500.0
  

 

 

 

Total consideration

   $ 40.9   
  

 

 

 

 

  (i) Represents our proportionate limited partner interests in the historical carrying value of Columbia OpCo’s net assets prior to this offering.
  (ii) The distribution to CEG will be made from Columbia OpCo to CEG. This distribution will not impact the controlling interest equity of the Partnership.

 

(4) 

Assumes the underwriters’ option to purchase additional common units is not exercised.

 

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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 the specific assumptions included in this section. 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 Columbia Pipeline Partners LP Predecessor’s audited historical financial statements as of December 31, 2012 and 2013 and for the years ended December 31, 2011, 2012 and 2013 and to Columbia Pipeline Partners LP Predecessor’s unaudited financial statements as of and for the nine months ended September 30, 2014 and our unaudited pro forma combined financial statements for the year ended December 31, 2013 and as of and for the nine months ended September 30, 2014, included elsewhere in this prospectus.

General

Our Cash Distribution Policy

The board of directors of our general partner will adopt a cash distribution policy pursuant to which we intend to distribute at least the minimum quarterly distribution of $0.1675 per unit ($0.67 per unit on an annualized basis) on all of our units to the extent we have sufficient cash after the establishment of cash reserves and the payment of our expenses, including payments to our general partner and its affiliates. We expect that if we are successful in executing our business strategy, we will grow our business in a steady and sustainable manner and distribute to our unitholders a portion of any increase in our cash available for distribution resulting from such growth. Our general partner has not established any cash reserves, and does not have any specific types of expenses for which it intends to establish reserves. We expect our general partner may establish reserves for specific purposes, such as major capital expenditures or debt service payments, or may choose to generally reserve cash in the form of excess distribution coverage from time to time for the purpose of maintaining stability or growth in our quarterly distributions. In addition, our general partner may cause us to borrow amounts to fund distributions in quarters when we generate less cash than is necessary to sustain or grow our cash distributions per unit. Our cash distribution policy reflects a judgment that our unitholders will be better served by our distributing rather than retaining our cash available for distribution.

The board of directors of our general partner may change our distribution policy at any time and from time to time. Our partnership agreement does not require us to pay cash distributions on a quarterly or other basis.

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

There is no guarantee that we will make cash distributions to our unitholders. We do not have a legal or contractual obligation to pay quarterly distributions quarterly or on any other basis or at our minimum quarterly distribution rate or at any other rate. Our cash distribution policy is subject to certain restrictions, as well as the considerable discretion of our general partner in determining the amount of our available cash each quarter, and may be changed at any time. The reasons for such uncertainties in our stated cash distribution policy include the following factors:

 

   

Our cash flow initially will depend completely on Columbia OpCo’s distributions to us as one of its partners.

 

   

The amount of cash Columbia OpCo can distribute to its partners will depend upon the amount of cash it generates from operations less any reserves that may be appropriate for operating its business. Columbia OpCo’s ability to make cash distributions to us may be subject to restrictions on distributions under our credit facility and HoldCo’s credit facility, both of which Columbia OpCo will guarantee and may be subject to restrictions in any future HoldCo indebtedness that Columbia OpCo guarantees. If HoldCo were to default under future indebtedness, Columbia OpCo would be unable to make

 

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distributions to us. Please read “Risk Factors—Risks Inherent in Our Business—Columbia OpCo will be a restricted subsidiary and a guarantor under HoldCo’s credit facility and, if requested by HoldCo, will guarantee future HoldCo indebtedness. Such indebtedness could limit Columbia OpCo’s ability to take certain actions, including incurring indebtedness, making acquisitions and capital expenditures and making distributions to us, which could adversely affect our business, financial condition, results of operations, ability to make distributions to unitholders and value of our common units.”

 

   

Because we control Columbia OpCo’s general partner, we have the authority to determine the amount of Columbia OpCo’s distributions, including the amount of cash reserved by Columbia OpCo and not distributed. We have a duty to make decisions with respect to Columbia OpCo in the best interest of all of its partners, including CEG. Our decision to make distributions, if any, and the amount of those distributions, if any, could result in a reduction in cash distributions to our unitholders from levels we currently anticipate pursuant to our stated distribution policy.

 

   

Our cash distribution policy may be subject to restrictions on cash distributions under our new credit facility and any future debt agreements. Such restrictions may prohibit us from making cash distributions while an event of default has occurred and is continuing under our new credit facility, notwithstanding our cash distribution policy.

 

   

We expect to establish reserves for the prudent conduct of Columbia OpCo’s business (including reserves for working capital, maintenance capital expenditures, environmental matters, legal proceedings and other operating purposes). Our general partner will have the authority to establish cash reserves for the prudent conduct of our business, including for future cash distributions to our unitholders, and the establishment of or increase in 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.

 

   

We are obligated under our partnership agreement to reimburse our general partner and its affiliates for all expenses they incur on our behalf. Our partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our partnership agreement provides that our general partner will determine 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 cash available to pay distributions to our unitholders.

 

   

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.

 

   

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 unitholders due to cash flow shortfalls attributable to a number of operational, commercial or other factors as well as increases in our operating expenses or general and administrative expenses, principal and interest payments on our outstanding debt, tax expenses, working capital requirements and anticipated cash needs.

 

   

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 minimum quarterly distribution and the target distribution levels. Please read “How We Make Distributions to Our Partners—Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels.” We do not anticipate that we will make any distributions from capital surplus.

 

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Our Ability to Grow may be Dependent on Our Ability to Access External Expansion Capital

We expect to generally distribute a significant percentage of our cash from operations to our unitholders on a quarterly basis, after the establishment of cash reserves and payment of our expenses. Therefore, our growth may not be as fast as businesses that reinvest most or all of their cash to expand ongoing operations. Moreover, our future growth may be slower than our historical growth. We expect that we will rely primarily upon external financing sources, including borrowings from HoldCo, bank borrowings and issuances of debt and equity securities, to fund our expansion capital expenditures. To the extent we are unable to finance growth with external sources of capital, our current cash distribution policy will significantly impair our ability to grow. Our new credit facility will limit, and any future debt agreements may limit, our ability to incur additional debt, including through the issuance of debt securities. Please read “Risk Factors—Risks Inherent in Our Business—Restrictions in our new or any future credit facility could adversely affect our business, financial condition, results of operations, ability to make distributions to unitholders and value of our common units.” 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 cash distributions per unit. There are no limitations in our partnership agreement on our ability to issue additional units, including units ranking senior to our common units, and our unitholders will have no preemptive or other rights (solely as a result of their status as unitholders) to purchase any such additional units. If we incur additional debt to finance our growth strategy, we will have increased interest expense, which will in turn reduce the operating surplus that we have to distribute to our unitholders. Please read “Risk Factors—Risks Inherent in Our Business—Debt that we or Columbia OpCo incur in the future may limit our or Columbia OpCo’s flexibility to obtain additional financing and to pursue other business opportunities.”

Our Minimum Quarterly Distribution

Upon completion of this offering, our partnership agreement will provide for a minimum quarterly distribution of $0.1675 per unit for each whole quarter, or $0.67 per unit on an annualized basis. The payment of the full minimum quarterly distribution on all of the common units and subordinated units to be outstanding after completion of this offering would require us to have cash available for distribution of approximately $15.7 million per quarter, or $62.7 million per year. Our ability to make cash distributions at the minimum quarterly distribution rate will be subject to the factors described above under “—General—Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy.” The table below sets forth the amount of common units and subordinated units that will be outstanding immediately after this offering and the cash available for distribution needed to pay the aggregate minimum quarterly distribution on all of such units for a single fiscal quarter and a four quarter period (assuming no exercise and full exercise of the underwriters’ option to purchase additional common units):

 

     No exercise of option to purchase
additional common units
     Full exercise of option to purchase
additional common units
 
     Aggregate minimum quarterly
distributions
     Aggregate minimum quarterly
distributions
 
     Number of
Units
     One
Quarter
     Annualized      Number of
Units
     One
Quarter
     Annualized  

Publicly held common units

     40,000,000       $ 6,700,000       $ 26,800,000         46,000,000       $ 7,705,000       $ 30,820,000   

Common units held by CEG

     6,811,398         1,140,909         4,563,636         6,811,398         1,140,909         4,563,636   

Subordinated units held by CEG

     46,811,398         7,840,909         31,363,636         46,811,398         7,840,909         31,363,636   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

     93,622,796       $ 15,681,818       $ 62,727,272         99,622,796       $ 16,686,818       $ 66,747,272   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Our general partner will initially own a non-economic general partner interest in us, which will not entitle it to receive cash distributions. CEG will hold the incentive distribution rights, which entitle the holder to increasing percentages, up to a maximum of 50.0%, of the cash we distribute in excess of $0.192625 per unit per quarter.

 

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We expect to pay our distributions on or about the last day of each of February, May, August and November to holders of record on or about the 15th day of each such month in which such distributions are made. We will adjust the quarterly distribution for the period after the closing of this offering through March 31, 2015, based on the actual length of the period.

Subordinated Units

Our sponsor will initially own all of our subordinated units. The principal difference between our common units and subordinated units is that for any quarter during the subordination period, holders of the subordinated units are not entitled to receive any distribution from operating surplus until the common units have received the minimum quarterly distribution from operating surplus for such quarter plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. Subordinated units will not accrue arrearages. When the subordination period ends, all of the subordinated units will convert into an equal number of common units.

To the extent we do not pay the minimum quarterly distribution from operating surplus on our common units, our common unitholders will not be entitled to receive such payments in the future except during the subordination period. To the extent we have cash available for distribution from operating surplus in any future quarter during the subordination period in excess of the amount necessary to pay the minimum quarterly distribution to holders of our common units, we will use this excess cash to pay any distribution arrearages on common units related to prior quarters before any cash distribution is made to holders of subordinated units. Please read “How We Make Distributions to Our Partners—Subordination Period.”

Unaudited Pro Forma Cash Available for Distribution for the Year Ended December 31, 2013 and Twelve Months Ended September 30, 2014

If we had completed the transactions described under “Summary—Formation Transactions and Partnership Structure” on January 1, 2013, our pro forma cash available for distribution for the year ended December 31, 2013 would have been approximately $50.8 million. This amount would have been sufficient to pay the full minimum quarterly distribution on all of our common units and insufficient to pay the minimum quarterly distribution on our subordinated units for the year ended December 31, 2013 by approximately $11.9 million.

If we had completed the transactions described under “Summary—Formation Transactions and Partnership Structure” on October 1, 2013, our pro forma cash available for distribution for the twelve months ended September 30, 2014 would have been approximately $55.6 million. This amount would have been sufficient to pay the full minimum quarterly distribution on all of our common units and insufficient to pay the minimum quarterly distribution on our subordinated units for the twelve months ended September 30, 2014 by approximately $7.1 million.

The unaudited pro forma combined financial statements, upon which pro forma cash available for distribution is based, do not purport to present our results of operations had the transactions contemplated in this prospectus actually been completed as of the date indicated. Furthermore, cash available for distribution is a cash accounting concept, while our pro forma combined financial statements have been prepared on an accrual basis. We derived the amounts of pro forma cash available for distribution in the manner described in the table below. As a result, the amount of pro forma cash available for distribution should only be viewed as a general indication of the amount of cash available for distribution that we might have generated had we been formed in an earlier period.

Following the completion of this offering, we estimate that we will incur $5 million of incremental annual general and administrative expenses as a result of operating as a publicly traded partnership. These incremental general and administrative expenses are not reflected in our unaudited pro forma combined financial statements and consist of expenses such as those associated with annual and quarterly reporting, tax return and Schedule K-1 preparation and distribution expenses, Sarbanes-Oxley compliance expenses, expenses associated with listing on the NYSE, independent auditor fees, legal fees, investor relations expenses, registrar and transfer agent fees, director and officer insurance expenses and director and officer compensation expenses.

 

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Our unaudited pro forma combined financial statements are derived from the audited and unaudited historical financial statements of the Predecessor, included elsewhere in this prospectus. Our unaudited pro forma combined financial statements should be read together with “Selected Historical and Pro Forma Financial and Operating Data,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the audited and unaudited historical financial statements of the Predecessor and the notes to those statements included elsewhere in this prospectus.

The following table illustrates, on a pro forma basis for the year ended December 31, 2013 and for the twelve months ended September 30, 2014, the amount of cash that would have been available for distribution to our unitholders, assuming that the transactions described under “Summary—Formation Transactions and Partnership Structure” had been consummated on the beginning of such period. Certain of the adjustments reflected or presented below are explained in the footnotes to such adjustments. Certain components may not add or subtract to totals due to rounding.

Columbia Pipeline Partners LP

Unaudited Pro Forma Cash Available for Distribution

 

     Year Ended
December 31, 2013
    Twelve  Months
Ended

September 30, 2014
 
     (in millions)  

Operating revenues(1)

   $ 1,176.7      $ 1,326.7  

Operating expenses:

    

Operation and maintenance

     481.4        588.1  

Operation and maintenance—affiliated(2)

     142.5        153.4  

Depreciation and amortization

     106.1        115.0  

Gain on sale of assets(3)

     (18.6     (28.1 )

Property and other taxes

     61.9        65.6  
  

 

 

   

 

 

 

Total operating expenses

     773.3        894.0   
  

 

 

   

 

 

 

Equity earnings in unconsolidated affiliates(4)

     35.8        43.1   
  

 

 

   

 

 

 

Operating income

     439.2        475.8   
  

 

 

   

 

 

 

Interest expense—affiliated(5)

     (1.8     (6.1

Other, net(6)

     22.6        10.6   

Income taxes(7)

     (0.2     (0.2
  

 

 

   

 

 

 

Net income

     459.8        480.1   
  

 

 

   

 

 

 

Add:

    

Interest expense—affiliated(5)

     1.8        6.1   

Income taxes(7)

     0.2        0.2   

Depreciation and amortization

     106.1        115.0   

Cash distributions from unconsolidated affiliates

     32.1        40.7   

Less:

    

Other, net(6)

     22.6        10.6   

Equity earnings in unconsolidated affiliates(4)

     35.8        43.1   
  

 

 

   

 

 

 

Adjusted EBITDA

     541.6        588.4   
  

 

 

   

 

 

 

Less:

    

Cash interest, net(8)

     15.7        20.2   

Maintenance capital expenditures(9)

     131.7        141.1   

Expansion capital expenditures(10)

     658.9        715.8   

Add:

    

Borrowings from affiliates of CEG to fund expansion capital expenditures

     658.9        715.8   

Estimated cash available for distribution by Columbia OpCo

   $ 394.2      $ 427.1   
  

 

 

   

 

 

 

 

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     Year Ended
December 31, 2013
    Twelve  Months
Ended

September 30, 2014
 
     (in millions except per unit amount)  

Less:

    

Estimated cash available for distribution attributable to non-controlling interest in Columbia OpCo(11)

     336.6        364.7   

Cash interest(12)

     1.8        1.8  

Incremental general and administrative expenses(13)

     5.0        5.0   

Estimated cash available for distribution by Columbia Pipeline Partners LP

   $ 50.8      $ 55.6   
  

 

 

   

 

 

 

Minimum annual distribution per unit (based on a minimum quarterly distribution rate of $0.1675 per unit)

   $ 0.6700      $ 0.6700   

Cash distributions

    

Distributions to public common unitholders

   $ 26.8      $ 26.8   

Distributions to CEG:

    

Common units

     4.5        4.5   

Subordinated units

     31.4        31.4   
  

 

 

   

 

 

 

Total distributions to CEG

   $ 35.9      $ 35.9   
  

 

 

   

 

 

 

Total distributions to our unitholders at minimum rate

   $ 62.7      $ 62.7   

Shortfall($)

   $ (11.9   $ (7.1

% of Distributions to Subordinated Units that can be paid

     62.0     77.3

Subordinated Unit Distribution ($/Unit)

   $ 0.42      $ 0.52   

 

(1) 

Operating revenues include affiliate transactions with subsidiaries of CEG that total $148.2 million and $149.0 million for the year ended December 31, 2013 and the twelve months ended September 30, 2014, respectively.

(2) 

Represents executive, financial, legal, information technology and other administrative and general services received from an affiliate, NiSource Corporate Services. For more information, please refer to Note 3 “Transactions with Affiliates” in the audited Notes to Combined Financial Statements.

(3) 

Includes approximately $11.1 million in proceeds from sale of base gas and $7.3 million attributable to the conveyance of mineral rights leases for the year ended December 31, 2013 and approximately $28.1 million attributable to the conveyance of mineral rights leases for the twelve months ended September 30, 2014.

(4) 

Represents equity earnings from equity method investments in Millennium Pipeline, Hardy Storage and Pennant. For more information, please refer to Note 9 “Equity Method Investments” in the audited Notes to Combined Financial Statements.

(5) 

Interest expense—affiliated includes interest expense incurred by our Predecessor and the amortization of origination fees incurred in connection with our new revolving credit facility.

(6) 

Consists of a gain from insurance proceeds and AFUDC equity income. AFUDC, or allowance for funds used during construction, is the amount approved by the FERC for inclusion in our tariff rates as reimbursement for the cost of financing construction projects with investor capital until a project is placed into operation. Refer to Note 2(f) “Pro Forma Adjustments and Assumptions,” in the Notes to Unaudited Pro Forma Combined Financial Statements for additional information.

(7) 

Consists of Tennessee state income taxes.

(8) 

Cash interest, net includes interest expense based on historical rates incurred by Columbia OpCo on borrowings from affiliates of CEG to fund expansion capital expenditures.

(9) 

Maintenance capital expenditures are cash expenditures (including expenditures for the construction or development of new capital assets to replace or improve existing capital assets) made to maintain, over the long term, our operating capacity, system integrity and reliability. Examples of maintenance capital expenditures are expenditures to replace pipelines, to fund the acquisition of certain equipment, to maintain equipment reliability, integrity and safety and to address environmental laws and regulations.

(10) 

Expansion capital expenditures are cash expenditures incurred for acquisitions or capital improvements that we expect will increase our operating income or operating capacity over the long term. Examples of expansion capital expenditures include the construction, development or acquisition of additional pipeline, storage or gathering capacity, as well as the Columbia Gas Transmission modernization program, to the extent such capital expenditures are expected to expand our operating capacity or our operating income.

 

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(11) 

Represents CEG’s 85.4% limited partner interest in Columbia OpCo.

(12) 

Cash interest includes commitment fees of $1.5 million and the amortization of origination fees of $0.3 million incurred in connection with our new revolving credit facility.

(13) 

Reflects an adjustment for approximately $5.0 million of expenses that we expect to incur as a result of operating as a publicly traded partnership, such as expenses associated with annual and quarterly reporting, tax return and Schedule K-1 preparation and distribution expenses, Sarbanes-Oxley compliance expenses, expenses associated with listing on the NYSE, independent auditor fees, legal fees, investor relations expenses, registrar and transfer agent fees, director and officer insurance expenses and director and officer compensation expenses.

Estimated Cash Available for Distribution for the Twelve Months Ending December 31, 2015

Set forth below is a statement of Estimated Cash Available for Distribution that reflects a forecast of our ability to generate sufficient cash flows to make the minimum quarterly distribution on all of our outstanding units for the twelve months ending December 31, 2015, based on assumptions we believe to be reasonable. These assumptions include adjustments giving effect to this offering.

Our estimated cash available for distribution for the twelve months ending December 31, 2015 is projected to be $69.0 million, as compared to our pro forma cash available for distribution of $50.8 million for the year ended December 31, 2013 and $55.6 million for the twelve months ended September 30, 2014. Our estimated cash available for distribution 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, 2015. The assumptions disclosed under “—Assumptions and Considerations” below are those that we believe are significant to our ability to generate such estimated cash available for distribution. We believe our actual results of operations and cash flows for the twelve months ending December 31, 2015 will be sufficient to generate our estimated cash available for distribution for such period; however, we can give you no assurance that such estimated cash available for distribution will be achieved. There will likely be differences between our estimated cash available for distribution for the twelve months ending December 31, 2015 and our actual results for such period and those differences could be material. If we fail to generate the estimated cash available for distribution for the twelve months ending December 31, 2015, we may not be able to pay cash distributions on our common units at the minimum quarterly distribution rate or at any rate.

We do not as a matter of course make public projections as to future sales, earnings, or other results. However, our management has prepared the prospective financial information set forth below to substantiate our belief that we will have sufficient cash available to make the minimum quarterly distribution to our unitholders for the twelve months ending December 31, 2015. The accompanying prospective financial information was not prepared with a view toward public disclosure or with a view toward complying with the published guidelines of the SEC or guidelines established by the American Institute of Certified Public Accountants with respect to prospective financial information, but, in the view of our management, 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, our expected course of action and our expected future financial performance. However, this information is not fact and should not be relied upon as being necessarily indicative of future results, and readers of this prospectus are cautioned not to place undue reliance on the prospective financial information.

Neither our independent auditors, 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. They assume no responsibility for, and disclaim any association with, the prospective financial information contained herein.

When considering the estimated cash available for distribution set forth below you should keep in mind the risk factors and other cautionary statements under “Risk Factors.” Any of the risks discussed in this prospectus, to the extent they are realized, could cause our actual results of operations to vary significantly from those

 

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supporting such estimated available cash. Accordingly, there can be no assurance that the forecast is indicative of our future performance. Inclusion of the forecast in this prospectus is not a representation by any person, including us or the underwriters, that the results in the forecast will be achieved.

We are providing the estimated cash available for distribution and related assumptions for the twelve months ending December 31, 2015 to supplement our pro forma and historical financial statements in support of our belief that we will have sufficient available cash to allow us to pay cash distributions on all of our outstanding common and subordinated units for each quarter in the twelve-month period ending December 31, 2015 at our stated minimum quarterly distribution rate. Please read below under “—Assumptions and Considerations” for further information as to the assumptions we have made for the preparation of the estimated cash available for distribution set forth below. The narrative descriptions of our assumptions in “—Assumptions and Considerations” generally compare our estimated cash available for distribution for the twelve months ending December 31, 2015 with the unaudited pro forma cash available for distribution for the year ended December 31, 2013 presented under “— Unaudited Pro Forma Cash Available for Distribution for the Year Ended December 31, 2013 and Twelve Months Ended September 30, 2014.”

We do not undertake any obligation to release publicly the results of any future revisions we may make to the assumptions used in generating our estimated cash available for distribution for the twelve months ending December 31, 2015 or to update those assumptions to reflect events or circumstances after the date of this prospectus. Therefore, you are cautioned not to place undue reliance on this information. Components in the following table may not add or subtract to totals due to rounding.

Columbia Pipeline Partners LP

Estimated Cash Available for Distribution

 

     Twelve Months
Ending December 31,
2015
 
     (in millions)  

Operating revenues

   $ 1,449.9   

Operating expenses:

  

Operation and maintenance

     624.0   

Operation and maintenance—affiliated(1)

     151.9   

Depreciation and amortization

     140.1   

Gain on sale of assets(2)

     (20.9

Property and other taxes

     77.3   
  

 

 

 

Total operating expenses

     972.4   
  

 

 

 

Equity earnings in unconsolidated affiliates

     61.2   
  

 

 

 

Operating income

     538.7   
  

 

 

 

Interest expense—affiliated(3)

     (26.2

Other, net

     15.2   

Income taxes

     —     
  

 

 

 

Net income

     527.7   
  

 

 

 

Add:

  

Interest expense—affiliated

     26.2   

Income taxes

     —     

Depreciation and amortization

     140.1   

Distributions of earnings received from equity investees

     59.5   

Less:

  

Other, net

     15.2   

Equity earnings in unconsolidated affiliates

     61.2   
  

 

 

 

 

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Adjusted EBITDA(4)

     677.1   
  

 

 

 

Less:

  

Cash interest, expense(5)

     26.2   

Maintenance capital expenditures

     139.3   

Gain on sale of assets(6)

     20.9   

Non-recurring capital costs related to spin-off(7)

     19.8   

Expansion capital expenditures

     892.0   

Add:

  

Borrowing from affiliates of CEG to fund non-cash gain on sale of assets(8)

     20.9   

Borrowing from affiliates of CEG to fund spin-off operating and capital expenditures

     30.8   

Borrowings from affiliates of CEG and IPO proceeds to fund expansion capital expenditures(9)

     892.0   

Estimated cash available for distribution by Columbia OpCo

   $ 522.6   
  

 

 

 

Less:

  

Estimated cash available for distribution attributable to non-controlling interest in Columbia OpCo(10)

     446.2   

Cash interest, net(11)

     2.4   

Incremental general and administrative expenses(12)

     5.0   

Estimated cash available for distribution by Columbia Pipeline Partners LP

   $ 69.0   
  

 

 

 

Minimum annual distribution per unit (based on a minimum quarterly distribution rate of $0.1675 per unit)

   $ 0.6700   

Cash distributions

  

Distributions to public common unitholders

   $ 26.8   

Distributions to CEG:

  

Common units

     4.5   

Subordinated units

     31.4   
  

 

 

 

Total distributions to CEG

     35.9   
  

 

 

 

Total distributions to our unitholders at minimum rate

   $ 62.7   

Surplus ($)

     6.3   

 

(1) 

Includes forecasted expenses of $25.6 million related to the spin-off of HoldCo for the twelve months ended December 31, 2015.

(2)

Includes approximately $20.9 million attributable to the conveyance of mineral rights leases.

(3) 

Includes interest expense attributable to funds drawn by Columbia OpCo under the intercompany money pool agreement to fund expansion capital expenditures.

(4) 

For more information, please read “Summary—Summary Historical and Pro Forma Financial and Operating Data—Non-GAAP Financial Measures.”

(5) 

Calculated based on an assumed average long-term debt level of $651.3 million and assumed average short-term debt level of $96.9 million.

(6) 

Relates to a non-cash gain attributable to a mineral interest conveyance for which cash was received in a prior period.

(7) 

Represents the non-recurring capital expenditures for the twelve months ended December 31, 2015, which relate to the spin-off of HoldCo.

(8) 

Consists of borrowings by Columbia OpCo under the intercompany money pool agreement relating to non-cash gain described above.

(9) 

Consists of $689.0 million in borrowings by Columbia OpCo under the intercompany money pool agreement and net proceeds of $255.0 million from this offering that will be used to fund expansion projects. For more information, please read “Use of Proceeds.”

(10) 

Represents CEG’s 85.4% limited partner interest in Columbia OpCo.

(11) 

Cash interest includes commitment fees on, and the amortization of origination fees incurred in connection with, our new revolving credit facility.

(12) 

Reflects an adjustment for approximately $5.0 million of expenses that we expect to incur as a result of operating as a publicly traded partnership, such as expenses associated with annual and quarterly reporting, tax return and Schedule K-1 preparation and distribution expenses, Sarbanes-Oxley compliance expenses, expenses associated with listing on the NYSE, independent auditor fees, legal fees, investor relations expenses, registrar and transfer agent fees, director and officer insurance expenses and director and officer compensation expenses.

 

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Assumptions and Considerations

We believe that our estimated cash available for distribution for the twelve months ending December 31, 2015 will not be less than $69.0 million. This amount of estimated cash available for distribution is approximately $13.4 million more than the pro forma cash available for distribution we generated for the twelve months ended September 30, 2014 and approximately $18.2 million more than the pro forma cash available for distribution we generated for the year ended December 31, 2013. We believe that increased income primarily from increases in revenues will result in our generating higher cash available for distribution for the twelve months ending December 31, 2015. The assumptions and estimates we have made to support our ability to generate the minimum estimated cash available for distribution are set forth below.

We have assumed we will not acquire any additional equity interests in Columbia OpCo during the twelve months ending December 31, 2015.

Regulatory, Industry and Economic Factors

Our estimate for the twelve months ending December 31, 2015 is based on the following significant assumptions related to regulatory, industry and economic factors:

 

   

We assume there will not be any new federal, state or local regulations of portions of the energy industry in which we operate, or any new interpretations of existing regulations, that will be materially adverse to our business.

 

   

We assume there will not be any major adverse changes in the portions of the energy industry in which we operate or in general economic conditions.

 

   

We assume that industry, insurance and overall economic conditions will not change substantially.

 

   

We assume the organic growth projects described will not be delayed due to unusual weather or other events beyond our control.

Operating Revenues

We estimate that Columbia OpCo will generate approximately $1,449.9 million in total operating revenue for the twelve months ending December 31, 2015, compared with pro forma total operating revenue of $1,326.7 million and $1,176.7 million for the twelve months ended September 30, 2014 and the year ended December 31, 2013, respectively. Our forecast is based primarily on the following assumptions:

Transmission and Storage. Excluding tracker-related revenues, we estimate that approximately 93%, or approximately $1,064 million, of our revenue will be generated from transmission and storage services for the twelve-month period ending December 31, 2015. This compares to approximately 96%, or approximately $904 million, of our pro forma revenues that were generated from transmission and storage revenues during the year ended December 31, 2013, and approximately 93%, or approximately $937 million, of our pro forma revenues that were generated from transmission and storage revenues during the twelve-month period ended September 30, 2014. Excluding tracker-related revenues, transmission and storage revenues are expected to increase by approximately $127 million during the twelve-month period ending December 31, 2015 as compared to the pro forma twelve-month period ended September 30, 2014, primarily consisting of the following:

 

   

approximately $42.5 million of the increase is due to the net impact of the Columbia Gas Transmission modernization settlement consisting of a new demand charge known as the Capital Cost Recovery Mechanism (“CCRM”) effective February 2014 partially offset by a base rate reduction;

 

   

approximately $19.8 million of the increase is due to additional contracted firm transmission capacity from the West Side Expansion, which was placed in service in the fourth quarter of 2014;

 

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approximately $15.3 million of the increase is due to additional contracted firm transmission capacity created by the East Side Expansion, which was placed in service in the fourth quarter of 2014;

 

   

approximately $12.7 million of the increase is due to increased throughput on the Big Pine system due to planned increased production by shippers;

 

   

approximately $7.6 million of the increase is due to additional contracted firm transmission capacity from the Giles County Project, which was placed in service during the fourth quarter of 2014;

 

   

approximately $7.3 million of the increase is due to additional contracted firm transmission capacity and a full period of revenue from the Warren County Project, which went in service in the second quarter of 2014;

 

   

approximately $6.3 million of the increase is due to additional contracted firm transmission capacity from Line 1570, which was placed in service during the fourth quarter of 2014;

 

   

approximately $3.9 million of the increase is due to additional contracted firm interim transmission capacity created by the Rayne XPress project, which commenced in the fourth quarter of 2014;

 

   

approximately $2.2 million of the increase is due to additional contracted firm transmission capacity created by Big Pine Expansion, which is expected to be in service in the third quarter of 2015; and

 

   

approximately $4.4 million of the increase is due to additional contracted firm transmission capacity created by Washington County Gathering, which is expected to be in service in the fourth quarter of 2015;

 

   

partially offset by an approximate $2.2 million decrease attributable to Columbia Gulf contracts that are anticipated to not be renewed or renewed at a discount.

Trackers. We estimate that approximately 21%, or approximately $306 million, of our total operating revenue for the twelve months ending December 31, 2015 will be generated from our recovery of operating costs under certain regulatory tracker mechanisms. This compares to approximately 20%, or approximately $234 million, of our pro forma revenues that were generated from cost recovery under certain regulatory tracker mechanisms during the year ended December 31, 2013, and approximately 24%, or approximately $322 million, of our pro forma revenues that were generated from cost recovery under certain regulatory tracker mechanisms during the twelve-month period ended September 30, 2014. We expect these regulatory tracker cost recovery revenues to decrease by approximately $15.5 million during the twelve-month period ending December 31, 2015, as compared to the pro forma twelve-month period ended September 30, 2014, due to changes in timing and lower gas prices. Revenues attributable to cost recovery under certain regulatory tracker mechanisms are offset in expenses and have no impact on net income.

Other Revenue. Other revenue primarily consists of revenue from mineral rights and processing, rent and sales of gas. Excluding trackers, we estimate that approximately 7%, or approximately $78 million, of our revenue for the twelve months ending December 31, 2015 will be generated from other revenue sources. This compares to approximately 4%, or approximately $39 million, of our pro forma revenues that were generated from other revenue sources during the year ended December 31, 2013, and approximately 7%, or approximately $68 million, of our pro forma revenues that were generated from other revenue sources during the twelve-month period ended September 30, 2014. We expect our other revenues to increase by approximately $11 million during the twelve-month period ending December 31, 2015, as compared to the pro forma twelve-month period ended September 30, 2014, due to increases in royalties from mineral rights as a result of additional drilling on leased properties.

Operation and Maintenance Expense

We estimate operation and maintenance expenses will be approximately $775.9 million for the twelve months ending December 31, 2015 as compared to $741.5 million for the twelve months ended September 30,

 

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2014 and $623.9 million for the year ended December 31, 2013, respectively. Excluding tracker-related expenses, the approximate $49.9 million increase in operation and maintenance expense during the twelve-month period ending December 31, 2015, as compared to the pro forma twelve-month period ended September 30, 2014, is primarily due to:

 

   

approximately $25.6 million related to the spin-off of HoldCo, consisting of recurring costs of approximately $14.6 million related to increased shared services costs required to operate as a separate public company and approximately $11.0 million of non-recurring costs related to implementation of new accounting and software systems;

 

   

approximately $10.0 million in increased maintenance, primarily due to the timing of the integrity management program and compressor station work; and

 

   

approximately $9.9 million in increased direct labor costs.

Depreciation and Amortization Expense

We estimate total depreciation and amortization expense for the twelve months ending December 31, 2015 will be approximately $140.1 million, as compared to depreciation and amortization expense of $115.0 million for the twelve months ended September 30, 2014 and $106.1 million for the year ended December 31, 2013, both on a pro forma basis. Estimated depreciation and amortization expense reflects management’s estimates, which are based on consistent average depreciable asset lives and depreciation methodologies, taking into account estimated capital expenditures and new assets placed into service.

Property and Other Tax Expense

We estimate our property and other taxes for the twelve months ending December 31, 2015 will be approximately $77.3 million, as compared to property and other taxes of $65.6 million for the twelve months ended September 30, 2014 and $61.9 million for the year ended December 31, 2013, both on a pro forma basis. The increase in property and other taxes is primarily due to increased property taxes resulting from new capital expansion projects.

Equity Earnings

We estimate our equity earnings for the twelve months ending December 31, 2015 will be approximately $61.2 million, as compared to equity earnings of $43.1 million for the twelve months ended September 30, 2014 and $35.8 million for the year ended December 31, 2013, both on a pro forma basis. We expect our equity earnings to increase due primarily to increases in equity earnings from Millennium Pipeline due to the Hancock Compressor Project, which went in service in the first quarter of 2014. We estimate cash distributions from our equity investments for the twelve months ending December 31, 2015 will be approximately $59.5 million as compared to cash distributions of $40.7 million for the twelve months ended September 30, 2014 and $32.1 million for the twelve months ended December 31, 2013.

Financing

We estimate that interest expense will be approximately $26.2 million for the twelve months ending December 31, 2015, as compared to $1.8 million for the year ended December 31, 2013 and $6.1 million during the twelve months ended September 30, 2014, both on a pro forma basis. Our forecasted interest expense for the twelve months ending December 31, 2015 is based on the following assumptions:

 

   

During the twelve months ending December 31, 2015, Columbia OpCo will use $255.0 million in net offering proceeds it receives from us to fund a portion of its expansion capital expenditures. All additional funding needs to fund expansion capital expenditures and spin-off operating and capital expenditures are expected to be made available from the credit facilities available to us or to Columbia OpCo. Any shortfall in our capital expenditures and expansion capital expenditures will be funded by our revolving credit facility or external equity or debt financing transactions.

 

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Columbia OpCo will have interest expense of approximately $26.2 million based on an assumed average long-term debt level of $651.3 million comprised of long-term debt remaining on Columbia OpCo’s books after formation and an assumed average short-term debt level of $96.9 million (or $689 million over the entire period) comprised of funds drawn on its $750 million of reserved borrowing capacity under the intercompany money pool agreement used to fund expansion capital expenditures and spin-off operating and capital expenditures.

 

   

We expect to have average borrowings under our new revolving credit facility of approximately $28.0 million during the twelve-month period ending December 31, 2015, which would be used to fund working capital by Columbia OpCo. We expect to pay approximately $1.5 million in credit facility commitment fees and approximately $40,000 in administrative agent fees at the closing of this offering. We have assumed that the new revolving credit facility will bear interest at an average rate of 2.35% per annum. An increase or decrease of 1.0% in the interest rate will result in increased or decreased annual interest expense of $0.3 million.

 

   

Interest expense also includes the amortization of origination fees of $1.8 million which are assumed to be incurred in connection with our new revolving credit facility. These fees are expected to be amortized at a rate of approximately $0.3 million per year.

 

   

Our borrowing capacity for Columbia OpCo and its subsidiaries under the intercompany money pool arrangement is limited to $750 million, plus any additional available capacity on NiSource’s revolving credit facility, up to a combined maximum level of $1 billion dollars. In addition, we will also have access to a $500 million revolving credit facility at the Partnership. In the event that the separation of HoldCo from NiSource occurs, Columbia OpCo will have access to an intercompany money pool arrangement with HoldCo with $750 million of reserved borrowing capacity, with additional capacity as available under the HoldCo revolving credit facility, up to a combined maximum level of $1.5 billion. To the extent our capital requirements exceed amounts available under our combined credit facilities, we will be required to fund such amounts by seeking to increase our borrowing capacity under these facilities or seek to issue debt or equity in private placements or public offerings, subject to market conditions.

Capital Expenditures

We maintain an ongoing program of continually investing in our business. Our expenditures include ongoing expenditures required to maintain operating capacity, system integrity and reliability as well as expansion projects that increase capacity or allow us to operate more efficiently. We categorize our capital expenditures as either:

 

   

Expansion capital expenditures are cash expenditures incurred for acquisitions or capital improvements that we expect will increase our operating income or operating capacity over the long term. Examples of expansion capital expenditures include the construction, development or acquisition of additional pipeline, storage or gathering capacity, as well as the Columbia Gas Transmission modernization program, to the extent such capital expenditures are expected to expand our operating capacity or our operating income. In particular, the Columbia Gas Transmission modernization program, which includes replacement of aging pipeline and compressor facilities, enhancements to system inspection capabilities and improvements in control systems, is expected to primarily increase our long-term operating income by allowing us to recover certain invested capital under the CCRM. For more information, please refer to Note 8 “Regulatory Matters” in the audited Notes to Combined Financial Statements.

 

   

Maintenance capital expenditures are cash expenditures (including expenditures for the construction or development of new assets to replace or improve existing assets) made to maintain, over the long term, our operating capacity, system integrity and reliability. Examples of maintenance capital expenditures are expenditures to replace pipelines, to fund the acquisition of certain equipment, to maintain equipment reliability, integrity and safety and to address environmental laws and regulations.

 

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We estimate that total capital expenditures for Columbia OpCo for the twelve months ending December 31, 2015 will be $1,051.1 million, compared to $856.9 million for the twelve months ended September 30, 2014 and $790.6 million for the year ended December 31, 2013 on a pro forma basis. Our estimate is based on the following assumptions:

Expansion Capital Expenditures. We estimate expansion capital expenditures to be $892.0 million for the twelve months ending December 31, 2015, as compared to $715.8 million for the twelve months ended September 30, 2014 and $658.9 million for the year ended December 31, 2013. We intend to finance these expansion capital expenditures as described above. These expenditures are primarily comprised of the following expansion capital projects that we intend to pursue during the forecast period:

 

   

approximately $300 million in connection with the modernization program, which involves replacement and improvement of aging infrastructure, upgrading compression and expanding in-line inspection capability;

 

   

approximately $179 million for East Side Expansion, which will provide access for production from the Marcellus shale to the northeastern and mid-Atlantic markets;

 

   

approximately $148 million for Rayne XPress and Leach XPress, which involves adding 124 miles of 36-inch pipeline from Majorsville to Crawford CS, 27 miles of 36-inch pipeline from Crawford CS to McArthur CS and approximately 163,700 horsepower of compression across multiple sites;

 

   

approximately $61 million for the Big Pine Expansion, which involves the addition of 9 miles of 20-inch pipeline and compression facilities that will add incremental capacity to the Big Pine pipeline;

 

   

approximately $58 million for Washington County Gathering System, which involves construction of a 21-mile dry gas field gathering system with compression, measurement and dehydration facilities to feed into Line 1570;

 

   

approximately $42 million for West Side Expansion, which involves increasing supply takeaway from the Marcellus to Gulf Coast and Southeast markets with piping modifications and compression to add 980,000 Dth/d of capacity;

 

   

approximately $32 million for WB XPress, which involves approximately 29 miles of various sized pipe, 170,000 horsepower of compression, various system and station modification along line WB to add 1,300,000 Dth/d of capacity to expanding eastern and Gulf coast markets;

 

   

approximately $22 million for CEVCO investments, which involves an investment in the Cardinal Upstream project, in which we are a 5% working interest owner with Hilcorp in the development of wells in a specified acreage area in the Utica/Point Pleasant formation;

 

   

approximately $20 million for the Kentucky Power Plant Project, which involves the addition of 2.7 miles of 16-inch greenfield pipeline from Columbia Gas Transmission’s Line P to a third-party power plant, point of delivery meter site in the existing third-party plant, regulation at the Kenova compressor station, and regulation and a heater at the intersection of Line P and SM-102;

 

   

approximately $13 million for Cameron Access Project, which involves the addition of a 26-mile pipeline and compressor; improvements to existing pipeline and compression facilities, and a new compressor station; 800,000 Dth/d of additional capacity from Rayne, LA compressor station to the Cameron LNG terminal; and

 

   

approximately $13 million for Utica Access, which involves the addition of 4.7 miles of 20-inch greenfield pipeline to provide 205,000 Dth/d of new firm service to allow Utica production access to liquid trading points on its system.

Our ability to finance our expansion capital expenditures will depend in part on our ability to fund them from borrowings rather than from cash generated from our operations or from proceeds from the sale of equity interests in Columbia OpCo. While our debt facilities will not be fully drawn during the 12 months ending December 31, 2015, there is no guarantee that expansion capital expenditures incurred after December 31, 2015

 

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could be funded from borrowings. If we are unable to borrow to finance our expansion capital expenditures in the future, we would need to fund them from either proceeds from the sale of equity interests in Columbia OpCo to the Partnership or to third parties or from operating cash flows, which would significantly reduce the amount of cash available for distribution to our unitholders.

Maintenance Capital Expenditures. We estimate total maintenance capital expenditures to be $139.3 million for the twelve months ending December 31, 2015. This compares to $141.1 million for the twelve months ended September 30, 2014 and $131.7 million for the year ended December 31, 2013 on a pro forma basis. We estimate this decrease will be due to the timing of maintenance projects. We expect to fund these maintenance capital expenditures with cash generated by our operations. We expect ongoing maintenance capital expenditures to be approximately $135 million per year in the near term.

Non-Recurring Capital Expenditures Related to Spin-Off. We estimate $19.8 million of non-recurring capital expenditures related to the spin-off of HoldCo for the twelve months ending December 31, 2015.

 

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HOW WE MAKE DISTRIBUTIONS TO OUR PARTNERS

General

Cash Distribution Policy

Our partnership agreement provides that our general partner will make a determination as to whether to make a distribution, but our partnership agreement does not require us to pay distributions at any time or in any amount. Instead, the board of directors of our general partner will adopt a cash distribution policy to be effective as of the closing of this offering that will set forth our general partner’s intention with respect to the distributions to be made to unitholders. Pursuant to our cash distribution policy, within 60 days after the end of each quarter, beginning with the quarter ending March 31, 2015, we intend to distribute to the holders of common and subordinated units on a quarterly basis at least the minimum quarterly distribution of $0.1675 per unit, or $0.67 on an annualized basis, to the extent we have sufficient cash after establishment of cash reserves and payment of fees and expenses, including payments to our general partner and its affiliates. We will prorate the distribution for the period after the closing of this offering through March 31, 2015.

The board of directors of our general partner may change the foregoing distribution policy at any time and from time to time, and 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. Our partnership agreement does not contain a requirement for us to pay distributions to our unitholders, and there is no guarantee that we will pay the minimum quarterly distribution, or any distribution, on the units in any quarter. However, our partnership agreement does contain provisions intended to motivate our general partner to make steady, increasing and sustainable distributions over time.

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

Operating Surplus and Capital Surplus

General

Any distributions we make will be characterized as made from “operating surplus” or “capital surplus.” Distributions from operating surplus are made differently than cash distributions we would make from capital surplus. Operating surplus distributions will be made to our unitholders and, if we make quarterly distributions above the first target distribution level described below, to the holder of our incentive distribution rights. We do not anticipate that we will make any distributions from capital surplus. In such an event, however, any capital surplus distribution would be made pro rata to all unitholders. Any distribution of capital surplus would result in a reduction of the minimum quarterly distribution and target distribution levels and, if we reduce the minimum quarterly distribution to zero and eliminate any unpaid arrearages, thereafter capital surplus would be distributed as if it were operating surplus and the incentive distribution rights would thereafter be entitled to participate in such distributions. Please see “—Distributions From Capital Surplus.” In determining operating surplus and capital surplus, we will only take into account our proportionate share of our consolidated subsidiaries that are not wholly owned, such as Columbia OpCo.

Operating Surplus

We define operating surplus as:

 

   

$62 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) and provided that cash receipts from the termination of any hedge contract prior to its

 

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stipulated settlement or termination date will be included in equal quarterly installments over the remaining scheduled life of such hedge contract had it not been terminated; 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 that commences when we enter into a binding obligation for the acquisition, construction, development or expansion and ending on the earlier to occur of the date any acquisition, construction, development or expansion commences commercial service and the date that it is disposed of or abandoned; plus

 

   

cash distributions paid in respect of equity issued (including incremental distributions on incentive distribution rights) to pay the construction period interest on debt incurred, or to pay construction period distributions on equity issued, to finance the expansion capital expenditures referred to above, in each case, in respect of the period that commences when we enter into a binding obligation for the acquisition, construction, development or expansion and ending on the earlier to occur of the date any acquisition, construction, development or expansion commences commercial service and the date that it is disposed of or abandoned; 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 or the boards of any of our subsidiaries to provide funds for future operating expenditures; less

 

   

all working capital borrowings not repaid within twelve months after having been incurred or repaid within such twelve-month period with the proceeds of additional working capital borrowings; less

 

   

any cash loss realized on disposition of an investment capital expenditure.

Disbursements made, cash received (including working capital borrowings) or cash reserves established, increased or reduced after the end of a period but on or before the date on which cash or cash equivalents will be distributed with respect to such period shall be deemed to have been made, received, established, increased or reduced, for purposes of determining operating surplus, within such period if our general partner so determines. Furthermore, cash received from an interest in an entity for which we account using the equity method will not be included to the extent it exceeds our proportionate share of that entity’s operating surplus (calculated as if the definition of operating surplus applied to such entity from the date of our acquisition of such an interest without any basket similar to described in the first bullet above). Operating surplus is not limited to cash generated by our operations. For example, it includes a basket of $62 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 deducted from operating surplus 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 deduction. Our general partner may treat the temporary use of cash reserved to fund expansion capital expenditures as a working capital borrowing, and may use such cash to temporarily fund operating expenditures. When such expansion capital expenditures are in fact made (or twelve months after the date such cash was used, if earlier), the amount temporarily used as working capital borrowings shall be treated as a repayment of working capital borrowings.

We define operating expenditures in our 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 hedge contracts (provided that (1) with respect to amounts paid in connection with the initial purchase of a hedge contract, such amounts will be amortized over the life of the applicable hedge contract and (2) payments made in connection with the termination of any hedge contract prior to the expiration of its stipulated settlement or termination date will be included in operating expenditures in equal quarterly

 

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installments over the remaining scheduled life of such hedge contract), officer and director compensation, repayment of working capital borrowings, interest on indebtedness and maintenance capital expenditures (as discussed in further detail below), 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 and the purchase price of indebtedness that is repurchased and cancelled) 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 cash distributed 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 interests; 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 provides that we treat all cash distributed as coming from operating surplus until the sum of all cash distributed since the closing of this offering (other than any distributions of proceeds of this offering) equals the operating surplus from the closing of this offering. Our partnership agreement provides that we treat any amount distributed in excess of operating surplus, regardless of its source, as distributions of capital surplus. We do not anticipate that we will make any distributions from capital surplus.

Capital Expenditures

Maintenance capital expenditures reduce operating surplus, but expansion capital expenditures and investment capital expenditures do not. Maintenance capital expenditures are those cash expenditures (including expenditures for the construction or development of new capital assets to replace or improve existing capital assets) made to maintain, over the long term, our operating capacity, system integrity and reliability. Examples of maintenance capital expenditures are expenditures to replace pipelines, to fund the acquisition of certain equipment, to maintain equipment reliability, integrity and safety and to address environmental laws and regulations. Cash expenditures made solely for investment purposes will not be considered maintenance capital expenditures.

Expansion capital expenditures are those cash expenditures, including transaction expenses, made to increase our operating capacity or net income over the long term. Examples of expansion capital expenditures

 

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include the development of a new facility or the expansion of an existing facility, to the extent such expenditures are expected to expand our long-term operating capacity or net income. Expansion capital expenditures will also include interest (and related fees) on debt incurred to finance all or any portion of such construction, development or expansion in respect of the period that commences when we enter into a binding obligation for the acquisition, construction, development or expansion and ending on the earlier to occur of the date any acquisition, construction, development or expansion commences commercial service and the date that it is disposed of or abandoned. Expenditures made solely for investment purposes will not be considered expansion capital expenditures.

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

As described above, neither investment capital expenditures nor expansion capital expenditures are 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 an acquisition, development or expansion in respect of a period that begins when we enter into a binding obligation for an acquisition, construction, development or expansion and ends on the earlier to occur of the date on which such acquisition, construction, development or expansion commences commercial service and the date that it is abandoned or disposed of, such interest payments 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.

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

Subordination Period

General

Our partnership agreement provides that, during the subordination period (which we describe below), the common units will have the right to receive distributions from operating surplus each quarter in an amount equal to $0.1675 per common unit, which amount is defined in our partnership agreement as the minimum quarterly distribution, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions from operating surplus may be made on the subordinated units. These units are deemed “subordinated” because for a period of time, referred to as the subordination period, the subordinated units will not be entitled to receive any distributions from operating surplus until the common units have received the minimum quarterly distribution from operating surplus plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. Furthermore, no arrearages will be paid on the subordinated units. The practical effect of the subordinated units is to increase the likelihood that during the subordination period there will be sufficient cash from operating surplus to pay the minimum quarterly distribution on the common units.

 

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Determination of Subordination Period

Except as described below, the subordination period will begin on the closing date of this offering and expire on the first business day after the distribution to unitholders in respect of any quarter, beginning with the quarter ending March 31, 2018, if each of the following has occurred:

 

   

for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date, aggregate distributions from operating surplus equaled or exceeded the sum of the minimum quarterly distribution multiplied by the total number of common and subordinated units outstanding for each quarter of each period;