Columbia Pipeline Partners LP - S-1 filing on 2007-12-21

Proposed Maximum

Amount of

Title of Each Class of

Aggregate Offering

Registration

Securities to be Registered

Price(1)(2)

Common units representing limited partner interests

$301,875,000

TABLE OF CONTENTS


SUMMARY			1
Overview			1
Columbia Gulf Pipeline System			1
Our Operations			2
Business Strategies			3
Competitive Strengths			3
Non-GAAP Financial Measures			15
RISK FACTORS			17
Risks Related to Our Business			17
Risks Inherent in an Investment in Us			31
Tax Risks to Common Unitholders			38
USE OF PROCEEDS			42
CAPITALIZATION			43
DILUTION			44
OUR CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS			46
General			46
Our Initial Distribution Rate			47
Unaudited Pro Forma Cash Available for Distribution for the Year Ended December 31, 2006 and Twelve Months Ended September 30, 2007			49
Minimum Estimated Cash Available for Distribution for the Twelve-Month Period Ending March 31, 2009			53
Assumptions and Considerations			57
PROVISIONS OF OUR PARTNERSHIP AGREEMENT RELATING TO CASH DISTRIBUTIONS			60
Distributions of Available Cash			60
Operating Surplus and Capital Surplus			61
Subordination Period			62
Distributions of Available Cash from Operating Surplus during the Subordination Period			63
Distributions of Available Cash from Operating Surplus after the Subordination Period			64
General Partner Interest and Incentive Distribution Rights			64
Percentage Allocations of Available Cash from Operating Surplus			65
General Partner’s Right to Reset Incentive Distribution Levels			65
Distributions from Capital Surplus			67
Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels			68
Distributions of Cash Upon Liquidation			68
SELECTED HISTORICAL AND PRO FORMA FINANCIAL AND OPERATING DATA			71
Non-GAAP Financial Measures			73
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			75
Overview			75
Factors That Impact Our Business			75
How We Evaluate Our Operations			76
Results of Operations			78
Future Trends and Outlooks			80
Liquidity and Capital Resources			81

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Market Risk Disclosures			84
Off Balance Sheet Arrangements			85
Critical Accounting Policies and Estimates			85
INDUSTRY OVERVIEW			87
Natural Gas Demand			88
Natural Gas Supply			90
BUSINESS			93
Overview			93
Business Strategies			93
Competitive Strengths			94
Our Relationship with NiSource			95
Columbia Gulf Pipeline System			96
Other Assets			100
Safety and Maintenance			100
FERC Regulation			102
Seasonality			106
Environmental Regulation			106
Title to Properties and Rights-of-Way			108
Insurance			108
Facilities			108
Employees			109
Legal Proceedings			109
MANAGEMENT			110
Management of NiSource Energy Partners, L.P.			110
Directors and Executive Officers			111
Reimbursement of Expenses of Our General Partner			112
Executive Compensation			112
Compensation Discussion and Analysis			112
Compensation of Directors			116
Long-Term Incentive Plan			116
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT			119
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS			120
Distributions and Payments to Our General Partner and its Affiliates			120
Agreements Governing the Transactions			121
Omnibus Agreement			121
Contracts with Affiliates			122
CONFLICTS OF INTEREST AND FIDUCIARY DUTIES			123
Conflicts of Interest			123
Fiduciary Duties			128
DESCRIPTION OF THE COMMON UNITS			131
The Units			131
Transfer Agent and Registrar			131
Transfer of Common Units			131
THE PARTNERSHIP AGREEMENT			133
Organization and Duration			133

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Purpose			133
Power of Attorney			133
Cash Distributions			133
Capital Contributions			133
Voting Rights			134
Limited Liability			135
Issuance of Additional Securities			136
Amendment of the Partnership Agreement			136
Merger, Consolidation, Conversion, Sale or Other Disposition of Assets			138
Termination and Dissolution			139
Liquidation and Distribution of Proceeds			139
Withdrawal or Removal of the General Partner			140
Transfer of General Partner Units			141
Transfer of Ownership Interests in the General Partner			141
Transfer of Incentive Distribution Rights			141
Change of Management Provisions			141
Limited Call Right			142
Non-Taxpaying Assignees; Redemption			142
Meetings; Voting			143
Status as Limited Partner			143
Non-Citizen Assignees; Redemption			144
Indemnification			144
Reimbursement of Expenses			144
Books and Reports			144
Right to Inspect Our Books and Records			145
Registration Rights			145
UNITS ELIGIBLE FOR FUTURE SALE			146
MATERIAL TAX CONSEQUENCES			147
Partnership Status			147
Limited Partner Status			148
Tax Consequences of Unit Ownership			149
Tax Treatment of Operations			154
Disposition of Common Units			155
Uniformity of Units			157
Tax-Exempt Organizations and Other Investors			157
Administrative Matters			158
State, Local, Foreign and Other Tax Considerations			160
SELLING UNITHOLDER			161
INVESTMENT IN NISOURCE ENERGY PARTNERS, L.P. BY EMPLOYEE BENEFIT PLANS			162
UNDERWRITING			163
Commissions and Expenses			163
Option to Purchase Additional Common Units			163
Lock-Up Agreements			164
Offering Price Determination			164
Indemnification			165

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Directed Unit Program			165
Stabilization, Short Positions and Penalty Bids			165
Electronic Distribution			166
New York Stock Exchange			166
Discretionary Sales			166
Stamp Taxes			166
Relationships			166
FINRA Rules			166
VALIDITY OF THE COMMON UNITS			167
EXPERTS			167
WHERE YOU CAN FIND MORE INFORMATION			167
FORWARD-LOOKING STATEMENTS			167
INDEX TO FINANCIAL STATEMENTS			F-1
APPENDIX A — FORM OF FIRST AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP OF NISOURCE ENERGY PARTNERS, L.P.			A-1
APPENDIX B — APPLICATION FOR TRANSFER OF COMMON UNITS			B-1
APPENDIX C — CERTIFICATION FORM FOR NON-INDIVIDUAL INVESTORS			C-1
APPENDIX D — GLOSSARY OF TERMS			D-1
Certificate of Limited Partnership
Certificate of Formation
Consent of Deloitte & Touche LLP

You should rely only on the information contained in this prospectus or any free writing prospectus prepared by or on behalf of us in connection with this offering. We have not, and the underwriters have not, authorized anyone to provide you with different information. 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. You should assume that the information appearing in this prospectus is accurate as of the date on the front cover of this prospectus. Our business, financial condition, results of operations and prospects may have changed since that date.

Until , 2008 (25 days after the date of this prospectus), all dealers that buy, sell or trade our common units, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealers’ obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.

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SUMMARY

This summary provides a brief overview of information contained elsewhere in this prospectus. You should read the entire prospectus carefully, including “Risk Factors” beginning on page 17 and the historical and pro forma financial statements. Unless indicated otherwise, the information presented in this prospectus assumes (1) an initial public offering price of $20.00 per common unit and (2) that the underwriters do not exercise their option to purchase additional units. We include a glossary of some of the terms used in this prospectus as Appendix D. References in this prospectus to “NiSource Energy Partners, L.P.,” “we,” “our,” “us” or like terms when used in a historical context refer to the business that NiSource Inc. is contributing to NiSource Energy Partners, L.P. in connection with this offering. When used in the present tense or prospectively, those terms refer to NiSource Energy Partners, L.P. and its subsidiaries. References to our “general partner” refer to NiSource GP, LLC. References to “NiSource” and “Columbia Gulf” refer to NiSource Inc. and its subsidiaries and Columbia Gulf Transmission Company, LLC, or its predecessor Columbia Gulf Transmission Company, respectively.

NiSource Energy Partners, L.P.

Overview

We are a growth-oriented Delaware limited partnership recently formed by NiSource to own and operate natural gas transportation pipelines and related energy infrastructure assets. Our initial asset is the Columbia Gulf pipeline system, an approximately 3,400 mile interstate natural gas transportation pipeline system that extends from southern Louisiana into Kentucky and is regulated by the Federal Energy Regulatory Commission (FERC).

NiSource is an 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. At December 31, 2006, NiSource had approximately 16,000 miles of interstate pipelines (including the Columbia Gulf pipeline system) and operated one of the nation’s largest underground natural gas storage systems with 36 storage facilities capable of storing approximately 252 Bcf of working gas. We intend to utilize the significant experience of NiSource’s management team to execute our growth strategy, which includes the construction and acquisition of additional energy infrastructure assets.

Columbia Gulf Pipeline System

The Columbia Gulf pipeline system consists of approximately 3,400 miles of pipelines and 11 compressor stations with approximately 445,450 horsepower located in Louisiana, Mississippi, Tennessee and Kentucky. The Columbia Gulf pipeline system primarily consists of:


	•	The Mainline System. Columbia Gulf’s Mainline System extends from southern Louisiana to a pipeline interconnection with Columbia Gas Transmission Corporation (Columbia Gas Transmission), a subsidiary of NiSource, in northeastern Kentucky. The Mainline System consists of approximately 2,550 miles of pipelines with peak-design throughput capacity of 2.2 Bcf/d; and

	•	The Louisiana Laterals. The Louisiana Laterals consist of the West Lateral and the East Lateral. The West Lateral extends from an interconnection with the Mainline System along the southern tier of Louisiana westward to Hackberry, Louisiana, while the East Lateral extends eastward to New Orleans and Venice, Louisiana. The Louisiana Laterals consist of approximately 850 miles of pipelines with maximum peak-design capacity in excess of 1.0 Bcf/d on each lateral.

The Columbia Gulf pipeline system was originally constructed for the sole purpose of moving natural gas produced on the Gulf Coast to Midwestern and Mid-Atlantic end-use markets. Since 2006, approximately 1.5 Bcf/d of access to new supply and approximately 0.7 Bcf/d of access to new markets have been added to the system through new interconnects and other system modifications. As a result of this development of laterals and pipeline interconnects, the functionality of this system has fundamentally changed. In addition to traditional supplies on the Gulf Coast, we now have access to multiple strategic natural gas supply sources,

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including basins in North Texas (Barnett Shale), East Texas, North Louisiana and the Appalachian Basin. Similarly, we now provide a pathway for delivery to growing markets in the Southeast in addition to our traditional Midwestern and Mid-Atlantic markets. With interconnections to 29 interstate and 13 intrastate pipelines as of September 30, 2007, we no longer operate solely as a supplier of point-to-point gas transportation services, but as a flexible network that connects multiple producing areas to multiple end-use markets. By continuing to develop the Columbia Gulf pipeline system as a flexible transportation link, we believe we can increase the amount of cash we are able to distribute to you.

For the year ended December 31, 2006 and the nine months ended September 30, 2007, we generated net income of $18.3 million and $20.1 million, respectively, and EBITDA of $54.0 million and $49.0 million, respectively. After adjusting for certain transactions to be effected at the closing of this offering, we would have generated pro forma net income of $21.9 million and $25.1 million, respectively, and pro forma EBITDA of $54.1 million and $49.9 million, respectively. We define our EBITDA as net income plus interest expense (net of a non-cash allowance for funds used during construction, or AFUDC), income taxes and depreciation and amortization, less interest income and other, net. Please read “— Non-GAAP Financial Measures” for an explanation of how we calculate EBITDA, which is a financial measure we use to evaluate our performance, and for a reconciliation of EBITDA to its most directly comparable financial measures calculated and presented in accordance with generally accepted accounting principles in the United States (GAAP).

Our Operations

We transport natural gas for a broad mix of customers, including local gas distribution companies (LDCs), municipal utilities, direct industrial users, electric power generators, marketers, producers and liquified natural gas (LNG) importers. In addition to serving markets directly connected to our system, we serve markets and customers in a variety of other regions through numerous interconnections with major interstate and intrastate pipelines. The rates we charge are regulated by the FERC.

Our pipeline system currently accesses natural gas supply from producing regions in Texas, Louisiana, the Gulf of Mexico and Appalachia, and is positioned to access new supplies from Gulf Coast LNG imports and non-traditional basins such as the Fayette Shale in Arkansas. Through interconnections with major interstate and intrastate pipelines, we also provide transportation of natural gas to growing markets in the Northeast, Midwest, Mid-Atlantic and Southeast United States, and serve industrial, commercial, electric generation and residential customers in Tennessee, Mississippi and Louisiana. We offer customers direct physical access to two of the most actively traded natural gas markets in North America at the Henry Hub in South Louisiana and the Columbia Gas Transmission Supply Pool (TCO Pool) at Leach, Kentucky.

We provide a significant portion of our transportation services under firm contracts that obligate our customers to pay monthly capacity reservation fees over the term of the contract. These monthly capacity reservation fees are payable to us regardless of the actual pipeline capacity utilized. An incremental usage fee based on the actual volume of natural gas transported is also applied when a customer utilizes the capacity it has reserved under these firm contracts. Though they are typically a small percentage of the total revenue we receive under our firm contracts, usage fees enable us to recover our variable costs incurred for the transportation of natural gas on our system. We also derive a portion of our revenues through interruptible contracts under which customers pay fees based on their utilization of our assets for transportation and other related services. Customers who have executed interruptible contracts are not assured capacity in our pipeline facilities. For the twelve months ended September 30, 2007, approximately 80.1% of our transportation revenues were derived from capacity reservation fees paid under firm contracts, approximately 8.7% of our transportation revenues were derived from usage fees under firm contracts and approximately 11.2% of our transportation revenues were derived from interruptible contracts.

The high percentage of our earnings derived from capacity reservation fees mitigates the risk to us of earnings fluctuations caused by changing supply and demand conditions. In addition, we do not own the gas we transport, and we retain a portion of the gas transported in our system to use as fuel for our compressors. As such, we have no direct commodity price exposure. For additional information about our contracts, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — How We Evaluate Our Operations” and “Business — FERC Regulation.”

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Business Strategies

Our primary business objectives are to generate predictable and stable cash flow and, over time, to increase our quarterly cash distribution per unit. We intend to achieve these objectives by executing the following strategies:


	•	Pursue economically attractive organic expansion opportunities and greenfield development projects;

	•	Optimize our asset base and increase profitability by expanding our points of supply and market access; and

	•	Grow through joint ventures, partnerships and accretive acquisitions of energy infrastructure assets from both NiSource and third parties.

Competitive Strengths

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


	•	Our strategic location allows us to transport natural gas from diverse supply sources to high-demand markets at competitive transportation rates;

	•	Our firm contracts and capacity reservation fees provide cash flow stability;

	•	Our pipeline assets have been prudently operated and well maintained;

	•	Our affiliation with NiSource; and

	•	Our experienced management team has a proven track record of operating large and complex interstate natural gas transportation, storage and marketing assets.

Our Relationship with NiSource

One of our principal strengths is our relationship with NiSource, which following this offering will indirectly own our 2% general partner, all of our incentive distribution rights, and a 58.9% limited partner interest in us. NiSource is an 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. NiSource is the largest natural gas distribution company operating east of the Rocky Mountains, as measured by number of customers. We intend to utilize the significant experience of NiSource’s management team to execute our growth strategy, including the construction and acquisition of additional energy infrastructure assets. NiSource’s common stock is traded on the New York Stock Exchange under the symbol “NI.”

NiSource’s Gas Transmission and Storage Operations subsidiaries own and operate approximately 16,000 miles of interstate pipelines (including the Columbia Gulf pipeline system) and operate one of the nation’s largest underground natural gas storage systems with 36 storage fields capable of storing approximately 252 Bcf of working gas as of December 31, 2006. Through its subsidiaries, NiSource owns and operates an interstate pipeline network extending from offshore in the Gulf of Mexico to Lake Erie, New York and the eastern seaboard. Together, these companies serve customers in 19 northeastern, Mid-Atlantic, Midwestern and southern states and the District of Columbia. The Gas Transmission and Storage Operations subsidiaries are engaged in several projects that will expand their facilities and throughput. The Millennium Pipeline is currently under construction and will connect the Empire Pipeline to the Algonquin Pipeline in order to transport natural gas to the greater New York City metropolitan area. In addition, Hardy Storage, a partnership that owns a natural gas storage field in West Virginia and serves the eastern United States, commenced operations in April 2007 and will be fully operational in 2009. In addition to its Gas Transmission and Storage Operations, NiSource’s Natural Gas Distribution Operations serves customers in nine states, and its Electric Operations generates, transmits and distributes electricity to customers in the northern part of Indiana and engages in wholesale and transmission transactions.

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We will enter into an omnibus agreement with NiSource, our general partner, and certain of their affiliates that will govern our relationship with them regarding certain reimbursement and indemnification matters. Please read “Certain Relationships and Related Party Transactions — Omnibus Agreement.” While our relationship with NiSource and its subsidiaries is a significant attribute, it may also be a source of conflicts. For example, neither NiSource nor any of its affiliates are prohibited from competing with us. NiSource and its affiliates may acquire, construct or dispose of assets in the future without any obligation to offer us the opportunity to purchase or construct those assets. Please read “Conflicts of Interest and Fiduciary Duties.”

Summary of Risk Factors

An investment in our common units involves risks. The following list of risk factors is not exhaustive. Please read carefully these and other risks described under “Risk Factors.”

Risks Related to Our Business


	•	We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our general partner, to enable us to make cash distributions to holders of our common units and subordinated units at the initial distribution rate under our cash distribution policy.

	•	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, 2006 and the twelve months ended September 30, 2007, respectively. Please read “Our Cash Distribution Policy and Restrictions on Distributions.”

	•	The assumptions underlying our minimum estimated cash available for distribution we include in “Our Cash Distribution Policy and Restrictions on Distributions” are inherently uncertain and are subject to significant business, economic, financial, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those estimated.

	•	Our natural gas transportation operations are subject to regulation by the FERC, which could have an adverse impact on our ability to establish transportation rates that would allow us to recover the full cost of operating our pipelines, including a reasonable return, and our ability to make distributions to you.

	•	We may not be able to maintain or replace expiring gas transportation contracts at favorable rates.

	•	Any significant decrease in supplies 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.

Risks Inherent in an Investment in Us


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

	•	Affiliates of NiSource are not limited in their ability to compete with us and are not obligated to offer us the opportunity to pursue additional assets or businesses, which could limit our commercial activities or our ability to acquire additional assets or businesses.

	•	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 at a price that may be below the current market price, unless you are (1) an individual or entity subject to U.S. federal income taxation on the income generated by us or (2) an entity not subject to U.S. federal taxation on the income generated by us, but all of whose owners are subject to such taxation.

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	•	Cost reimbursements to our general partner and its affiliates for services provided, which will be determined by our general partner, will be substantial and will reduce our cash available for distribution to you.

	•	Our partnership agreement limits our general partner’s fiduciary duties to holders of our common units and subordinated units and restricts the remedies available to holders of our common units and subordinated units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

Tax Risks to Common Unitholders


	•	Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our 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 were to become subject to additional amounts of entity-level taxation for state tax purposes, then our cash available for distribution to you could be substantially reduced.

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

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

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

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

	•	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.

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Formation Transactions and Partnership Structure

NiSource recently formed us as a Delaware limited partnership to own and operate certain natural gas transportation assets to be contributed to us by NiSource. As is common with publicly traded limited partnerships and in order to maximize operational flexibility, we will conduct our operations through subsidiaries. We will have one direct operating subsidiary initially, NiSource Operating LLC, a Delaware limited liability company that will conduct business through itself and its subsidiaries.

At the closing of this offering the following transactions will occur:


	•	NiSource will contribute Columbia Gulf to us;

	•	we will issue to a subsidiary of NiSource 8,584,349 common units and 10,222,715 subordinated units, representing an aggregate 58.9% limited partner interest in us;

	•	we will issue to NiSource GP, LLC, a subsidiary of NiSource, a 2% general partner interest in us and all of our incentive distribution rights, which will entitle our general partner to increasing percentages of the cash we distribute in excess of $0.345 per unit per quarter (115% of the minimum quarterly distribution);

	•	we will issue 12,500,000 common units to the public in this offering, representing a 39.1% limited partner interest in us, and will use the proceeds as described in “Use of Proceeds”;

	•	we will borrow approximately $37.0 million of term debt and $163.0 million of revolving debt under our $250.0 million credit facility and distribute the aggregate amount of such borrowings to subsidiaries of NiSource; and

	•	we will enter into an omnibus agreement with NiSource, our general partner and certain of their affiliates pursuant to which:


	-	we will reimburse NiSource for the payment of certain operating expenses and for providing various general and administrative services; and

	-	NiSource will indemnify us for certain environmental and tax liabilities, title and right-of-way defects and certain government-mandated pipeline capital expenditures.

Management of NiSource Energy Partners, L.P.

NiSource GP, LLC, our general partner, has sole responsibility for conducting our business and for managing our operations. An affiliate of NiSource, as the sole member of our general partner, will elect all seven members to the board of directors of NiSource GP, LLC, with at least three directors meeting the independence standards established by the New York Stock Exchange. We will have one independent director at the closing of this offering, with the balance to be elected within the time period prescribed by the New York Stock Exchange. All of the executive officers and certain of the directors of our general partner are employed by affiliates of NiSource and will allocate their time between managing our business and affairs and the business and affairs of NiSource and its affiliates. For more information about these individuals, please read “Management — Directors and Executive Officers.”

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Organizational Structure and Ownership

The following diagram depicts our organizational structure after giving effect to this offering and the related transactions assuming no exercise of the underwriters’ option to purchase additional common units.


Public Common Units	12,500,000	39.1%
NiSource Common Units	8,584,349	26.9%
NiSource Subordinated Units	10,222,715	32.0%
General Partner Units	638,920	2.0%

Total	31,945,984	100.0%

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Principal Executive Offices and Internet Address

Our principal executive offices are located at 801 East 86th Avenue, Merrillville, Indiana 46410 and our telephone number is 877-647-5990. Our website is located at http://www.nisourceenergypartners.com and will be activated in connection with the closing of this offering. We expect to make our periodic reports and other information filed with or furnished to the Securities and Exchange Commission (SEC) available free of charge through our website as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus.

Summary of Conflicts of Interest and Fiduciary Duties

General. Our general partner has a legal duty to manage us in a manner beneficial to holders of our common units and subordinated units. This legal duty originates in statutes and judicial decisions and is commonly referred to as a “fiduciary duty.” However, because our general partner is owned by NiSource, the officers and directors of our general partner also have fiduciary duties to manage our general partner in a manner beneficial to NiSource. As a result of this relationship, conflicts of interest may arise in the future between us and holders of our common units and subordinated units, on the one hand, and our general partner and its affiliates on the other hand.

Partnership Agreement Modifications to Fiduciary Duties. Our partnership agreement limits the liability and reduces the fiduciary duties of our general partner to holders of our common units and subordinated units. Our partnership agreement also restricts the remedies available to holders of our common units and subordinated units for actions that might otherwise constitute a breach of our general partner’s fiduciary duties owed to holders of our common units and subordinated units. Our partnership agreement also provides that affiliates of our general partner, including NiSource and its affiliates, are not restricted from competing with us. By purchasing a common unit, the purchaser agrees to be bound by the terms of our partnership agreement and, pursuant to the terms of our partnership agreement, each holder of common units consents to various actions contemplated in the partnership agreement and conflicts of interest that might otherwise be considered a breach of fiduciary or other duties under applicable state law.

For a more detailed description of the conflicts of interest and fiduciary duties of our general partner, please read “Conflicts of Interest and Fiduciary Duties.”

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The Offering


Common units offered to the public		12,500,000 common units; 14,375,000 common units if the underwriters’ option to purchase additional common units is exercised in full.

Units outstanding after this offering		21,084,349 common units and 10,222,715 subordinated units, representing 66.0% and 32.0%, respectively, limited partner interests in us. The general partner will own 638,920 general partner units.

Use of proceeds		We intend to use the net proceeds of approximately $235.0 million from this offering, after deducting $15.0 million of underwriting discounts, but before paying offering expenses, to:

		• pay approximately $3.9 million of fees and expenses associated with the offering and related formation transactions, including a structuring fee payable to Lehman Brothers Inc. for evaluation, analysis and structuring of our partnership;

		• distribute $71.7 million in cash to subsidiaries of NiSource as reimbursement for capital expenditures related to the Columbia Gulf assets incurred by subsidiaries of NiSource prior to the closing of this offering;

		• retire approximately $31.1 million of indebtedness owed to a subsidiary of NiSource;

		• purchase approximately $37.0 million of qualifying investment grade securities, which will be assigned as collateral to secure the term loan portion of our credit facility;

		• use approximately $64.0 million to fund working capital; and

		• use the remaining amount of $27.3 million to offset identified maintenance capital expenditures, including an amount to offset costs we expect to incur in connection with government-mandated pipeline improvements through 2010.

		We also anticipate that we will borrow approximately $37.0 million in term debt and $163.0 million in revolving debt upon the closing of this offering, and we will distribute the net proceeds of such borrowings (or approximately $198.0 million, net of debt issuance costs) to subsidiaries of NiSource, which distribution will be made in partial consideration of the assets contributed to us upon the closing of this offering.

		If the underwriters’ option to purchase an additional 1,875,000 common units is exercised in full, we will (1) use the net proceeds of approximately $35.1 million to purchase an equivalent amount of qualifying investment grade securities and (2) borrow an additional amount under the term loan portion of our credit facility equal to the net proceeds to be received from the exercise of the underwriters’ option. The qualifying securities purchased will be assigned as collateral to secure such additional term loan borrowings. The proceeds of the additional term loan borrowings will be used to redeem from a subsidiary of NiSource a number of common units equal to the number of common units issued upon

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		exercise of the underwriters’ option, at a price per common unit equal to the proceeds per common unit before expenses but after underwriting discounts and a structuring fee.

Cash distributions		We will make an initial quarterly distribution of $0.30 per common unit ($1.20 per common unit on an annualized basis) to the extent we have sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to our general partner and its affiliates. Our ability to pay cash distributions at this initial distribution rate is subject to various restrictions and other factors described in more detail under the caption “Our Cash Distribution Policy and Restrictions on Distributions.”

		We will pay investors in this offering a prorated distribution for the first quarter during which we are a publicly traded partnership. Such distribution will cover the period from the closing date of this offering to and including March 31, 2008. We expect to pay this cash distribution on or about May 15, 2008.

		Our partnership agreement requires us to distribute all of our cash on hand at the end of each quarter, less reserves established by our general partner. We refer to this cash as “available cash,” and we define its meaning in our partnership agreement and in the glossary of terms attached as Appendix D. Our partnership agreement also requires that we distribute all of our available cash from operating surplus each quarter in the following manner:

		• first, 98% to the holders of common units and 2% to our general partner, until each common unit has received a minimum quarterly distribution of $0.30 plus any arrearages from prior quarters;

		• second, 98% to the holders of subordinated units and 2% to our general partner, until each subordinated unit has received a minimum quarterly distribution of $0.30; and

		• third, 98% to all unitholders, pro rata, and 2% to our general partner, until each unit has received a distribution of $0.345.

		If cash distributions to our unitholders exceed $0.345 per common unit in any quarter, our general partner will receive, in addition to distributions on its 2% general partner interest, increasing percentages, up to 50%, of the cash we distribute in excess of that amount. We refer to these distributions as “incentive distributions.” Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions.”

		The amount of pro forma available cash generated during the year ended December 31, 2006 would have been sufficient to allow us to pay approximately 55% of the minimum quarterly distribution on our common units, but no quarterly distributions on our subordinated units during that period. The amount of pro forma available cash generated during the twelve months ended September 30, 2007 would have been sufficient to allow us to pay approximately 81% of the minimum quarterly distribution on our our common units, but no quarterly distributions on our

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		subordinated units during that period. For a calculation of our ability to make distributions to unitholders based on our pro forma results for 2006 and the twelve months ended September 30, 2007, please read “Our Cash Distribution Policy and Restrictions on Distributions — Unaudited Pro Forma Cash Available for Distribution for the Year Ended December 31, 2006 and the Twelve Months Ended September 30, 2007.”

		We believe that, based on the estimates contained and the assumptions listed under the caption “Our Cash Distribution Policy and Restrictions on Distributions — Minimum Estimated Cash Available for Distribution for the Twelve-Month Period Ending March 31, 2009,” we will have sufficient cash available for distribution to make cash distributions for the four quarters ending March 31, 2009 at the initial distribution rate of $0.30 per common unit per quarter ($1.20 per common unit on an annualized basis) on all common units and subordinated units.

Subordinated units		Subsidiaries of NiSource will initially own all of our subordinated units. The principal difference between our common units and subordinated units is that in any quarter during the subordination period, holders of the subordinated units are entitled to receive the minimum quarterly distribution of $0.30 per unit only after the common units have received the minimum quarterly distribution plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. Subordinated units will not accrue arrearages. The subordination period will end on the first business day after we have earned and paid at least $0.30 on each outstanding limited partner unit and general partner unit for any three consecutive, non-overlapping four quarter periods ending on or after March 31, 2011. The subordination period also will end upon the removal of our general partner other than for cause if the units held by our general partner and its affiliates are not voted in favor of such removal.

		When the subordination period ends, all remaining subordinated units will convert into common units on a one-for-one basis, and the common units will no longer be entitled to arrearages. Please read “Provisions of Our Partnership Agreement Related to Cash Distributions — Subordination Period.”

Early conversion of subordinated units		Alternatively, the subordination period will end on the first business day after we have earned and paid at least $1.80 (150% of the annualized minimum quarterly distribution) on each outstanding limited partner unit and general partner unit for any four quarter period ending on or after March 31, 2009. Please read “Provisions of Our Partnership Agreement Related to Cash Distributions — Subordination Period.”

General Partner’s right to reset the target distribution levels		Our general partner has the right, at a time when there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled (48%) for each of the prior four consecutive fiscal quarters, to reset the initial cash target distribution levels at higher levels based on the

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		distribution at the time of the exercise of the reset election. Following a reset election by our general partner, the minimum quarterly distribution amount will be reset to an amount equal to the average cash distribution amount per common unit for the two fiscal quarters 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 the same percentage increases above the reset minimum quarterly distribution amount as in our current target distribution levels.

		In connection with resetting these target distribution levels, our general partner will be entitled to receive Class B units. The Class B units will be entitled to the same cash distributions per unit as our common units and will be convertible into an equal number of common units. The number of Class B units to be issued will be equal to that number of common units whose aggregate quarterly cash distributions equaled the average of the distributions to our general partner on the incentive distribution rights in the prior two quarters. For a more detailed description of our general partner’s right to reset the target distribution levels upon which the incentive distribution payments are based and the concurrent right of our general partner to receive Class B units in connection with this reset, please read “Provisions of Our Partnership Agreement Related to Cash Distributions — General Partner’s Right to Reset Incentive Distribution Levels.”

Issuance of additional units		We can issue an unlimited number of units without the consent of our unitholders. Please read “Units Eligible for Future Sale” and “The Partnership Agreement — Issuance of Additional Securities.”

Limited voting rights		Our general partner will manage and operate us. Unlike the holders of common stock in a corporation, you will have only limited voting rights on matters affecting our business. You 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 662/3% of the outstanding units, including any units owned by our general partner and its affiliates, voting together as a single class. Upon consummation of this offering, our general partner and its affiliates will own an aggregate of approximately 60.0% of our common and subordinated units. This will give NiSource the ability to prevent our general partner’s involuntary removal. 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 not less than the then-current market price of the common units.

Eligible Holders and redemptions		Only Eligible Holders will be entitled to receive distributions or be allocated income or loss from us. Eligible Holders are:

		• individuals or entities subject to United States federal income taxation on the income generated by us; or

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		• entities not subject to United States federal taxation on the income generated by us, so long as all of the entity’s owners are subject to such taxation.

		We have the right, which we may assign to any of our affiliates, but not the obligation, to redeem all of the common and subordinated units of any holder that is not an Eligible 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 lower 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-Citizen Assignees; 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, 2010, you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be % or less of the cash distributed to you with respect to that period. For example, if you receive an annual distribution of $1.20 per unit, we estimate that your average allocable federal taxable income per year will be no more than $ per unit. Please read “Material Tax Consequences — Tax Consequences of Unit Ownership — Ratio of Taxable Income to Distributions.”

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

Exchange listing		We intend to apply to list our common units on the New York Stock Exchange under the symbol “NIA.”

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Summary Historical and Pro Forma Financial and Operating Data

The following table shows (i) summary historical financial and operating data of Columbia Gulf and (ii) summary pro forma financial data of NiSource Energy Partners, L.P. for the periods and as of the dates indicated. The summary historical financial data of Columbia Gulf as of December 31, 2005 and 2006 and for the years ended December 31, 2004, 2005 and 2006 are derived from the historical audited financial statements of Columbia Gulf appearing elsewhere in this prospectus. The summary historical financial data for Columbia Gulf as of September 30, 2007 and for the nine months ended September 30, 2006 and 2007 are derived from the historical unaudited financial statements of Columbia Gulf appearing elsewhere in this prospectus. The table should also be read together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

The summary pro forma financial data of NiSource Energy Partners, L.P. for the year ended December 31, 2006, and as of and for the nine months ended September 30, 2007 are derived from the unaudited pro forma financial statements of NiSource Energy Partners, L.P. included elsewhere in this prospectus. The pro forma adjustments have been prepared as if certain transactions to be effected at the closing of this offering had taken place on September 30, 2007, in the case of the pro forma balance sheet, and as of January 1, 2006, in the case of the pro forma statements of operations for the year ended December 31, 2006, and for the nine months ended September 30, 2007. These transactions include:


	•	Columbia Gulf’s distribution of accounts receivable of $62.4 million to NiSource;

	•	Our receipt of $250.0 million in gross proceeds from the issuance and sale of 12,500,000 common units to the public;

	•	Our borrowing approximately $37.0 million in term debt and $163.0 million in revolving debt under our new $250.0 million credit facility;

	•	Our use of proceeds from this offering and related borrowings to pay transaction fees and expenses and underwriting commissions, retire assumed indebtedness, reimburse subsidiaries of NiSource for certain capital expenditures, make distributions to subsidiaries of NiSource, fund working capital and anticipated capital expenditures, and purchase qualifying investment grade securities; and

	•	The disposition of certain offshore assets currently owned by Columbia Gulf.

The following table includes the non-GAAP financial measure of EBITDA. We define our EBITDA as net income plus interest expense (net of a non-cash allowance for funds used during construction, or AFUDC), income taxes and depreciation and amortization, less interest income and other, net. For a reconciliation of EBITDA to its most directly comparable financial measures calculated and presented in accordance with GAAP, please read “— Non-GAAP Financial Measures.”


																NiSource Energy
																Partners, L.P. Pro Forma
	Columbia Gulf																		Nine Months
										Nine Months Ended						Year Ended			Ended
	Year Ended December 31,									September 30,						December 31,			September 30,
	2004			2005			2006			2006			2007			2006			2007
	(In millions, except per unit and operating data)

Statement of Operations Data:
Total operating revenues	$	127.0		$	116.1		$	123.3		$	90.8		$	99.6		$	117.3		$	94.5
Operating expenses:
Operation and maintenance		55.7			51.3			61.2			41.2			44.4			55.1			38.4
Depreciation and amortization		23.2			22.2			22.0			16.5			16.4			19.1			14.8
Other taxes		7.8			8.5			8.1			6.0			6.2			8.1			6.2

Total operating expenses		86.7			82.0			91.3			63.7			67.0			82.3			59.4

Operating income		40.3			34.1			32.0			27.1			32.6			35.0			35.1

Other income (deductions):
Interest expense (net of AFUDC)		(5.4	)		(5.0	)		(2.7	)		(2.2	)		(1.8	)		(15.2	)		(10.7	)
Interest income		0.4			0.6			0.5			0.5			—			1.5			0.8
Other, net		—			0.5			0.7			0.7			—			0.7			—
Income taxes		(13.1	)		(11.7	)		(12.2	)		(9.2	)		(10.7	)		(0.1	)		(0.1	)

Net income	$	22.2		$	18.5		$	18.3		$	16.9		$	20.1		$	21.9		$	25.1

Net income per limited partners’ unit
Common unit																$	1.02		$	0.90
Subordinated unit																	—			0.55

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											NiSource Energy
											Partners, L.P. Pro Forma
	Columbia Gulf												Nine Months
							Nine Months Ended				Year Ended		Ended
	Year Ended December 31,						September 30,				December 31,		September 30,
	2004		2005		2006		2006		2007		2006		2007
	(In millions, except per unit and operating data)

Balance Sheet Data (at period end):
Total Assets			$	716.0	$	763.1			$	783.3			$	841.2
Net property plant and equipment				305.5		310.6				321.5				321.5
Long-term debt-affiliated, excluding amounts due within one year				67.9		67.9				67.9				265.9
Total capitalization				552.6		556.1				576.2				701.8
Other Financial Data:
Net cash provided by operating activities	$	45.3	$	51.0	$	40.1	$	26.7	$	20.0	$	43.7	$	25.0
EBITDA		63.5		56.3		54.0		43.6		49.0		54.1		49.9
Maintenance capital expenditures(1)		7.0		31.4		22.2		13.2		11.6		22.2		11.6
Expansion capital expenditures(1)		—		0.1		2.9		1.1		10.5		2.9		10.5
Columbia Gulf Operating Data:
Mainline:
Transportation capacity (Bcf/d)(2)		2.156		2.156		2.156		2.156		2.156
Contracted firm capacity (Bcf/d)(3)		2.453		2.177		2.266		2.245		2.471
Transported volumes (Bcf)		523.6		506.7		519.7		392.3		477.4
Laterals (East and West):
Transportation capacity (Bcf/d)(4)		2.157		2.157		2.157		2.157		2.157
Contracted firm capacity (Bcf/d)		0.616		0.589		0.680		0.634		0.870
Transported volumes (Bcf)		428.9		422.1		379.7		291.3		247.6


(1)		Maintenance capital expenditures are capital expenditures made to replace partially or fully depreciated assets, to maintain the existing operating capacity of our assets and to extend their useful lives, or other capital expenditures that are incurred in maintaining existing system volumes and related cash flows. Expansion capital expenditures are made to acquire additional assets to grow our business, to expand and upgrade our systems and facilities, and to construct or acquire similar systems or facilities. This includes projects designed to reduce costs or enhance revenues.

(2)		Represents one-way peak-design capacity from Rayne, Louisiana to Leach, Kentucky.

(3)		Our contracted firm capacity exceeds our one-way peak-design capacity during the indicated periods as a result of our ability to transport natural gas in multiple directions on our pipeline system.

(4)		Represents the maximum combined peak-design capacity of the two laterals — East (1.054 Bcf/d) and West (1.103 Bcf/d).

Non-GAAP Financial Measures

We define our EBITDA as net income plus interest expense (net of AFUDC), income taxes and depreciation and amortization, less interest income and other, net. EBITDA is used as a supplemental financial measure by management and by external users of our financial statements, such as investors and commercial banks, to assess:


	•	the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;

	•	the ability of our assets to generate cash sufficient to pay interest on our indebtedness and to make distributions to our partners; and

	•	our operating performance and return on invested capital as compared to those of other publicly traded limited partnerships that own energy infrastructure assets, without regard to their financing methods and capital structure.

EBITDA should not be considered an alternative to net income, operating income, net cash provided by operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. EBITDA excludes some, but not all, items that affect net income and operating income and these

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measures may vary among other companies. Therefore, EBITDA as presented may not be comparable to similarly titled measures of other companies.

The following tables present reconciliations of the non-GAAP financial measure of EBITDA to the respective GAAP financial measures of net income and net cash provided (used) by operating activities on a historical basis and on a pro forma basis as adjusted for this offering.


															NiSource Energy Partners, L.P.
															Pro Forma
	Columbia Gulf																	Nine Months
									Nine Months Ended						Year Ended			Ended
	Year Ended December 31,								September 30,						December 31,			September 30,
	2004		2005			2006			2006			2007			2006			2007
	(In millions)

Reconciliation of Non-GAAP
“EBITDA” to GAAP “Net income”
Net income	$	22.2	$	18.5		$	18.3		$	16.9		$	20.1		$	21.9		$	25.1
Add:
Interest expense (net of AFUDC)		5.4		5.0			2.7			2.2			1.8			15.2			10.7
Income taxes		13.1		11.7			12.2			9.2			10.7			0.1			0.1
Depreciation and amortization		23.2		22.2			22.0			16.5			16.4			19.1			14.8
Less:
Interest income		0.4		0.6			0.5			0.5			—			1.5			0.8
Other, net		—		0.5			0.7			0.7			—			0.7			—

EBITDA	$	63.5	$	56.3		$	54.0		$	43.6		$	49.0		$	54.1		$	49.9

Reconciliation of Non-GAAP
“EBITDA” to GAAP “Net cash provided by operating activities”
Net cash provided by operating activities	$	45.3	$	51.0		$	40.1		$	26.7		$	20.0		$	43.7		$	25.0
Less:
Interest income		0.4		0.6			0.5			0.5			—			1.5			0.8
Add:
Interest expense (net of AFUDC)		5.4		5.0			2.7			2.2			1.8			15.2			10.7
Income taxes paid		10.3		10.7			9.4			9.2			10.0			0.1			0.1
Other		1.0		1.1			(4.3	)		(5.1	)		(2.8	)		(10.0	)		(5.1	)
Changes in operating working capital		1.9		(10.9	)		6.6			11.1			20.0			6.6			20.0

EBITDA	$	63.5	$	56.3		$	54.0		$	43.6		$	49.0		$	54.1		$	49.9

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RISK FACTORS

Limited partner interests are inherently different from capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in similar businesses. You should consider carefully 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 actually to occur, our business, financial condition, results of operations and cash flows 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 Related to Our Business

We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our general partner, to enable us to make cash distributions to holders of our common units and subordinated units at the initial distribution rate under our cash distribution policy.

In order to make cash distributions at our initial distribution rate of $0.30 per common unit per complete quarter, or $1.20 per unit per year, we will require available cash of approximately $9.6 million per quarter, or $38.3 million per year, based on the number of common units and subordinated units outstanding immediately after completion of this offering, whether or not the underwriters exercise their option to purchase additional common units. 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 transportation services, the volume of capacity under contract and the volumes of natural gas our customers transport;

	•	the demand for natural gas in the markets served by our system and the quantities of natural gas available for transport on our system;

	•	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, our operating costs and our operating flexibility;

	•	the imposition of requirements by state agencies that materially reduce the demand of our customers, such as local distribution companies and power generators, for our pipeline services;

	•	the commodity price of natural gas, which could reduce the quantities of natural gas available for transport if prolonged low natural gas prices cause diminished natural gas exploration and production activity in specific regions of the United States, particularly on the Gulf Coast and in the Gulf of Mexico;

	•	the creditworthiness of our customers — if a customer files for bankruptcy protection, there is no assurance we will be kept whole for the revenue that would have been realized had the contract been honored for its entire term;

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

	•	the level of capital expenditures we incur to maintain our assets;

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

	•	successful development of LNG import terminals in the eastern or northeastern United States, which could reduce the need for natural gas to be transported on the Columbia Gulf pipeline system.

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In addition, the actual amount of cash we will have available for distribution will depend on other factors, some of which are beyond our control, including:


	•	unanticipated required capital expenditures;

	•	our debt service requirements and other liabilities;

	•	fluctuations in our working capital needs;

	•	our ability to borrow funds and access capital markets;

	•	restrictions on distributions contained in our debt agreements; and

	•	the amount of cash reserves established by our general partner.

For a description of additional restrictions and factors that may affect our ability to make cash distributions, please read “Our 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, 2006 and the twelve months ended September 30, 2007, respectively.

The amount of available cash we need to pay the minimum quarterly distribution for four quarters on all of our units to be outstanding immediately after this offering is approximately $38.3 million. The amount of pro forma available cash generated during the year ended December 31, 2006 would have been sufficient to allow us to pay approximately 55% of the minimum quarterly distributions on our common units, but it would not have been sufficient to allow us to pay any distributions on our subordinated units during that period. The amount of pro forma available cash generated during the twelve months ended September 30, 2007 would have been sufficient to allow us to pay approximately 81% of the minimum quarterly distribution on our common units, but no quarterly distributions on our subordinated units during that period. For a calculation of our ability to make distributions to unitholders based on our pro forma results for 2006 and the twelve months ended September 30, 2007, please read “Our Cash Distribution Policy and Restrictions on Distributions.”

The assumptions underlying our minimum estimated cash available for distribution we include in “Our Cash Distribution Policy and Restrictions on Distributions” are inherently uncertain and are subject to significant business, economic, financial, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those estimated.

Our estimate of cash available for distribution set forth in “Our Cash Distribution Policy and Restrictions on Distributions” has been prepared by management and we have not received an opinion or report on it from our or any other independent auditor. The assumptions underlying this estimate are inherently uncertain and are subject to significant business, economic, financial, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those assumed. For example, as discussed in “— Minimum Estimated Cash Available for Distribution for the Twelve-Month Period Ending March 31, 2009,” we expect to incur approximately $24.1 million of maintenance capital expenditures for the twelve months ending March 31, 2009, $8.5 million of which we expect to be recurring in nature. While we believe our assumption regarding the amount of recurring maintenance capital expenditures is reasonable, we have incurred total annual maintenance capital expenditures in amounts significantly in excess of $8.5 million per year in the past, including $22.2 million of total maintenance capital expenditures in 2006 and $31.4 million of total maintenance capital expenditures in 2005. If our future maintenance capital expenditures are higher than expected, our anticipated results could be adversely impacted. If we do not achieve our anticipated results, we may not be able to pay the full minimum quarterly distribution or any amount on our common units or subordinated units, in which event the market price of our common units may decline materially.

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The amount of cash we have available for distribution to holders of our common units and subordinated 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.

You should be aware that the amount of cash we have available for distribution depends primarily upon our cash flow, including cash flow from financial 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 make cash distributions during periods when we record net losses for financial accounting purposes and may not make cash distributions during periods when we record net earnings for financial accounting purposes.

Our natural gas transportation operations are subject to regulation by the FERC, which could have an adverse impact on our ability to establish transportation rates that would allow us to recover the full cost of operating our pipelines, including a reasonable return, and our ability to make distributions to you.

Our interstate natural gas transportation operations are subject to federal, state and local regulatory authorities. Specifically, our natural gas pipeline system is subject to regulation by the FERC under the Natural Gas Act of 1938 (NGA). The federal regulation extends to such matters as:


	•	transportation of natural gas;

	•	rates, operating terms and conditions of service;

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

	•	construction of new facilities;

	•	acquisition, extension or abandonment of services or facilities;

	•	accounts and records;

	•	commercial relationships and communications with affiliated companies involved in certain aspects of the natural gas business; and

	•	the initiation and discontinuation of services.

We may only charge rates that we have been authorized to charge by the FERC. In addition, the FERC prohibits natural gas companies from unduly preferring or unreasonably discriminating against any person with respect to pipeline rates or terms and conditions of service.

The maximum recourse rates that may be charged by our pipeline for its transportation services are established through the FERC’s ratemaking process, and those recourse rates, as well as the terms and conditions of service, are set forth in our FERC-approved tariff. Pursuant to the FERC’s jurisdiction over rates, existing rates may be challenged by complaint, proposed rate increases may be challenged by protest, and either may be challenged sua sponte by the FERC. Any successful challenge against our rates could have an adverse impact on our revenues associated with providing transportation services. Generally, the maximum filed recourse rates for interstate pipelines are based on the cost of service plus an approved return on equity, which may be determined through the use of a proxy group of similarly situated companies. On July 19, 2007, the FERC issued a proposed policy statement addressing the issue of the proxy groups it will use to decide the return on equity of natural gas pipelines. The FERC uses a discounted cash flow model that incorporates the use of proxy groups to develop a range of reasonable returns earned on equity interests in companies with corresponding risks. The FERC then assigns a rate of return on equity within that range to reflect specific risks of that pipeline when compared to the proxy group companies. The proposed policy statement describes the FERC’s intention to allow the use of master limited partnerships in proxy groups, with certain restrictions, which could lower the return that would otherwise be allowed. The FERC has requested comments on the proposed policy. Please read “Business — FERC Regulation — FERC Policy Statement on Proxy Groups for Rates of Return Determinations.” Other key determinants in the ratemaking process are costs of providing service, including an income tax allowance, allowed rate of return and volume throughput and contractual capacity commitment assumptions. The allowed rate of return must be approved by the FERC as part of the resolution of each rate case. The maximum applicable recourse rates and terms and conditions for service are

19

found in each pipeline’s FERC-approved tariff. Rate design and the allocations of costs can also impact a pipeline’s profitability. Our interstate pipelines may also use “negotiated rates” which, in theory, could involve rates above or below the “recourse rate.” A prerequisite for having the right to agree to negotiated rates is that the negotiated rate customers must have had the option to take service under the pipeline’s maximum recourse rates.

Finally, we cannot give any assurance regarding the likely future regulations under which we will operate our natural gas transportation business or the effect such regulation could have on our business, financial condition, results of operations and ability to make distributions to you.

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

Should we fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines. Under the Energy Policy Act of 2005, the FERC has civil penalty authority under the NGA to impose penalties for current 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. Columbia Gulf and Columbia Gas Transmission are currently cooperating with the FERC on an informal non-public investigation in connection with an audit initiated in 2003 that covers a period beginning in 1999 that evaluates whether Columbia Gulf and Columbia Gas Transmission properly followed the FERC’s regulations. We cannot predict what the result of that audit will be, but the FERC has indicated that it may seek to impose penalties under the NGPA. Please read “Business — FERC Regulation.”

The outcome of certain rate cases involving the FERC policy statements is uncertain and could affect the amount of any allowance our system can include for income taxes in establishing its rates for service, which would in turn impact our revenues.

In May 2005, the FERC issued a policy statement permitting the inclusion of an income tax allowance in the cost of service-based rates of a pipeline organized as a tax pass through entity to reflect actual or potential income tax liability on public utility income, if the pipeline proves that the ultimate owner of its interests has an actual or potential income tax liability on such income. The policy statement also provides that whether a pipeline’s owners have such actual or potential income tax liability will be reviewed by the FERC on a case-by-case basis. In August 2005, the FERC dismissed requests for rehearing of its new policy statement. On December 16, 2005, the FERC issued its first significant case-specific review of the income tax allowance issue in another pipeline partnership’s rate case. The FERC reaffirmed its new income tax allowance policy and directed the subject pipeline to provide certain evidence necessary for the pipeline to determine its income tax allowance. The new tax allowance policy and the December 16, 2005 order were appealed to the United States Court of Appeals for the District of Columbia Circuit (the D.C. Circuit). The D.C. Circuit issued an order on May 29, 2007 in which it denied these appeals and upheld on all points subject to appeal the FERC’s new tax allowance policy and the application of that policy in the December 16, 2005 order. The D.C. Circuit denied rehearing of the May 29, 2007 decision on August 20, 2007. The period for appeals has now passed.

On December 8, 2006, the FERC issued another order addressing a permissible allowance for income taxes in rates. In that order, the FERC refined its income tax allowance policy, and notably raised a new issue regarding the implication of the policy statement for publicly traded partnerships. It noted that the tax deferral features of a publicly traded partnership may cause some investors to receive, for some indeterminate duration, cash distributions in excess of their taxable income, which the FERC characterized as a “tax savings.” The FERC stated that it is concerned that this created an opportunity for those investors to earn an additional return, funded by ratepayers. Responding to this concern, the FERC chose to adjust the pipeline’s equity rate of return downward based on the percentage by which the publicly traded partnership’s cash flow exceeded taxable income. On February 7, 2007, the pipeline asked the FERC to reconsider this ruling.

The ultimate outcome of these proceedings is not certain and could result in changes to the FERC’s treatment of income tax allowances in cost of service. Depending upon how the policy statement on income tax allowances is applied in practice to pipelines organized as pass through entities, these decisions might adversely affect us. Under the FERC’s current income tax allowance policy, if our FERC-regulated pipeline

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was to file a rate case or its rates were to otherwise become subject to review for justness and reasonableness before the FERC, we would be required to demonstrate that the equity interest owners in our pipeline incur actual or potential income tax liability on their respective shares of partnership public utility income. While we have established the Eligible Holder certification requirement, we can provide no assurance that such certification will be effective to establish that our unitholders, or our unitholders’ owners, are subject to United States federal income taxation on the public utility income generated by us or the applicable tax rate that should apply to such unitholders. If we are unable to do so, the FERC could decide to reduce our rates from current levels. We can give no assurance that in the future the FERC’s current income tax allowance policy or its application will not change.

The recent rupture of one of our pipelines near Delhi, Louisiana could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to you.

On December 14, 2007, one of the three trunklines (Line 100) comprising our Mainline System suffered a rupture near Delhi, Louisiana that resulted in one death, one other person injured and damage to nearby property. As a result of the rupture, an 8.8 mile section of Line 100 has been taken out of service indefinitely. As a precautionary measure, the other two trunklines (Lines 200 and 300) were also temporarily taken out of service for integrity assessment. Following this assessment, Lines 300 and 200 were placed back in service on December 14 and December 15, 2007, respectively.

The cause of the rupture has not been determined at this time. We are cooperating with the Pipeline and Hazardous Materials Safety Administration (PHMSA) in connection with an investigation of the incident. On December 19, 2007, we received a corrective action order from PHMSA under which (i) we may not resume operation of the 8.8 mile section of Line 100 where the rupture occurred until we prepare, and PHMSA approves, a written restart plan, (ii) the operating pressure on Line 100 from Rayne, Louisiana to Corinth, Mississippi may not exceed 80% of the actual operating pressure in effect immediately prior to the incident without the approval of PHMSA, (iii) we are required to complete certain testing analysis of the failed pipe within 30 days, and (iv) we are required to develop and submit to PHMSA for approval a remedial work plan within 60 days.

While we currently cannot quantify the total financial impact this rupture may have on our business, results of operations and financial condition, which impact could be material, we expect to incur approximately $1.0 million of capital expenditures in the fourth quarter of 2007 for the replacement of pipe on Line 100 and approximately $1.0 million in integrity assessment expenses related to the inspection of Line 100 in the first quarter of 2008. These estimates do not include the capital costs, if any, for major replacement, repair, remediation, preventative or mitigating actions that may be determined to be necessary as a result of the testing of Line 100 or any other lines. In addition, any remedial actions PHMSA may require us to take under the remedial work plan contemplated by the December 19th corrective action order, or in response to other corrective action orders, notices of probable violation or other findings issued by PHMSA, or any fines assessed by PHMSA with respect to this incident, could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to you. This incident could also result in actions by other governmental agencies, including fines or orders impacting our operations. Other adverse impacts of this event could include lawsuits from private individuals for damages to person or property (to the extent not covered by insurance), increased insurance costs, increased costs associated with any resulting acceleration of the integrity testing of other sections of our pipeline system, and expenses associated with our internal investigation of the incident and our response to governmental investigations or proceedings.

A significant delay in returning Line 100 to service could also have a material adverse impact on our revenues and our ability to satisfy the requirements of our customers. Further, if we are required to operate a portion of our pipelines at a reduced pressure for a significant period of time, our revenues and ability to satisfy the requirements of our customers may be adversely impacted. In addition, if the investigation regarding the cause of this incident or any steps taken under the remedial work plan contemplated by the December 19th corrective action order identify any further necessary repairs or other remediation steps, we

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may be required to remove Line 100 or other portions of our pipeline system from service and/or operate them at a lower pressure for an extended period of time.

Certain of our transportation 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, and, as a result, our costs could exceed our revenues received under 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 “recourse rate” for that service, and that contract must be filed and accepted by the FERC. For the nine months ended September 30, 2007, approximately 4.7% of our transportation revenues were derived from such “negotiated rate” contracts. 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, representing the difference between “recourse rates” (if higher) and negotiated rates, under current FERC policy is generally not recoverable from other customers. It is possible that our costs to perform services under these “negotiated rate” contracts will exceed the negotiated rates. If this occurs, it could decrease our cash flow.

Increased competition from alternative natural gas transportation options and alternative fuel sources could have a significant financial impact on us.

We compete primarily with other interstate and intrastate pipelines in the transportation of natural gas. Some of our competitors have greater financial resources and access to greater supplies of natural gas than we do. Some of these competitors may expand or construct transportation systems that would create additional competition or reduce demand for the services we provide to our customers. Moreover, NiSource and its affiliates are not limited in their ability to compete with us. Further, natural gas also competes with other forms of energy available to our customers, including electricity, coal and fuel oils.

The principal elements of competition among natural gas transportation assets are rates, terms of service, access to natural gas supplies, flexibility and reliability. The FERC’s policies promoting competition in natural gas markets are having the effect of increasing the natural gas transportation options for our traditional customer base. As a result, as existing agreements expire we may be unable to re-market this capacity. If we are unable to remarket this capacity or can remarket it only at substantially discounted rates compared to previous contracts, we may have to bear the costs associated with the turned back capacity. Increased competition could reduce the volumes of natural gas transported by our systems or, in cases where we do not have long-term fixed rate contracts, could force us to lower our transportation rates. Competition could intensify the negative impact of factors that significantly decrease demand for natural gas in the markets served by our pipeline systems, such as competing or alternative forms of energy, a recession or other adverse economic conditions, weather, higher fuel costs and taxes or other governmental or regulatory actions that directly or indirectly increase the cost or limit the use of natural gas. Our ability to renew or replace existing contracts at rates sufficient to maintain current revenues and cash flows could be adversely affected by the activities of our competitors. All of these competitive pressures could have a material adverse effect on our business, financial condition, results of operations, and ability to make distributions to you.

We may not be able to maintain or replace expiring natural gas transportation contracts at favorable rates.

Our primary exposure to market risk occurs at the time our existing transportation contracts expire and are subject to renegotiation and renewal. As of September 30, 2007, the average remaining contract life (based on contracted revenues) of our firm transportation contracts was approximately 3.8 years with respect to our Mainline System and 2.5 years with respect to the Louisiana Laterals. Approximately 21.3% and 35.0% of the revenue we generated for the nine months ended September 30, 2007 is attributable to firm capacity reservation fees received under transportation contracts that are set to expire in 2008 and 2009, respectively. Upon expiration, we may not be able to extend contracts with existing customers or obtain replacement contracts at favorable rates or on a long-term basis.

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The extension or replacement of existing contracts depends on a number of factors beyond our control, including:


	•	the level of existing and new competition to deliver natural gas to our markets;

	•	changes in demand for natural gas in our markets;

	•	whether the market will continue to support long-term contracts; and

	•	the effects of state regulation on customer contracting practices.

Any failure to extend or replace a significant portion of our existing contracts may increase the volatility of our cash flows and have a material adverse effect on our business, financial condition, results of operations and ability to make distributions to you.

Any significant decrease in supplies 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. Low prices for natural gas or regulatory limitations could adversely affect development of additional reserves and production that is accessible by our pipeline assets. Production from existing wells and natural gas supply basins with access to our pipelines will naturally decline over time. Additionally, 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. Accordingly, to maintain or increase the volume of natural gas transported, or throughput, on our pipelines and cash flows associated with the transportation of gas, our customers must continually obtain new supplies of natural gas.

If new supplies of natural gas are not obtained to replace the natural decline in volumes from existing supply basins, the overall volume of natural gas transported on our pipelines would decline, which could have a material adverse effect on our business financial condition, results of operations and ability to make distributions to you.

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 revenues. Our three largest customers for the year ended December 31, 2006 were Columbia Gas of Ohio Inc. (a subsidiary of NiSource), Washington Gas Light Company and Baltimore Gas & Electric Company. Contracts with these customers accounted for approximately 13.1%, 9.1% and 7.0% of our contracted revenues, respectively, during 2006. Our three largest customers for the nine months ended September 30, 2007 were Columbia Gas of Ohio, Inc., Washington Gas Light Company and BG Energy Merchants, LLC. Contracts with these customers accounted for approximately 11.6%, 8.2% and 7.5% of our contracted revenues, respectively, for the nine months ended September 30, 2007. 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, involves numerous regulatory, environmental, political and legal uncertainties beyond our control and may require the expenditure of significant amounts of capital. If we undertake these projects they may not be completed on schedule, or at

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the budgeted cost, or completed 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 for demand for our services in a region in which such growth does not materialize. 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 rights-of-way, and it may become more expensive for us to obtain 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.

We face significant hurdles in making acquisitions on economically favorable terms that will enable us to increase our distributions to unitholders. In addition, NiSource and its affiliates have no obligation to present us with, and are not restricted from competing with us for, potential acquisitions.

We intend to expand our current business by pursuing joint ventures, partnerships and acquisitions that are accretive to distributable cash flow. Our ability to achieve this strategy is subject to a number of hurdles beyond our control, including the following:


	•	NiSource and its affiliates have no obligation to offer us the opportunity to purchase from them assets they currently own or acquire in the future;

	•	NiSource and its affiliates may face legal or business hurdles in contributing or selling assets to us. For example, the tax efficiency of selling suitable assets to us may influence NiSource’s willingness or the timing of its decision to transfer those assets to us;

	•	We will rely on NiSource and its affiliates to identify and evaluate for us prospective assets or businesses for acquisition. NiSource and its affiliates are not obligated to present us with acquisition opportunities and are permitted under our partnership agreement to take these opportunities for themselves. Because NiSource controls our general partner, we will not be able to pursue or consummate any acquisition opportunity unless NiSource causes us to do so;

	•	NiSource and its affiliates will not be restricted under our partnership agreement or the omnibus agreement or any other agreement from owning assets or engaging in business that compete directly or indirectly with us. NiSource is a large, established participant in the energy business, and has significantly greater resources and experience than we have, which may make it difficult for us to compete with them;

	•	Even if NiSource and its affiliates offer us an opportunity to buy assets from them or from third parties, we may not be able to consummate any such acquisition for several reasons, including an inability to agree on acceptable purchase terms, an inability to obtain financing for the purchase on acceptable terms, the lack of required regulatory approvals, and applicable restrictions in credit facilities, indentures or other contracts; and

	•	We may be outbid by competitors for third party assets.

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

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


	•	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;

	•	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;

	•	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 integrate successfully the businesses we build or acquire;

	•	limitations on rights to indemnity from the seller of an acquired business;

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

	•	unforeseen difficulties operating in new product areas or new geographic areas; and

	•	customer or key employee losses at the acquired business.

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.

Significant prolonged changes in natural gas prices could affect supply and demand, reducing demand for capacity reservations and throughput on our pipeline system and adversely affecting our revenues and cash available to make distributions to you over the long-term.

Higher natural gas prices over the long-term could result in a decline in the demand for natural gas and, therefore, in the demand for capacity reservations and throughput on our pipeline system. Also, lower natural gas prices over the long-term could result in a decline in the production of natural gas resulting in reduced demand for capacity reservations and throughput on our system. As a result, significant prolonged changes in natural gas prices could have a material adverse effect on our financial condition, results of operations and ability to make distributions to you.

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

Our natural gas transportation activities are subject to stringent and complex federal, state and local environmental laws and regulations. We may incur substantial costs in order to conduct our operations in compliance with these laws and regulations. For instance, we may be required to obtain and maintain permits and other approvals issued by various federal, state and local governmental authorities; limit or prevent releases of materials from our operations in accordance with these permits and approvals; install pollution control equipment; and incur potentially substantial liabilities for any pollution or contamination that may result from our operations. Moreover, new, stricter environmental laws, regulations or enforcement policies could be implemented that significantly increase our compliance costs or the cost of any remediation of environmental contamination that may become necessary, and these costs could be material.

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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 obligations and the issuance of injunctions limiting or preventing some or all of our operations. In addition, strict joint and several liability 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 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 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.

We currently estimate that we will incur costs of approximately $1.3 million annually between 2008 and 2012 for the required initial assessment of our pipeline and minor remediation along our pipeline to implement pipeline integrity management program testing along certain segments of our pipeline system. In addition, we currently anticipate we will incur capital costs of approximately $3.8 million for the twelve months ended March 31, 2009 for facility upgrades to facilitate ongoing annual pipeline integrity testing. 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. Any additional regulatory requirements that are enacted could significantly increase the amount of these expenditures. Additionally, our actual implementation costs may be materially higher than we estimate if the increased industry-wide demand for the associated contractors and service providers causes their rates to materially increase. Should we fail to comply with DOT regulations, we could be subject to penalties and fines. Please read “Business — Safety and Maintenance” for more information.

We may incur significant costs from time to time in order to comply with DOT regulations regarding the pipe wall thickness of our pipelines if the population density near any particular portion of our pipelines increases beyond specified levels.

DOT regulations govern the pipe wall thickness of our pipelines. The required thickness of the pipe wall 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 thicker pipe unless a waiver from the DOT is obtained. For example, beginning in 2005, we commenced the upgrading of certain portions of our pipeline located near Nashville, Tennessee. From January 1, 2005 through September 30, 2007, we incurred $16.6 million of expenses relating to this upgrade. For more information regarding the upgrading of our pipeline located near Nashville, Tennessee, please read “Business — Safety and Maintenance.” While the majority of our pipelines are located in remote areas, the possibility exists that we could be required to incur

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significant expenses in the future in response to similar increases in population density near other sections of our pipelines.

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 have been constructed, 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. For example, certain levee construction in Mississippi across our right-of-way is expected to result in pipe relocation capital expenditures of $6.8 million in 2009. 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.

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


	•	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 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. Please read “— The recent rupture of one of our pipelines near Delhi, Louisiana could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to you.” A natural disaster or other hazard affecting the areas in which we operate could have a material adverse effect on our operations.

Our debt levels may limit our flexibility in obtaining additional financing and in pursuing other business opportunities.

At the closing of this offering we expect to borrow approximately $37.0 million in term debt and $163.0 million in revolving debt under our new $250.0 million credit facility. Following this offering, we will continue to have the ability to incur additional debt, subject to limitations in our credit facility. Our level of debt could have important consequences to us, including the following:


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

	•	we will need a substantial portion of our cash flow to make principal and interest payments on our indebtedness, reducing the funds that would otherwise be available for operations, future business opportunities and distributions to unitholders; 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.

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Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. 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 the credit facility we will enter into in connection with this offering may interrupt distributions to us from our subsidiaries, which will limit our ability to make distributions to you and may limit our ability to capitalize on acquisition and other business opportunities.

We are a holding company with no business operations. As such, we depend upon the earnings and cash flow of our subsidiaries and the distribution of that cash to us in order to meet our obligations and to allow us to make distributions to our unitholders. Our new credit facility may contain covenants limiting our ability to make distributions to our unitholders. Additionally, the operating and financial restrictions and covenants in our credit facility and any future financing agreements may restrict our ability to finance future operations or capital needs or to expand or pursue our business activities. For example, our credit facility will contain covenants, some of which may be modified or eliminated upon our receipt of an investment grade rating, that may restrict or limit our ability to:


	•	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;

	•	make any material change to the nature of our business from the midstream energy business;

	•	make a disposition of assets; or

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

Furthermore, our credit facility will contain covenants requiring us to maintain certain financial ratios and tests. Our 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 to comply with these covenants may be impaired. If we violate 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 our operating partnership 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 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.

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The credit and risk profile of our general partner and its owner, NiSource, 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 may be factors considered in credit evaluations of us. This is because our general partner controls our business activities, including our cash distribution policy and acquisition strategy and business risk profile. Another factor that may be considered is the financial condition of NiSource, 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 the leverage of our general partner or NiSource, 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 its affiliates because of their ownership interest in and control of us and the strong operational links between NiSource 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, as of September 30, 2007, our pipelines interconnect with 29 interstate pipelines and 13 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 to the facility, 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 caused 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.

Some of the pipelines in the Columbia Gulf pipeline system are more than 50 years old, which may adversely affect our business, results of operations, financial condition and our ability to make distributions to you.

Some portions of the pipelines in the Columbia Gulf pipeline system are more than 50 years old. The current age of these sections could result in a material adverse impact on our business, financial condition and results of operations and on our ability to make distributions to you if their age contributes to unanticipated maintenance expenditures.

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

We may not realize expected increases in future natural gas supply from LNG imports for transportation on our pipelines 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 expansion of existing, LNG facilities outside our areas of operations could reduce the need for customers to transport natural gas from the Gulf Coast region, as well as

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other supply basins connected to our pipelines. This could reduce the amount of natural gas transported by our pipeline.

Terrorist attacks, and the threat of terrorist attacks, could result in increased costs to our business. Continued hostilities in the Middle East or other sustained military campaigns may adversely impact our results of operations.

The long-term impact of terrorist attacks and the threat of future terrorist attacks on our industry in general, and on us in particular, is not known at this time. However, the United States government has issued warnings that energy assets, including our nation’s pipeline infrastructure, may be the future target of terrorist organizations. Uncertainty surrounding continued hostilities in the Middle East or other sustained military campaigns may affect our operations in unpredictable ways, including the possibility that infrastructure facilities could be direct targets of, or indirect casualties of, an act of terror. Any terrorist attack on our facilities or pipelines or those of our customers could have a material adverse effect on our business.

Changes in the insurance markets attributable to terrorist attacks may make certain types of insurance more difficult for us to obtain. Moreover, the insurance that may be available to us may be significantly more expensive than our existing insurance coverage. Instability in the financial markets as a result of terrorism or war could also affect our ability to raise capital.

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

Prior to this offering, Columbia Gulf was wholly-owned by NiSource and we have not previously filed reports with the SEC. We will become subject to the public reporting requirements of the Securities Exchange Act of 1934 upon the completion of this offering. We produce our financial statements in accordance with the requirements of GAAP, but our internal accounting controls may not currently meet all standards applicable to companies with publicly traded securities. Effective internal controls are necessary for us to provide reliable financial reports to prevent fraud and to operate successfully as a publicly traded partnership. Our efforts to develop and maintain our internal controls may not be successful, and we may be unable to maintain adequate controls over our financial processes and reporting in the future, including compliance with the obligations under Section 404 of the Sarbanes-Oxley Act of 2002, which we refer to as Section 404. For example, Section 404 will require us, among other things, annually to review and report on, and our independent registered public accounting firm annually to attest to, our internal control over financial reporting. Any failure to develop or maintain effective controls, or difficulties encountered in their implementation or other effective improvement of our internal controls could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls subject us to regulatory scrutiny and a loss of confidence in our reported financial information, which could have an adverse effect on our business and would likely have a negative effect on the trading price of our common units.

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 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 capacity during and after insolvency proceedings involving a customer.

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Risks Inherent in an Investment in Us

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

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


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

	•	our general partner is allowed to take into account the interests of parties other than us, such as NiSource and its affiliates, in resolving conflicts of interest;

	•	NiSource will own a 2% general partner interest, the incentive distribution rights and common and subordinated units representing a combined 58.9% limited partner interest in us, and if a vote of limited partners is required, NiSource will be entitled to vote its units in accordance with its own interests, which may be contrary to our interests;

	•	NiSource and its affiliates are not limited in their ability to compete with us and are not obligated to offer us business opportunities or to offer to contribute or sell additional assets or operations to us. Please read “— Affiliates of NiSource are not limited in their ability to compete with us, which could limit our commercial activities or our ability to acquire additional assets or businesses”;

	•	our general partner may make a determination to receive a quantity of our Class B units in exchange for resetting the target distribution levels related to its incentive distribution rights without the approval of the conflicts committee of our general partner or our unitholders. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions — General Partner’s Right to Reset Incentive Distribution Levels”;

	•	all of the executive officers and certain of the directors of our general partner are also officers and/or directors of NiSource, and these persons will also owe fiduciary duties to NiSource;

	•	the officers of NiSource who provide services to us also will devote significant time to the business of NiSource, and will be compensated by NiSource for the services rendered to it;

	•	our general partner has limited its liability and reduced its fiduciary duties, and has also restricted the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty. By purchasing common units, unitholders will be deemed to have consented to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable law;

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

	•	our general partner determines the amount and timing of any capital expenditures and, based on the applicable facts and circumstances, whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not

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		reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders and the ability of the subordinated units to convert to common units;


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

	•	in some instances, 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;

	•	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 any of these entities on our behalf;

	•	our partnership agreement permits us to classify up to $ as operating surplus, even if it is generated from assets sales, non-working capital borrowings or other sources, the distribution of which would otherwise constitute capital surplus. This cash may be used to fund distributions on our subordinated units or to our general partner in respect of the general partner interest or the incentive distribution rights;

	•	our general partner intends to limit its liability regarding our contractual and other obligations and, in some circumstances, is entitled to be indemnified by us;

	•	our general partner may exercise its limited 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 owed to us by our general partner and its affiliates; and

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

Please read “Conflicts of Interest and Fiduciary Duties.”

Affiliates of NiSource are not limited in their ability to compete with us and are not obligated to offer us the opportunity to pursue additional assets or businesses, which could limit our commercial activities or our ability to acquire additional assets or businesses.

Neither our partnership agreement nor the omnibus agreement among us, NiSource and others will prohibit affiliates of our general partner, including NiSource, from owning assets or engaging in businesses that compete directly or indirectly with us. In addition, NiSource and its affiliates may acquire, construct or dispose of additional transportation or other energy infrastructure assets in the future, without any obligation to offer us the opportunity to purchase or construct any of those assets. NiSource is a large, established participant in the midstream energy business, and has significantly greater resources and experience than we have, which factors may make it more difficult for us to compete with NiSource and its affiliates with respect to commercial activities as well as for acquisitions. As a result, competition from NiSource and its affiliates could adversely impact our results of operations and cash available for distribution. Please read “Conflicts of Interest and Fiduciary Duties.”

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 at a price that may be below the current market price.

In order to comply with certain FERC rate-making policies applicable to entities that pass-through their taxable income to their owners, we have adopted certain requirements regarding those investors who may own our common and subordinated units. Eligible Holders are individuals or entities subject to United States federal income taxation on the income generated by us or entities not subject to United States federal income taxation on the income generated by us, so long as all of the entity’s owners are subject to such taxation.

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Please read “Description of the Common Units — Transfer of Common Units.” If you are not a person who fits the requirements to be an Eligible Holder, you will not receive distributions or allocations of income and loss on your units and you run the risk of having your units redeemed by us at the lower of your purchase price cost or 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.

Cost reimbursements to our general partner and its affiliates for services provided, which will be determined by our general partner, will be substantial and will reduce our cash available for distribution to you.

Pursuant to an omnibus agreement we will enter into with NiSource, our general partner and certain of their affiliates upon the closing of this offering, NiSource will receive reimbursement for the payment of operating expenses related to our operations and for the provision of various general and administrative services for our benefit, including costs for rendering administrative staff and support services to us, and overhead allocated to us, which amounts will be determined by our general partner in its sole discretion. Payments for these services will be substantial and will reduce the amount of cash available for distribution to unitholders. Please read “Certain Relationships and Related Party Transactions — Omnibus Agreement.” In addition, under Delaware partnership law, our general partner has unlimited liability for our obligations, such as our debts and environmental liabilities, except for our contractual obligations that are expressly made without recourse to our general partner. To the extent our general partner incurs obligations on our behalf, we are obligated to reimburse or indemnify it. If we are unable or unwilling to reimburse or indemnify our general partner, our general partner may take actions to cause us to make payments of these obligations and liabilities. Any such payments could reduce the amount of cash otherwise available for distribution to our unitholders.

Our partnership agreement limits our general partner’s fiduciary duties to holders of our common units and subordinated units and restricts the remedies available to holders of our common units and subordinated units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

Our partnership agreement contains provisions that reduce the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty laws. For example, our partnership agreement:


	•	permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include the exercise of its right to make a determination to receive Class B units in exchange for resetting the target distribution levels related to its incentive distribution rights, the exercise of its limited call right, the exercise of its rights to transfer or vote the units it owns, the exercise of its registration rights and its determination whether or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement;

	•	provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as it acted in good faith, meaning it believed the decision was in the best interests of our partnership;

	•	generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the conflicts committee of the board of directors of our general partner acting in good faith and not involving a vote of unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or must be “fair and reasonable” to us, as determined by our general partner in good faith and that, in determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us;

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

	•	provides that in resolving conflicts of interest, it will be presumed that in making its decision the general partner or its conflicts committee acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.

By purchasing a common unit, a common unitholder will agree to become bound by the provisions in the partnership agreement, including the provisions discussed above. Please read “Conflicts of Interest and Fiduciary Duties — Fiduciary Duties.”

Our general partner may elect to cause us to issue Class B units to it in connection with a resetting of the target distribution levels related to our general partner’s incentive distribution rights without the approval of the conflicts committee of our general partner or holders of our common units and subordinated units. This may result in lower distributions to holders of our common units in certain situations.

Our general partner has the right, at a time when there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled (48%) for each of the prior four consecutive fiscal quarters, to reset the initial cash target distribution levels at higher levels based on the distribution at the time of the exercise of the reset election. Following a reset election by our general partner, the minimum quarterly distribution amount will be reset to an amount equal to the average cash distribution amount per common unit for the two fiscal quarters 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 amount.

In connection with resetting these target distribution levels, our general partner will be entitled to receive a number of Class B units. The Class B units will be entitled to the same cash distributions per unit as our common units and will be convertible into an equal number of common units. The number of Class B units to be issued will be equal to that number of common units whose aggregate quarterly cash distributions equaled the average of the distributions to our general partner on the incentive distribution rights in the prior two quarters. We anticipate that our general partner 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; however, it is possible that our general partner could exercise this reset election at a time when it is experiencing, or may be expected to experience, declines in the cash distributions it receives related to its incentive distribution rights and may therefore desire to receive our Class B units, which are entitled to receive cash distributions from us on the same priority as our common units, rather than retain the right to receive incentive distributions based on the initial target distribution levels. As a result, a reset election may cause our common unitholders to experience dilution in the amount of cash distributions that they would have otherwise received had we not issued new Class B units to our general partner in connection with resetting the target distribution levels related to our general partner incentive distribution rights. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions — General Partner Interest and Incentive Distribution Rights” and “— General Partner’s Right to Reset Incentive Distribution Levels.”

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 the common units will trade.

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders will not elect our general partner or its board of directors, and will have no right to elect

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our general partner or its board of directors on an annual or other continuing basis. The board of directors of our general partner, including the independent directors, will be chosen entirely by its owner and not by the unitholders. In addition, the New York Stock Exchange does not require a listed partnership like us to have a majority of independent directors on the board of directors of our general partner or to establish a nominating and governance committee, and we do not expect that a majority of the board of directors of our general partner will be independent. Furthermore, if the unitholders were dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. 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.

The unitholders will be unable initially to remove our general partner without its consent because our general partner and its affiliates will own sufficient units upon completion of this offering to be able to prevent its removal. The vote of the holders of at least 662/3% of all outstanding units voting together as a single class is required to remove the general partner. Following the closing of this offering, our general partner and its affiliates will own approximately 60.0% of our aggregate outstanding common and subordinated units. Also, if our general partner is removed without cause during the subordination period and units held by our general partner and its affiliates are not voted in favor of that removal, all remaining subordinated units will automatically convert into common units and any existing arrearages on our common units will be extinguished. A removal of our general partner under these circumstances would adversely affect our common units by prematurely eliminating their distribution and liquidation preference over our subordinated units, which would otherwise have continued until we had met certain distribution and performance tests. Cause is narrowly defined to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding the general partner liable for actual fraud or willful or wanton misconduct in its capacity as our general partner. Cause does not include most cases of charges of poor management of the business, so the removal of the general partner because of the unitholders’ dissatisfaction with our general partner’s performance in managing our partnership will most likely result in the termination of the subordination period and conversion of all subordinated units to common units.

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 that owns 20% or more of any class of units then outstanding, other than our general partner, 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 partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.

We have a holding company structure in which our subsidiaries conduct our operations and own our operating assets, which may affect our ability to make distributions to you.

We are a partnership holding company and our operating subsidiaries conduct all of our operations and own all of our operating assets. We have no significant assets other than the ownership interests in our subsidiaries. As a result, our ability to make distributions to our unitholders depends on the performance of our subsidiaries and their ability to distribute funds to us. The ability of our subsidiaries to make distributions to us may be restricted by, among other things, the provisions of existing and future indebtedness, applicable state partnership and limited liability company laws and other laws and regulations, including FERC policies.

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 in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, our partnership agreement

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does not restrict the ability of the owners of our general partner or its parent, from transferring all or a portion of their respective ownership interest in our general partner or its parent to a third party. The new owners of our general partner or its parent would then be in a position to replace the board of directors and officers of its parent with its own choices and thereby influence the decisions taken by the board of directors and officers. This effectively permits a “change of control” of the partnership without your vote or consent.

You will experience immediate and substantial dilution of $16.41 in tangible net book value per common unit.

The assumed initial public offering price of $20.00 per unit exceeds our pro forma net tangible book value of $3.59 per unit. Based on an assumed initial public offering price of $20.00 per unit, you will incur immediate and substantial dilution of $16.41 per common unit. This dilution results primarily because the assets contributed by our general partner and its affiliates are recorded at their historical cost, and not their fair value, in accordance with GAAP. Please read “Dilution.”

Increases in interest rates could adversely impact our unit price and our ability to issue additional equity to make acquisitions, incur debt or for other purposes.

In recent years, the U.S. credit markets experienced 50-year record lows in interest rates. In the future, it is possible that monetary policy will tighten, resulting in higher interest rates to counter possible inflation risk. Interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly and which could reduce our cash available for distribution. As with other yield-oriented securities, our unit price is impacted by the level of our cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank related yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates may affect the yield requirements of investors who invest in our units, and a rising interest rate environment could have an adverse impact on our unit price and our ability to issue additional equity to make acquisitions or to repay debt or for other purposes.

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

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


	•	each unitholder’s proportionate ownership interest in us will decrease;

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

	•	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.

NiSource and its affiliates may sell units in the public or private markets, which sales could have an adverse impact on the trading price of the common units.

After the sale of the common units offered hereby, NiSource and its affiliates will hold an aggregate of 8,584,349 common units and 10,222,715 subordinated units. All of the subordinated units will convert into common units at the end of the subordination period, which could occur as early as the first business day after March 31, 2011, and all of the subordinated units may convert into common units by March 31, 2009 if

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additional tests are satisfied. The sale of any of these units in the public or private markets could have an adverse impact on the price of the common units or on any trading market that may develop.

Our general partner has a limited call right that may require you to sell your 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, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then-current market price. As a result, you may be required to sell your common units at an undesirable time or price and may not receive any return on your investment. You may also incur a tax liability upon a sale of your units. At the completion of this offering and assuming no exercise of the underwriters’ option to purchase additional common units, our general partner and its affiliates will own approximately 40.7% of our outstanding common units. At the end of the subordination period, assuming no additional issuances of common units (other than for the conversion of the subordinated units into common units), our general partner and its affiliates will own approximately 60.0% of our aggregate outstanding common units. For additional information about this right, please read “The Partnership Agreement — Limited Call Right.”

Your 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. You could be liable for any and all of our obligations as if you were a general partner if a court or government agency determined that:


	•	we were conducting business in a state but had not complied with that particular state’s partnership statute; or

	•	your right to act with other unitholders to remove or replace the 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 Revised Uniform Limited Partnership Act, we may not make a distribution to you 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. Substituted limited partners are liable for the obligations of the assignor to make contributions to the partnership that are known to the substituted limited partner at the time it became a limited partner and for unknown obligations if the liabilities could be determined from the partnership agreement. Liabilities to partners on account of their partnership interest and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.

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There is no existing market for our common units, and a trading market that will provide you with adequate liquidity may not develop.

Prior to the offering, there has been no public market for the common units. After the offering, there will be only 12,500,000 publicly traded common units, assuming no exercise of the underwriters’ option to purchase additional 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. You may not be able to resell your 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.

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. In addition, the Sarbanes-Oxley Act of 2002, as well as new rules subsequently implemented by the SEC and the New York Stock Exchange, have required changes in corporate governance practices of publicly-traded entities. We expect these new rules and regulations to increase 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 additional board committees 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 publicly-traded company reporting requirements. We also expect these new rules and regulations to make it more difficult and more expensive for our general partner to obtain director and officer liability insurance and it may be required to accept reduced policy limits and coverage or incur substantially higher costs to obtain the same or similar coverage. As a result, it may be more difficult for our general partner to attract and retain qualified persons to serve on its board of directors or as executive officers. We expect to incur approximately $3.2 million of estimated incremental costs associated with being a publicly-traded partnership for purposes of our Statement of Minimum Estimated Cash Available for Distribution included elsewhere in this prospectus; 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 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 our 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 were to become subject to additional amounts of entity-level taxation for state tax purposes, then our cash available for distribution to you could 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. We have not requested, and do not plan to request, a ruling from the IRS on this or any other tax matter affecting us.

Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. Although we do not believe based upon our current operations that we are so treated, a change in our business (or a change in current law) could cause us to be treated as a corporation for 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 federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%, and would likely pay

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state income tax at varying rates. Distributions to you 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. Therefore, treatment of us as a corporation 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.

Current law may change so as to cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation. For example, at the federal level, legislation has been proposed that would eliminate partnership tax treatment for certain publicly traded partnerships. Although such legislation would not apply to us as currently proposed, it could be amended prior to enactment in a manner that does apply to us. We are unable to predict whether any of these changes, or other proposals will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units. At the state level, 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. The imposition of such a tax on us by any state will reduce the cash available for distribution to you.

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

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

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. 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. If the IRS were to challenge this method or new Treasury regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders. Please read “Material Tax Consequences — Disposition of Common Units — Allocations Between Transferors and Transferees.”

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

We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. 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 positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution.

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

Because our unitholders will be treated as partners to whom we will allocate taxable income which could be different in amount than the cash we distribute, you will be required to pay any federal income taxes and, in some cases, state and local income taxes on your share of our taxable income even if you receive no cash distributions from us. You may not receive cash distributions from us equal to your share of our taxable income or even equal to the actual tax liability that results from that income.

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

If you sell your common units, you will recognize a gain or loss equal to the difference between the amount realized and your tax basis in those common units. Because distributions in excess of your allocable share of our net taxable income decrease your tax basis in your common units, the amount, if any, of such prior excess distributions with respect to the units you sell will, in effect, become taxable income to you if you sell such units at a price greater than your tax basis in those units, even if the price you receive is less than your original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a 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 Tax Consequences — Disposition of Common 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 reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file United States 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 because of 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 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 adopt certain valuation methodologies that may 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 Internal Revenue 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.

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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. Our termination would, among other things, result in the closing of our taxable year for all unitholders, which could result in us filing two tax returns (and unitholders receiving two Schedule K-1s) for one fiscal year. Our termination could also result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead, we would be treated as a new partnership for tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred. Please read “Material Tax Consequences — Disposition of Common 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 return filing requirements in states where you do not live as a result of investing in our common units.

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

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USE OF PROCEEDS

We expect to receive net proceeds from this offering of approximately $235.0 million (based on an assumed initial public offering price of $20.00 per common unit) after deducting underwriting discounts but before paying expenses associated with the offering and related formation transactions. We anticipate using the aggregate net proceeds of this offering to:


	•	pay approximately $3.9 million of fees and expenses associated with the offering and related formation transactions, including a structuring fee payable to Lehman Brothers Inc. for evaluation, analysis and structuring of our partnership;

	•	distribute $71.7 million in cash to subsidiaries of NiSource as reimbursement for capital expenditures related to the Columbia Gulf assets incurred by subsidiaries of NiSource prior to the closing of this offering, which distribution will be made in partial consideration of the assets contributed to us upon the closing of this offering;

	•	retire approximately $31.1 million of indebtedness owed to a subsidiary of NiSource;

	•	purchase approximately $37.0 million of qualifying investment grade securities, which will be assigned as collateral to secure the term loan portion of our credit facility;

	•	use approximately $64.0 million to fund working capital; and

	•	use the remaining amount of $27.3 million to offset identified maintenance capital expenditures expected to be incurred through 2010, including an amount to offset costs we expect to incur in connection with government-mandated pipeline improvements.

We will enter into a $250.0 million credit facility under which we expect to borrow approximately $37.0 million in term debt and $163.0 million in revolving debt upon the closing of this offering. We will distribute the net proceeds of such borrowings (or approximately $198.0 million net of debt issuance costs) to subsidiaries of NiSource, which distribution will be made in partial consideration of the assets contributed to us upon the closing of this offering. Please read “Certain Relationships and Related Party Transactions — Distributions and Payments to our General Partner and its Affiliates.”

The qualifying securities we will purchase will be assigned as collateral to secure the term loan borrowings. The interest we receive from our ownership of these securities will partially offset our cost of borrowings under our term loan facility. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Financing Activities — Description of Credit Agreement.”

If the underwriters’ option to purchase an additional 1,875,000 common units is exercised in full, we will (1) use the net proceeds of approximately $35.1 million from the sale of these additional securities to purchase an equivalent amount of qualifying investment grade securities and (2) borrow an additional amount of term debt equal to the net proceeds to be received from the exercise of the underwriters’ option. The qualifying securities purchased will be assigned as collateral to secure such additional term loan borrowings. The proceeds of the additional term loan borrowings will be used to redeem from a subsidiary of NiSource a number of common units equal to the number of common units issued upon exercise of the underwriters’ option, at a price per common unit equal to the proceeds per common unit before expenses but after underwriting discounts and a structuring fee.

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CAPITALIZATION

The following table shows:


	•	our capitalization as of September 30, 2007; and

	•	our pro forma capitalization as of September 30, 2007, as adjusted to reflect this offering, the other transactions described under “Summary — Formation Transactions and Partnership Structure” and the application of the net proceeds from this offering and our borrowings as described under “Use of Proceeds.”

We derived this table from, and it should be read in conjunction with and is qualified in its entirety by reference to, the historical and pro forma financial statements and the accompanying notes included elsewhere in this prospectus. You should also read this table in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”


	As of September 30, 2007
	Historical		Pro Forma
	(In millions)

Long-term debt:
Revolving borrowings	$	—	$	163.0
Long-term debt-affiliated		67.9		67.9
Term borrowings(a)		—		37.0
Unamortized debt issuance costs				(2.0	)

Total long-term debt	$	67.9	$	265.9

Partners’ capital/parent net equity:
Parent net equity	$	508.3	$	—
Common units — public		—		231.1
Common units — sponsor		—		90.4
Subordinated units — sponsor		—		107.7
General partner interest		—		6.7

Total partners’ capital/parent net equity		508.3		435.9

Total capitalization	$	576.2	$	701.8


(a)		Our initial $37.0 million in term borrowings will be collateralized by an equal $37.0 million in qualifying investment grade securities not reflected in the capitalization table shown above. Please read “Use of Proceeds.”

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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 pro forma net tangible book value per unit after the offering. On a pro forma basis as of September 30, 2007, after giving effect to the offering of common units and the application of the related net proceeds, our net tangible book value was $114.6 million, or $3.59 per common unit. Net tangible book value excludes $321.3 million of goodwill. Purchasers of 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:


Initial public offering price per common unit				$	20.00
Net tangible book value per common unit before the offering(a)	$	9.62
Decrease in net tangible book value per common unit attributable to purchasers in the offering		(6.03	)

Less: Pro forma net tangible book value per common unit after the offering(b)					3.59

Immediate dilution in tangible net book value per common unit to purchasers in the offering				$	16.41


(a)		Determined by dividing the number of units and general partner units (8,584,349 common units, 10,222,715 subordinated units and 638,920 general partner units) to be issued to a subsidiary of NiSource for its contribution of assets and liabilities to NiSource Energy Partners, L.P. into the net tangible book value of the contributed assets and liabilities.

(b)		Determined by dividing the total number of units and general partner units to be outstanding after the offering (21,084,349 common units, 10,222,715 subordinated units and 638,920 general partner units) and the application of the related net proceeds into our pro forma net tangible book value, after giving effect to the application of the expected net proceeds of the offering.

The following table sets forth the number of units that we will issue and the total consideration contributed to us by our general partner and its affiliates and by the purchasers of common units in this offering:


						Total Consideration
	Units Acquired					(In millions)
	Number		Percent			Amount		Percent

General partner and affiliates(a)(b)		19,445,984		60.9	%	$	204.8		45.0	%
New investors		12,500,000		39.1	%		250.0		55.0	%

Total		31,945,984		100.0	%	$	454.8		100.0	%


(a)		The common and subordinated units and general partner units acquired by our general partner and its affiliates consist of 8,584,349 common units and 10,222,715 subordinated units and 638,920 general partner units.

(b)		The assets contributed by our general partner and its affiliates were recorded at historical cost in accordance with GAAP. Book value of the consideration provided by our general partner and its affiliates, as of September 30, 2007, after giving effect to the application of the net proceeds of this offering is as follows:

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The following table shows the investment of NiSource in us after giving effect to this offering and related formation transactions. Please see our unaudited pro forma balance sheet for a more complete presentation of the adjustments associated with this offering and the related formation transactions.


Parent net equity prior to unit offering	$	508.3
Less:
Distribution to NiSource from the net proceeds of the offering and borrowings under the credit facility		275.7
Retention by NiSource of accounts receivable, tax related accounts, and certain offshore assets		27.8

Total consideration	$	204.8

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OUR CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

You should read the following discussion of our cash distribution policy in conjunction with specific assumptions included in this section. For more detailed information regarding the factors and assumptions upon which our cash distribution policy is based, please read “— Assumptions and Considerations” below. 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 operating results, you should refer to Columbia Gulf’s historical audited financial statements for the years ended December 31, 2004, 2005 and 2006, and to Columbia Gulf’s historical unaudited financial statements as of and for the nine months ended September 30, 2007; and our unaudited pro forma financial statements for the year ended December 31, 2006 and as of and for the nine months ended September 30, 2007 included elsewhere in this prospectus.

General

Rationale for Our Cash Distribution Policy. Our cash distribution policy reflects a basic judgment that our unitholders will be better served by our distributing our cash available after expenses and reserves rather than retaining it. Because we believe we will generally finance any expansion capital investments from external financing sources, we believe that our investors are best served by our distributing all of our available cash. Because we are not subject to an entity-level federal income tax, we have more cash to distribute to you than would be the case were we subject to tax. Our cash distribution policy is consistent with the terms of our partnership agreement, which requires that we distribute all of our available cash quarterly.

Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy. There is no guarantee that unitholders will receive quarterly distributions from us. Our distribution policy may be changed at any time and is subject to certain restrictions, including:


	•	Our cash distribution policy is subject to restrictions on distributions under our new credit facility. Specifically, the agreement related to our credit facility contains material financial tests and covenants that we must satisfy. These financial tests and covenants are described in this prospectus under the caption “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Description of Credit Agreement.” Should we be unable to satisfy these restrictions under our credit facility or if we are otherwise in default under our credit facility, we would be prohibited from making cash distributions to you notwithstanding our stated cash distribution policy;

	•	Our board of directors will have the authority to establish reserves for the prudent conduct of our business and for future cash distributions to our unitholders, and the establishment of those reserves could result in a reduction in cash distributions to you from the levels we currently anticipate pursuant to our stated distribution policy;

	•	While our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including provisions requiring us to make cash distributions contained therein, may be amended. Although during the subordination period, with certain exceptions, our partnership agreement may not be amended without the approval of the public common unitholders, our partnership agreement can be amended with the approval of a majority of the outstanding common units and any Class B units issued upon the reset of incentive distribution rights, if any, voting as a class (including common units held by affiliates of NiSource) after the subordination period has ended. At the closing of this offering, a subsidiary of NiSource will own our general partner and approximately 60.0% of our outstanding common units and subordinated units;

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

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	•	Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to you if the distribution would cause our liabilities to exceed the fair value of our assets; and

	•	We may lack sufficient cash to pay distributions to our unitholders due to increases in our operating or general and administrative expenses, principal and interest payments on our outstanding debt, tax expenses, working capital requirements and anticipated cash needs. Our cash available for distribution to unitholders is directly impacted by our cash expenses necessary to run our business and will be reduced dollar-for-dollar to the extent that such uses of cash increase. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions — Distributions of Available Cash.”

Our Ability to Grow is Dependent on Our Ability to Access External Expansion Capital. We will distribute all of our available cash to our unitholders on a quarterly basis. As a result, we expect that we will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. To the extent we are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow. In addition, because we distribute all of our available cash, our growth may not be as fast as businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level, which in turn may impact the available cash that we have to distribute on each unit. There are no limitations in our partnership agreement or our credit facility on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which in turn may impact the available cash that we have to distribute to our unitholders.

Our Initial Distribution Rate

Upon completion of this offering, the board of directors of our general partner will adopt a policy pursuant to which we will declare an initial quarterly distribution of $0.30 per unit per complete quarter, or $1.20 per unit per year, to be paid no later than 45 days after the end of each fiscal quarter (beginning with the quarter ending March 31, 2008) through the quarter ending March 31, 2009. This equates to an aggregate cash distribution of $9.6 million per quarter or $38.3 million per year, in each case based on the number of common units, subordinated units and general partner units outstanding immediately after completion of this offering. If the underwriters’ option to purchase additional common units is exercised, we will (1) use the net proceeds from the sale of these additional securities to purchase an equivalent amount of qualifying investment grade securities and (2) borrow an additional amount of term debt equal to the net proceeds to be received from the exercise of the underwriters’ option. The qualifying securities purchased will be assigned as collateral to secure such additional term loan borrowings. The proceeds of the additional term loan borrowings will be used to redeem from a subsidiary of NiSource a number of common units equal to the number of common units issued upon exercise of the underwriters’ option, at a price per common unit equal to the proceeds per common unit before expenses but after underwriting discounts and a structuring fee. Accordingly, the exercise of the underwriters’ option will not affect the total amount of units outstanding or the amount of cash needed to pay the initial distribution rate on all units. Our ability to make cash distributions at the initial distribution rate pursuant to this policy will be subject to the factors described above under the caption “— Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy.”

The table below sets forth the number of outstanding common units, subordinated units and general partner units upon the closing of this offering and the aggregate distribution amounts payable on such units during the year following the closing of this offering at our initial distribution rate of $0.30 per common unit per quarter ($1.20 per common unit on an annualized basis).

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			Distributions
	Number of Units		One Quarter		Four Quarters

Publicly held common units		12,500,000	$	3,750,000	$	15,000,000
Common units held by NiSource		8,584,349		2,575,305		10,301,219
Subordinated units held by NiSource		10,222,715		3,066,815		12,267,258
General partner units held by NiSource		638,920		191,676		766,704

Total		31,945,984	$	9,583,796	$	38,335,181

As of the date of this offering, our general partner will be entitled to 2% of all distributions that we make prior to our liquidation. The general partner’s initial 2% interest in these distributions may be reduced if we issue additional units in the future and our general partner does not elect to contribute a proportionate amount of capital to us to maintain its initial 2% general partner interest.

The subordination period will generally end if we have earned and paid at least $1.20 (the minimum quarterly distribution on an annualized basis) on each outstanding limited partner unit and general partner unit for any three consecutive, non-overlapping four-quarter periods ending on or after March 31, 2011. Alternatively, if we have earned and paid at least $0.45 per quarter (150% of the minimum quarterly distribution, which is $1.80 on an annualized basis) on each outstanding limited partner unit and general partner unit for any four-quarter period ending on or after March 31, 2009, the subordination period will terminate automatically. In addition, the subordination period will end if our general partner is removed without cause and the units held by our general partner and its affiliates are not voted in favor of such removal. When the subordination period ends, all remaining subordinated units will convert into an equal number of common units, and the common units will no longer be entitled to arrearages.

If distributions on our common units are not paid with respect to any fiscal quarter at the initial distribution rate, our unitholders will not be entitled to receive such payments in the future except that during the subordination period, to the extent we have available cash in any future quarter in excess of the amount necessary to make cash distributions to holders of our common units at the initial distribution rate, we will use this excess available cash to pay these deficiencies related to prior quarters before any cash distribution is made to holders of subordinated units. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions — Subordination Period.”

We do not have a legal obligation to pay distributions at our initial distribution rate or at any other rate except as provided in our partnership agreement. Our distribution policy is consistent with the terms of our partnership agreement, which requires that we distribute all of our available cash quarterly. Under our partnership agreement, available cash is defined to generally mean, for each fiscal quarter, cash generated from our business in excess of the amount of reserves our general partner determines is necessary or appropriate to provide for the conduct of our business, to comply with applicable law, any of our debt instruments or other agreements or to provide for future distributions to our unitholders for any one or more of the upcoming four quarters.

Our partnership agreement provides that any determination made by our general partner in its capacity as our general partner must be made in good faith and that any such determination will not be subject to any other standard imposed by our partnership agreement, the Delaware limited partnership statute or any other law, rule or regulation or at equity. Holders of our common units may pursue judicial action to enforce provisions of our partnership agreement, including those related to requirements to make cash distributions as described above; however, our partnership agreement provides that our general partner is entitled to make the determinations described above without regard to any standard other than the requirements to act in good faith. Our partnership agreement provides that, in order for a determination by our general partner to be made in “good faith,” our general partner must believe that the determination is in our best interests. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions.”

Our cash distribution policy, as expressed in our partnership agreement, may not be modified or repealed without amending our partnership agreement; however, the actual amount of our cash distributions for any

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quarter is subject to fluctuations based on the amount of cash we generate from our business and the amount of reserves our general partner establishes in accordance with our partnership agreement as described above. Our partnership agreement may be amended with the approval of our general partner and holders of a majority of our outstanding common units and any Class B units issued upon the reset of the incentive distribution rights, voting together as a class.

We will pay our distributions on or about the 15th day of each of February, May, August and November to holders of record on or about the 1st day of each such month. If the distribution date does not fall on a business day, we will make the distribution on the business day immediately preceding the indicated distribution date. We will adjust the quarterly distribution for the period from the closing of this offering through March 31, 2008 based on the actual length of the period.

In the sections that follow, we present in detail the basis for our belief that we will be able to fully fund our initial distribution rate of $0.30 per unit each quarter through the quarter ending March 31, 2009. In those sections, we present two tables, consisting of:


	•	“Unaudited Pro Forma Cash Available for Distribution,” in which we present the amount of cash we would have had available for distribution for our fiscal year ended December 31, 2006 and for the twelve months ended September 30, 2007 derived from our unaudited pro forma financial statements that are included in this prospectus, which unaudited pro forma financial statements are based on the historical financial statements of Columbia Gulf for the year ended December 31, 2006 and for the twelve months ended September 30, 2007, as adjusted to give pro forma effect to:


	•	the transactions to be completed as of the closing of this offering, including our incurrence of approximately $37.0 million in term debt and $163.0 million in revolving debt under our new $250.0 million credit facility;

	•	this offering and the application of the net proceeds as described under “Use of Proceeds”; and

	•	the disposition of certain offshore assets currently owned by Columbia Gulf.


	•	“Statement of Minimum Estimated Cash Available for Distribution,” in which we demonstrate our anticipated ability to generate the minimum estimated cash available for distribution necessary for us to pay distributions at the initial distribution rate on all units for the twelve months ending March 31, 2009.

Unaudited Pro Forma Cash Available for Distribution for the Year Ended December 31, 2006 and Twelve Months Ended September 30, 2007

If we had completed the transactions contemplated in this prospectus on January 1, 2006, pro forma cash available for distribution for the year ended December 31, 2006 would have been approximately $14.3 million. This amount would have been sufficient to make a cash distribution of approximately 55% of the minimum quarterly distribution on our common units but no quarterly distributions on our subordinated units.

If we had completed the transactions contemplated in this prospectus on October 1, 2006, our pro forma available cash for the twelve months ended September 30, 2007 would have been approximately $21.0 million. This amount would have been sufficient to make a cash distribution for the twelve months ended September 30, 2007 at the initial distribution rate of $0.30 per unit per quarter (or $1.20 per unit on an annualized basis) of approximately 81% of the minimum quarterly distribution on our common units but no quarterly distributions on our subordinated units.

Unaudited pro forma cash available for distribution from operating surplus includes estimated incremental general and administrative expense we will incur as a result of being a publicly traded limited partnership, costs associated with annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution, independent auditor fees, investor relations activities, registrar and transfer agent fees, incremental director and officer liability insurance costs and director compensation. We expect our incremental general and administrative expense associated with being a publicly-traded partnership to total approximately $3.2 million per year. Our incremental general and administrative expense is not reflected in our historical or pro forma net

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income for 2006 or for the nine months ended September 30, 2007. Corporate general and administrative costs allocated to us by NiSource totaled $11.0 million in 2006 and $9.4 million for the nine months ended September 30, 2007, and are already reflected in our historical results for 2006 and for the nine months ended September 30, 2007.

The following table illustrates, on a pro forma basis, for the year ended December 31, 2006 and for the twelve months ended September 30, 2007 the amount of available cash that would have been available for distributions to our unitholders, assuming in each case that this offering had been consummated at the beginning of such period. Each of the pro forma adjustments presented below is explained in the footnotes to such adjustments.

We based the pro forma adjustments upon currently available information and specific estimates and assumptions. The pro forma amounts below do not purport to present our results of operations had the transactions contemplated in this prospectus actually been completed as of the dates indicated. In addition, cash available to pay distributions is primarily a cash accounting concept, while our pro forma financial statements have been prepared on an accrual basis. As a result, you should view the amount of pro forma cash available for distribution only as a general indication of the amount of cash available to pay distributions that we might have generated had we been formed in earlier periods.

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NISOURCE ENERGY PARTNERS, L.P.

UNAUDITED PRO FORMA CASH AVAILABLE FOR DISTRIBUTION


				Twelve Months
	Year Ended			Ended
	December 31,			September 30,
	2006(a)			2007(a)
	($ Millions, except per unit data)

Pro forma operating revenues	$	117.3		$	125.7
Pro forma operating expenses:
Operation and maintenance		55.1			57.4
Depreciation and amortization		19.1			19.0
Other taxes		8.1			8.3

Total operating expenses		82.3			84.7

Pro forma operating income		35.0			41.0

Add:
Interest income		1.5			1.0
Other, net		0.7			—
Less:
Interest expense (net of AFUDC)		15.2			14.2
Income taxes		0.1			0.1

Pro forma net income(b)	$	21.9		$	27.7

Add:
Interest expense (net of AFUDC)		15.2			14.2
Income taxes		0.1			0.1
Depreciation and amortization		19.1			19.0
Less:
Interest income		1.5			1.0
Other, net		0.7			—

Pro forma EBITDA(c)	$	54.1		$	60.0

Less:
Incremental general and administrative expense of being a public company(d)		3.2			3.2
Pro forma net cash paid for interest expense(e)		14.3			14.8
Income taxes paid		0.1			0.1
Maintenance capital expenditures(f)		22.2			20.9

Pro forma cash available for distribution	$	14.3		$	21.0

Pro forma cash distributions
Distributions per unit(g)	$	1.20		$	1.20

Distributions to public common unitholders(g)		15.0			15.0
Distributions to NiSource(g)		23.3			23.3

Total distributions(g)	$	38.3		$	38.3

Excess (shortfall)	$	(24.0	)	$	(17.3	)


(a)		Unaudited pro forma cash available for distribution for the year ended December 31, 2006 was derived from the unaudited pro forma financial statements included elsewhere in this prospectus. Unaudited pro forma cash available for distribution for the twelve months ended September 30, 2007 was derived by combining pro forma amounts for the three months ended December 31, 2006 (not included in this prospectus) and the nine months ended September 30, 2007 (included in this prospectus).

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(b)		Reflects net income of Columbia Gulf derived from its historical financial statements for the periods indicated giving pro forma effect to this offering and the related transactions.

(c)		Our EBITDA is defined as net income plus interest expense (net of AFUDC), income taxes, depreciation and amortization, less our interest income and other, net. We have provided EBITDA in this prospectus because we believe it provides investors with additional information to measure our financial performance and liquidity. EBITDA is not a presentation made in accordance with GAAP. Because EBITDA excludes some, but not all, items that affect net income and is defined differently by different companies in our industry, our definition of EBITDA may not be comparable to similarly titled measures presented by other companies. EBITDA has important limitations as an analytical tool, and you should not consider it in isolation, or as a substitute for analysis of our results as reported under GAAP. Please read “Summary — Summary Historical and Pro Forma Financial and Operating Data — Non-GAAP Financial Measures.”

(d)		Reflects an adjustment to our EBITDA for an estimated incremental cash expense associated with being a publicly traded limited partnership, including costs associated with annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution, independent registered public accounting firm fees, investor relations activities, registrar and transfer agent fees, incremental director and officer liability insurance costs and director compensation.

(e)		Reflects on a net basis the interest expense related to borrowings under our credit facility made in connection with this offering and the interest income related to the investment grade securities we intend to purchase with a portion of the proceeds from this offering.

(f)		Maintenance capital expenditures are capital expenditures made to replace partially or fully depreciated assets, to maintain the existing operating capacity of our assets and to extend their useful lives, or other capital expenditures that are incurred in maintaining existing system volumes and related cash flows.

Maintenance capital expenditures for the year ended December 31, 2006 of $22.2 million included $17.6 million of capital expenditures we consider to be non-recurring in nature. These non-recurring expenditures include:


	•	$6.0 million for compressor station upgrades for compliance with new environmental regulations;

	•	$3.8 million for the replacement of disbonded protective coatings on pipelines downstream of compressors at certain compressor stations;

	•	$2.3 million, net of insurance proceeds, for the replacement of a turbine at our Delhi compressor station as a result of a turbine failure;

	•	$2.0 million for development of a new customer activity software system to replace a 15-year old system;

	•	$1.8 million for upgrades to enable our pipeline integrity management program in order to comply with pipeline safety regulations; and

	•	$1.7 million for pipeline retirements, hurricane related damages to offshore assets to be disposed of by Columbia Gulf, pipeline upgrades due to class changes as required by DOT regulations, and forced relocations due to highway construction.

The balance of our total maintenance capital expenditures for the year ended December 31, 2006 included $4.6 million of capital expenditures which we expect to be recurring in nature and necessary to maintain the operating capacity of our systems.

Maintenance capital expenditures for the twelve months ended September 30, 2007 of $20.9 million included $16.1 million of capital expenditures we consider to be non-recurring in nature (of which $7.4 million was incurred in the fourth quarter of 2006). These non-recurring expenditures include:


	•	$5.1 million for compressor station upgrades for compliance with new environmental regulations;

	•	$2.4 million, net of insurance proceeds, for the replacement of a turbine at our Delhi compressor station as a result of a turbine failure;

	•	$2.3 million for development of a new customer activity software system to replace a 15-year old system;

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	•	$2.1 million for pipeline retirements, and hurricane related damages to offshore assets to be disposed of by Columbia Gulf;

	•	$1.8 million for the replacement of disbonded protective coatings on pipelines downstream of compressors at certain compressor stations;

	•	$1.4 million for relocation and build-out of new office space in Houston; and

	•	$1.0 million for forced relocations due to highway construction, upgrades to enable our pipeline integrity management program as required by DOT regulations, and upgrades to ancillary compressor systems.

The balance of our total maintenance capital expenditures for the twelve months ended September 30, 2007 included $4.8 million of capital expenditures which we consider to be recurring in nature and necessary to maintain the operating capacity of our systems.

For the twelve months ending March 31, 2009, we expect to incur additional non-recurring maintenance capital expenditures as described in “— Assumptions and Considerations.” We will retain a portion of the proceeds from this offering to offset future identified maintenance capital expenditures, including the non-recurring items included in our forecast period for the twelve months ending March 31, 2009.


		In addition, we made expansion capital expenditures of $2.9 million for the year ended December 31, 2006 and $12.3 million for the twelve months ended September 30, 2007. Expansion capital expenditures are made to acquire additional assets to grow our business, to expand and upgrade our systems and facilities and to construct or acquire similar systems or facilities. The expansion projects included the Shadyside, Terrebonne and Evangeline interconnects, which were placed in service during the latter half of 2007. For more information regarding our expansion projects, please read “Business — Columbia Gulf Pipeline System — Expansion Projects.” For purposes of this presentation, these expenditures were assumed to be funded by cash contributions from our parent, NiSource, and are not included in our pro forma cash available for distribution calculation.

(g)		The table below sets forth the number of outstanding common units, subordinated units and general partner units upon the closing of this offering and the per unit and aggregate distribution amounts payable on our common units, subordinated units and general partner units for four quarters at our initial distribution rate of $0.30 per common unit per quarter ($1.20 per common unit on an annualized basis).


			Distributions for Four Quarters
	Number of Units		Per Unit		Aggregate

Pro forma distributions on publicly held common units		12,500,000	$	1.20	$	15,000,000
Pro forma distributions on common units held by NiSource		8,584,349		1.20		10,301,219
Pro forma distributions on subordinated units held by NiSource		10,222,715		1.20		12,267,258
Pro forma distributions on general partner units		638,920		1.20		766,704

Total		31,945,984	$	1.20	$	38,335,181

Minimum Estimated Cash Available for Distribution for the Twelve-Month Period Ending March 31, 2009

Set forth below is a Statement of Minimum Estimated Cash Available for Distribution that reflects our ability to generate sufficient cash flows to make the minimum quarterly distribution on all of our outstanding units for the twelve months ending March 31, 2009, based on assumptions we believe to be reasonable. These assumptions include adjustments to reflect this offering, 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.” Cash available for distribution is presented as our EBITDA less cash reserves, incremental public company expense, cash interest expense, and maintenance capital expenditures.

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Our minimum 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 March 31, 2009. The assumptions disclosed below under “ — Assumptions and Considerations” are those that we believe are significant to our ability to generate our minimum estimated cash available for distribution. We believe our actual results of operations and cash flows will be sufficient to generate our minimum estimated cash available for distribution; however, we can give you no assurance that our minimum estimated cash available for distribution will be achieved. There will likely be differences between our minimum estimated cash available for distribution and our actual results and those differences could be material. If we fail to generate the minimum estimated cash available for distribution, we may not be able to pay cash distributions on our common units at the initial distribution rate stated in our cash distribution policy. In order to fund distributions to our unitholders at our initial rate of $1.20 per common unit for the twelve months ending March 31, 2009, our EBITDA for the twelve months ending March 31, 2009 must be at least $65.5 million. As set forth in the table below and as further explained under “— Assumptions and Considerations,” we believe our operations will produce minimum estimated cash available for distribution of $38.3 million for the twelve months ending March 31, 2009.

We do not as a matter of course make public projections as to future operations, earnings, or other results. However, management has prepared the minimum estimated cash available for distribution and assumptions 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 March 31, 2009. The accompanying prospective financial information was not prepared with a view toward complying with the guidelines established by the American Institute of Certified Public Accountants with respect to prospective financial information, but, in 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, the assumptions on which we base our belief that we can generate the minimum estimated cash available for distribution necessary for us to have sufficient cash available for distribution to pay the minimum quarterly distribution to all of our unitholders for the twelve months ending March 31, 2009. 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, and assume no responsibility for, and disclaim any association with, the prospective financial information.

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

We are providing our minimum estimated cash available for distribution and related assumptions 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 March 31, 2009 at our stated initial distribution rate. Please read below under “— Assumptions and Considerations” for further information as to the assumptions we have made for the preparation of our minimum estimated cash available for distribution.

Actual payments of distributions on common units, subordinated units and the general partner units are expected to be $38.3 million for the twelve month period ending March 31, 2009. This is the expected aggregate amount of cash distributions of $9.6 million per quarter for the period. Quarterly distributions will be paid within 45 days after the close of each quarter.

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 minimum estimated cash available for distribution 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.

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NISOURCE ENERGY PARTNERS, L.P.

STATEMENT OF

MINIMUM ESTIMATED CASH AVAILABLE FOR DISTRIBUTION


	Twelve Months
	Ending
	March 31, 2009
	(In millions,
	except per units
	data)

Operating revenues	$	131.1
Operating expenses:
Operation and maintenance		52.7
Depreciation and amortization		19.7
Other taxes		9.7
Incremental public company expense		3.2

Total operating expenses		85.3

Operating income		45.8

Add:
Interest income(a)		1.0
Less:
Interest expense (net of AFUDC)(b)		13.5
Income taxes		0.1

Net income		33.2

Adjustments to reconcile net income to EBITDA:
Add:
Depreciation and amortization		19.7
Interest expense (net of AFUDC)(b)		13.5
Income taxes		0.1
Less:
Interest income(a)		1.0

EBITDA		65.5

Add:
Interest income		1.0
Proceeds from IPO reserved for non-recurring maintenance capital expenditure(c)		15.6
Less:
Cash interest expense		15.8
Income taxes paid		0.1
Maintenance capital expenditures(c)		24.1
Cash reserve(d)		3.8

Minimum estimated cash available for distribution before expansion capital expenditures		38.3

Add:
Liquidation of marketable securities held to fund expansion capital expenditures		37.0
Borrowings under revolving credit facility to fund expansion capital expenditures		25.0
Less:
Expansion capital expenditures(e)		62.0

Minimum estimated cash available for distribution		38.3

Minimum annual distribution per unit	$	1.20
Annual distributions to:
Public common unitholders	$	15.0
NiSource:
Common Units	$	10.3
Subordinated Units		12.3
General Partner Units		0.7

Total distributions to NiSource	$	23.3

Total distributions to our unitholders and general partner at the initial distribution rate	$	38.3

Interest coverage ratio(f)		4.4	x
Leverage ratio(f)		4.5	x

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(a)		Reflects the interest income related to the long-term investments we intend to purchase with a portion of the proceeds from this offering.

(b)		Reflects $15.8 million in interest expense related to borrowings under our credit facility made in connection with this offering, our long-term debt, and amortization of $0.4 million of debt issuance costs, and net of $2.7 million of AFUDC income.

(c)		Estimated maintenance capital expenditures for the twelve months ending March 31, 2009 of $24.1 million includes $15.6 million in capital expenditures we consider to be non-recurring in nature. We are retaining $15.6 million of the proceeds from this offering to offset these identified capital expenditures. The non-recurring expenditures include:


	•	$7.0 million for pipeline retirements of offshore assets to be disposed of by Columbia Gulf;

	•	$3.8 million of pipeline relocations cost as a result of highway and Mississippi levee construction;

	•	$3.7 million to make improvements to our East Lateral to reduce the costs of in-line pipeline integrity inspections; and

	•	$1.1 million for upgrades to ancillary compressor systems, and measurement equipment primarily for modifications to meet gas quality requirements.

The balance of our total maintenance capital expenditures for the twelve months ending March 31, 2009 includes $8.5 million of capital expenditures which we expect to be recurring in nature and necessary to maintain the operating capacity of our systems. Please read “—Assumptions and Considerations.”


(d)		Represents a discretionary reserve that can be used for reinvestment and other general partnership purposes and constitutes a reserve of cash in excess of the amount required to pay the minimum quarterly distribution.

(e)		Please read the accompanying summary of the assumptions and considerations underlying these estimates.

(f)		In connection with the closing of this offering we expect to enter into a $250.0 million credit facility. We expect to borrow approximately $37.0 million in term debt and $163.0 million in revolving debt upon the closing of this offering. The credit facility is expected to contain covenants limiting our ability to 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; grant liens or make certain negative pledges; make certain loans or investments; engage in transactions with affiliates; make any material change to the nature of our business from the midstream energy business; make a disposition of assets; or enter into a merger, consolidate, liquidate, wind up or dissolve. These covenants may be modified or eliminated upon our receipt of an investment grade rating.

In addition, the credit facility is expected to contain financial covenants requiring us to maintain:


	•	an interest coverage ratio (the ratio of our EBITDA to our consolidated interest expense (net of interest income), in each case as defined in the credit agreement) of not less than to 1.0, determined as of the last day of each quarter for the four-quarter period ending on the date of determination; and

	•	a leverage ratio (the ratio of our consolidated indebtedness to our EBITDA, in each case as defined in the credit agreement) of not more than to 1.0 (or, on a temporary basis for not more than three consecutive quarters following the consummation of certain acquisitions, not more than to 1.0).

We believe that we will be in compliance with these covenants for the twelve months ending March 31, 2009.

If an event of default exists under the credit agreement, the lenders will be able to accelerate the maturity of the credit facility and demand repayment of amounts outstanding.

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Assumptions and Considerations

General

We believe that our minimum estimated cash available for distribution for the twelve months ending March 31, 2009 will not be less than $38.3 million. This amount of estimated cash available for distribution is approximately $17.3 million more than the pro forma cash available for distribution we generated for the twelve months ended September 30, 2007. As we discuss in further detail below, we believe that the increased revenue primarily from firm transportation agreements resulting from expansion projects, and lower operating expenses will generate higher cash available for distribution for the twelve months ending March 31, 2009.

Our Operating Revenue


	•	We estimate that we will generate $131.1 million in revenues for the twelve months ending March 31, 2009. The majority of these revenues, approximately 92%, will be generated from services provided under firm transportation agreements. We estimate 8% of revenues will be generated based on actual utilization of interruptible transportation services. We generated $125.7 million in revenues for the twelve months ended September 30, 2007.

	•	The expected $5.4 million increase in our revenues for the twelve months ending March 31, 2009 compared to the twelve months ended September 30, 2007 is primarily due to $9.5 million of incremental firm transportation revenues. This incremental revenue is associated with several expansion projects, including the Shadyside, Terrebonne and Evangeline interconnects, which were placed in service during the latter half of 2007, as well as the expansion of our existing Florida Gas Transmission interconnect, which is projected to be placed into service in June 2008. For more information regarding these expansion projects, please read “Business — Columbia Gulf Pipeline System — Expansion Projects.” These estimated increased revenues for the twelve months ending March 31, 2009 will be partially offset by the fact that revenues for the twelve months ended September 30, 2007 were favorably impacted by non-recurring business interruption insurance proceeds of $4.3 million. In addition, we have assumed that any contracts expiring before March 31, 2009 will be renewed or recontracted at rates substantially the same as those currently in effect.

Our Expenses


	•	We estimate operating and maintenance expenses (before any incremental public-company related expenses) will be approximately $52.7 million for the twelve months ending March 31, 2009 as compared to $57.4 million for the twelve months ended September 30, 2007. The expected $4.7 million reduction from the twelve months ended September 30, 2007 is expected to result from $1.5 million of lower employee and administrative expenses due to lower allocations from Columbia Gas Transmission and $1.2 million of lower maintenance costs due to unplanned maintenance during the twelve months ended September 30, 2007. In addition, expenses for the twelve months ended September 30, 2007 were increased by a $2.0 million legal reserve, net of settlement.

	•	We estimate that we will also incur approximately $3.2 million of incremental general and administrative expenses relating to being a publicly-traded partnership during the twelve months ending March 31, 2009 that were not incurred as a subsidiary of NiSource during the twelve months ended September 30, 2007.

	•	We estimate depreciation and amortization expense for the twelve months ending March 31, 2009 will be $19.7 million as compared to $19.0 million for the twelve months ended September 30, 2007. 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.

	•	We estimate other taxes for the twelve months ending March 31, 2009 will be $9.7 million as compared to $8.3 million for the twelve months ended September 30, 2007, primarily due to increased property taxes resulting from new capital expansion projects.

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Our Capital Expenditures


	•	We estimate our maintenance capital expenditures will be approximately $24.1 million for the twelve months ending March 31, 2009 as compared to $20.9 million for the twelve months ended September 30, 2007. Of the $24.1 million, approximately $15.6 million relates to expenditures that we consider to be non-recurring in nature. For more information, please read footnote (c) to our Statement of Minimum Estimated Cash Available for Distribution for the twelve months ending March 31, 2009. Of the $20.9 million of maintenance capital expenditures during the twelve months ended September 30, 2007, approximately $16.1 million relates to expenditures that we consider to be non-recurring in nature. For more information, please read footnote (f) to our Unaudited Pro Forma Cash Available for Distribution. We assume that there are no capital expenditures during the twelve months ending March 31, 2009 related to DOT-mandated pipeline upgrades along our system;

	•	We will retain $15.6 million of the proceeds from this offering to offset future identified maintenance capital expenditures, including the non-recurring expenditures included in our forecast period for the twelve months ending March 31, 2009;

	•	The balance of our total maintenance capital expenditures for the twelve months ending March 31, 2009 includes $8.5 million of capital expenditures which we expect to be recurring in nature and necessary to maintain the operating capacity of our systems; and

	•	We estimate that our expansion capital expenditures will be approximately $62.0 million for the twelve months ending March 31, 2009 compared to approximately $12.3 million for the twelve months ended September 30, 2007. This increase relates to proposed interconnects and compression expansions to deliver gas to Florida Gas Transmission, which are expected to be placed into service in June 2008, and other proposed interconnects served by the East Lateral that are not expected to be placed into service prior to March 31, 2009.

Our Financing


	•	We estimate that at closing of this offering we will borrow approximately $37.0 million in term debt and $163.0 million in revolving debt under our new $250 million credit facility. We estimate that the revolving borrowings will bear a variable average interest rate of 6.25%.

	•	We estimate that our term debt borrowings, net of interest earned on the approximately $37.0 million in qualifying investment grade securities pledged to secure the loan, will incur interest at a net effective rate of 0.25%.

	•	We estimate that Columbia Gulf’s $67.9 million promissory notes will remain outstanding and continue to bear a weighted average interest rate of 5.52%.

	•	We believe that we will remain in compliance with the financial covenants in our existing and future debt agreements during the twelve months ending March 31, 2009.

Our 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 during the twelve months ending March 31, 2009.

	•	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 during the twelve months ending March 31, 2009.

	•	We assume that industry, insurance and overall economic conditions will not change substantially during the twelve months ending March 31, 2009.

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Payments of Distributions on Common Units, Subordinated Units and General Partner Units

Distributions on common units, subordinated units and general partner units for the twelve months ending March 31, 2009 are estimated to be $38.3 million in the aggregate. Quarterly distributions will be paid within 45 days after the close of each quarter.

While we believe that these assumptions are reasonable based upon management’s current expectations concerning future events, they are inherently uncertain and are subject to significant business, economic, regulatory and competitive risks and uncertainties, including those described in “Risk Factors,” that could cause actual results to differ materially from those we anticipate. If our assumptions are not realized, the actual cash available for distribution that we generate could be substantially less than that currently expected and could, therefore, be insufficient to permit us to make the full minimum quarterly distribution on all units, in which event the market price of the common units may decline materially.

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PROVISIONS OF OUR PARTNERSHIP AGREEMENT
RELATING TO CASH DISTRIBUTIONS

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

Distributions of Available Cash

General. Our partnership agreement requires that, within 45 days after the end of each quarter, beginning with the quarter ending March 31, 2008, we distribute all of our available cash to unitholders of record on the applicable record date.

Definition of Available Cash. Available cash, for any quarter, consists of all cash on hand at the end of that quarter:


	•	less the amount of cash reserves established by our general partner to:


	•	provide for the proper conduct of our business;

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

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


	•	plus, if our general partner so determines, all additional cash and cash equivalents on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter. Working capital borrowings are generally borrowings that are made under a credit facility, commercial paper facility or similar financing arrangement, and in all cases are used solely for working capital purposes or to pay distributions to partners and with the intent of the borrower to repay such borrowings within 12 months from sources other than additional working capital borrowings.

Minimum Quarterly Distribution. We will distribute to the holders of common units and subordinated units on a quarterly basis at least the minimum quarterly distribution of $0.30 per unit, or $1.20 per year, to the extent we have sufficient cash from our operations after establishment of cash reserves and payment of fees and expenses, including payments to our general partner. However, there is no guarantee that we will pay the minimum quarterly distribution on the units in any quarter. Even if our cash distribution policy is not modified or revoked, the amount of distributions paid under our policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement. We will be prohibited from making any distributions to unitholders if it would cause an event of default, or an event of default is existing, under our credit agreement. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Description of Credit Agreement” for a discussion of the restrictions to be included in our credit agreement that may restrict our ability to make distributions.

General Partner Interest and Incentive Distribution Rights. Initially, our general partner will be entitled to 2% of all quarterly distributions since inception that we make prior to our liquidation. This general partner interest will be represented by 638,920 general partner units. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its current general partner interest. The general partner’s initial 2% interest in these distributions will be reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its 2% general partner interest.

Our general partner also currently holds incentive distribution rights that entitle it to receive increasing percentages, up to a maximum of 50%, of the cash we distribute from operating surplus (as defined below) in excess of $0.345 per unit per quarter. The maximum distribution of 50% includes distributions paid to our general partner on its 2% general partner interest and assumes that our general partner maintains its general partner interest at 2%. The maximum distribution of 50% does not include any distributions that our general

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partner may receive on units that it owns. Please read “— General Partner Interest and Incentive Distribution Rights” for additional information.

Operating Surplus and Capital Surplus

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

Operating Surplus. We define operating surplus in the partnership agreement and for any period it generally means:


	•	an operating surplus “basket” equal to ; plus

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

	•	working capital borrowings made after the end of a quarter but on or before the date of determination of operating surplus for the quarter; less

	•	all of our operating expenditures after the closing of this offering (but not the repayment of borrowings) and maintenance capital expenditures; less

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

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

We define operating expenditures in the partnership agreement, and it generally means all of our expenditures, including, but not limited to, taxes, reimbursement of expenses incurred by our general partner on our behalf, non-pro rata purchases of units (other than those made with the proceeds of an interim capital transaction (as defined below), repayment of working capital borrowings, interest payments, payments made in the ordinary course of business under interest rate hedge contracts and commodity hedge contracts and maintenance capital expenditures, provided that operating expenditures will not include:


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

	•	payments of principal of and premium on indebtedness;

	•	expansion capital expenditures;

	•	payment of transaction expenses (including taxes) related to interim capital transactions;

	•	distributions to our partners; and

	•	non-pro rata purchases of units of any class made with the proceeds of an interim capital transaction.

Maintenance capital expenditures represent capital expenditures made to replace partially or fully depreciated assets, to maintain the existing operating capacity of our assets and to extend their useful lives, or other capital expenditures that are incurred in maintaining existing system volumes and related asset base. Expansion capital expenditures represent capital expenditures made to increase the long-term operating capacity or asset base, whether through construction or acquisition. Costs for repairs and minor renewals to maintain facilities in operating condition and that do not extend the useful life of existing assets will be treated as operations and maintenance expenses as we incur them. Our partnership agreement provides that our general partner, with the concurrence of the conflicts committee, determines how to allocate a capital expenditure for the acquisition or expansion of our assets between maintenance capital expenditures and expansion capital expenditures.

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If a working capital borrowing, which increases operating surplus, is not repaid during the twelve-month period following the borrowing, it will be deemed repaid at the end of such period, thus decreasing operating surplus at such time. When such working capital is in fact repaid, it will not be treated as a reduction in operating surplus because operating surplus will have been previously reduced by the deemed repayment.

Capital Surplus. We also define capital surplus in the partnership agreement and in “— Characterization of Cash Distributions” below, and it will generally be generated only by the following, which we call “interim capital transactions”:


	•	borrowings;

	•	sales of our equity and debt securities;

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

	•	the termination of interest rate hedge contracts or commodity hedge contracts prior to the termination date specified therein;

	•	capital contributions received; and

	•	corporate reorganizations or restructurings.

Characterization of Cash Distributions. Our partnership agreement requires that we treat all available cash distributed as coming from operating surplus until the sum of all available cash distributed since the closing of this offering equals the operating surplus as of the most recent date of determination of available cash. Our partnership agreement requires that we treat any amount distributed in excess of operating surplus, regardless of its source, as capital surplus. As reflected above, operating surplus includes an operating surplus “basket” which equals $ million. This amount does not reflect actual cash on hand that is available for distribution to our unitholders. Rather, it is a provision that will enable us, if we choose, to distribute as operating surplus up to this amount of cash we receive in the future from interim capital transactions, that would otherwise be distributed as capital surplus. We do not anticipate that we will make any distributions from capital surplus. The characterization of cash distributions as operating surplus versus capital surplus does not result in a different impact to unitholders for federal tax purposes. Please read “Material Tax Consequences — Tax Consequences of Unit Ownership — Treatment of Distributions” for a discussion of the tax treatment of cash distributions.

Subordination Period

General. Our partnership agreement provides that, during the subordination period (which we define below and in Appendix D), the common units will have the right to receive distributions of available cash from operating surplus each quarter in an amount equal to $0.30 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 of available cash from operating surplus may be made on the subordinated units. 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 available cash to be distributed on the common units.

Subordination Period. The subordination period will extend until the first business day of any quarter beginning after March 31, 2011 that each of the following tests are met:


	•	distributions of available cash from operating surplus on each of the outstanding common units, subordinated units and general partner units equaled or exceeded the minimum quarterly distribution for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date;

	•	the “adjusted operating surplus” (as defined below) generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of the minimum quarterly distributions on all of the outstanding common units, subordinated units and general partner units during those periods on a fully diluted basis; and

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	•	there are no arrearages in payment of the minimum quarterly distribution on the common units.

Expiration of the Subordination Period. When the subordination period expires, each outstanding subordinated unit will convert into one common unit and will then participate pro rata with the other common units in distributions of available cash. In addition, if the unitholders remove our general partner other than for cause and units held by the general partner and its affiliates are not voted in favor of such removal:


	•	the subordination period will end and each subordinated unit will immediately convert into one common unit;

	•	any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and

	•	the general partner will have the right to convert its general partner units and its incentive distribution rights into common units or to receive cash in exchange for those interests.

Early Conversion of Subordinated Units. The subordination period will automatically terminate and all of the subordinated units will convert into common units on a one-for-one basis on the first business day following the distribution of available cash to partners in respect of any quarter ending on or after March 31, 2009 that each of the following occurs:


	•	distributions of available cash from operating surplus on each outstanding common unit, subordinated unit and general partner unit equaled or exceeded $1.80 (150% of the annualized minimum quarterly distribution) for the four-quarter period immediately preceding the date;

	•	the “adjusted operating surplus” (as defined below) generated during the four-quarter period immediately preceding the date equaled or exceeded the sum of the distribution of $1.80 (150% of the annualized minimum quarterly distribution) on all of the outstanding common units, subordinated units and general partner units during that period on a fully diluted basis; and

	•	there are no arrearages in payment of the minimum quarterly distribution on the common units.

Adjusted Operating Surplus. Adjusted operating surplus is intended to reflect the cash generated from operations during a particular period and therefore excludes the two-quarter operating surplus “basket” and net drawdowns of reserves of cash generated in prior periods. We define adjusted operating surplus in the partnership agreement and for any period it generally means:


	•	operating surplus generated with respect to that period; plus

	•	any net decrease made in subsequent periods in cash reserves for operating expenditures initially established with respect to that period to the extent such decrease results in a reduction in adjusted operating surplus in subsequent periods pursuant to the following bullet point; less

	•	any net decrease in cash reserves for operating expenditures with respect to that period not relating to an operating expenditure made with respect to that period; plus

	•	any net increase in cash reserves for operating expenditures with respect to that period required by any debt instrument for the repayment of principal, interest or premium.

Distributions of Available Cash from Operating Surplus during the Subordination Period

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


	•	first, 98% to the common unitholders, pro rata, and 2% to the general partner, until we distribute for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter;

	•	second, 98% to the common unitholders, pro rata, and 2% to the general partner, until we distribute for each outstanding common unit an amount equal to any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters during the subordination period;

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	•	third, 98% to the subordinated unitholders, pro rata, and 2% to the general partner, until we distribute for each subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and

	•	thereafter, in the manner described in “ — General Partner Interest and Incentive Distribution Rights” below.

The preceding discussion is based on the assumptions that our general partner maintains its 2% general partner interest and that we do not issue additional classes of equity securities.

Distributions of Available Cash from Operating Surplus after the Subordination Period

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


	•	first, 98% to all unitholders, pro rata, and 2% to the general partner, until we distribute for each outstanding unit an amount equal to the minimum quarterly distribution for that quarter; and

	•	thereafter, in the manner described in “ — General Partner Interest and Incentive Distribution Rights” below.

The preceding discussion is based on the assumptions that our general partner maintains its 2% general partner interest and that we do not issue additional classes of equity securities.

General Partner Interest and Incentive Distribution Rights

Our partnership agreement provides that our general partner initially will be entitled to 2% of all distributions that we make prior to our liquidation. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its 2% general partner interest if we issue additional units. Our general partner’s 2% interest, and the percentage of our cash distributions to which it is entitled, will be proportionately reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us in order to maintain its 2% general partner interest. Our general partner will be entitled to make a capital contribution in order to maintain its 2% general partner interest in the form of the contribution to us of common units based on the current market value of the contributed common units.

Incentive distribution rights represent the right to receive an increasing percentage (13%, 23% and 48%) of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved. Our general partner currently holds the incentive distribution rights, but may transfer these rights separately from its general partner interest, subject to restrictions in the partnership agreement.

The following discussion assumes that the general partner maintains its 2% general partner interest and continues to own the incentive distribution rights.

If for any quarter:


	•	we have distributed available cash from operating surplus to the common and subordinated unitholders in an amount equal to the minimum quarterly distribution; and

	•	we have distributed available cash from operating surplus on outstanding common units in an amount necessary to eliminate any cumulative arrearages in payment of the minimum quarterly distribution;

then, our partnership agreement requires that we distribute any additional available cash from operating surplus for that quarter among the unitholders and the general partner in the following manner:


	•	first, 98% to all unitholders, pro rata, and 2% to the general partner, until each unitholder receives a total of $0.345 per unit for that quarter (the “first target distribution”);

	•	second, 85% to all unitholders, pro rata, and 15% to the general partner, until each unitholder receives a total of $0.375 per unit for that quarter (the “second target distribution”);

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	•	third, 75% to all unitholders, pro rata, and 25% to the general partner, until each unitholder receives a total of $0.45 per unit for that quarter (the “third target distribution”); and

	•	thereafter, 50% to all unitholders, pro rata, and 50% to the general partner.

Percentage Allocations of Available Cash from Operating Surplus

The following table illustrates the percentage allocations of available cash from operating surplus between the unitholders and our general partner based on the specified target distribution levels. The amounts set forth under “Marginal Percentage Interest in Distributions” are the percentage interests of our general partner and the unitholders in any available cash from operating surplus we distribute up to and including the corresponding amount in the column “Total Quarterly Distribution Per Unit Target Amount,” until available cash from operating surplus we distribute reaches the next target distribution level, if any. The percentage interests shown for the unitholders and the general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below for our general partner include its 2% general partner interest and assume our general partner has contributed any additional capital to maintain its 2% general partner interest and has not transferred its incentive distribution rights.


		Marginal Percentage Interest
	Total Quarterly Distribution	in Distributions
	per Unit Target Amount	Unitholders			General Partner

Minimum Quarterly Distribution	$0.30		98	%		2	%
First Target Distribution	up to $0.345		98	%		2	%
Second Target Distribution	above $0.345 up to $0.375		85	%		15	%
Third Target Distribution	above $0.375 up to $0.45		75	%		25	%
Thereafter	above $0.45		50	%		50	%

General Partner’s Right to Reset Incentive Distribution Levels

Our general partner, as the holder of our incentive distribution rights, has the right under our partnership agreement to elect to relinquish the right to receive incentive distribution payments based on the initial cash target distribution levels and to reset, at higher levels, the minimum quarterly distribution amount and cash target distribution levels upon which the incentive distribution payments to our general partner would be set. Our general partner’s right to reset the minimum quarterly distribution amount and the target distribution levels upon which the incentive distributions payable to our general partner are based may be exercised, without approval of our unitholders or the conflicts committee of our general partner, at any time when there are no subordinated units outstanding and we have made cash distributions to the holders of the incentive distribution rights at the highest level of incentive distribution for each of the prior four consecutive fiscal quarters. The reset minimum quarterly distribution amount and target distribution levels will be higher than the minimum quarterly distribution amount and the target distribution levels prior to the reset such that our general partner will not receive any incentive distributions under the reset target distribution levels until cash distributions per unit following this event increase as described below. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would otherwise not be sufficiently accretive to cash distributions per common unit, taking into account the existing levels of incentive distribution payments being made to our general partner.

In connection with the resetting of the minimum quarterly distribution amount and the target distribution levels and the corresponding relinquishment by our general partner of incentive distribution payments based on the target cash distributions prior to the reset, our general partner will be entitled to receive a number of newly issued Class B units based on a predetermined formula described below that takes into account the “cash parity” value of the average cash distributions related to the incentive distribution rights received by our general partner for the two quarters prior to the reset event as compared to the average cash distributions per common unit during this period. We will also issue an additional amount of general partner units in order to maintain the general partner’s ownership interest in us relative to the issuance of the Class B units.

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The number of Class B units that our general partner would be entitled to receive from us in connection with a resetting of the minimum quarterly distribution amount and the target distribution levels then in effect would be equal to (x) the average amount of cash distributions received by our general partner in respect of its incentive distribution rights during the two consecutive fiscal quarters ended immediately prior to the date of such reset election divided by (y) the average of the amount of cash distributed per common unit during each of these two quarters. Each Class B unit will be convertible into one common unit at the election of the holder of the Class B unit at any time following the first anniversary of the issuance of these Class B units The issuance of Class B units will be conditioned upon approval of the listing or admission for trading of the common units into which the Class B units are convertible by the national securities exchange on which the common units are then listed or admitted for trading. Each Class B unit will receive the same level of distribution as a common unit on a pari passu basis with other unitholders.

Following a reset election by our general partner, the minimum quarterly distribution amount will be reset to an amount equal to the average cash distribution amount per common unit for the two fiscal quarters 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 be correspondingly higher such that we would distribute all of our available cash from operating surplus for each quarter thereafter as follows:


	•	first, 98% to all unitholders, pro rata, and 2% to the general partner, until each unitholder receives an amount equal to 115% of the reset minimum quarter distribution for that quarter;

	•	second, 85% to all unitholders, pro rata, and 15% to the general partner, until each unitholder receives an amount per unit equal to 125% of the reset minimum quarterly distribution for that quarter;

	•	third, 75% to all unitholders, pro rata, and 25% to the general partner, until each unitholder receives an amount per unit equal to 150% of the reset minimum quarterly distribution for that quarter; and

	•	thereafter, 50% to all unitholders, pro rata, and 50% to the general partner.

The following table illustrates the percentage allocation of available cash from operating surplus between the unitholders and our general partner at various levels of cash distribution levels pursuant to the cash distribution provision of our partnership agreement in effect at the closing of this offering as well as following a hypothetical reset of the minimum quarterly distribution and target distribution levels based on the assumption that the average quarterly cash distribution amount per common unit during the two fiscal quarters immediately preceding the reset election was $0.60.


		Marginal Percentage Interest in
		Distribution						Quarterly Distribution
	Quarterly Distribution				General			per Unit Following
	per Unit Prior to Reset	Unitholders			Partner			Hypothetical Reset

Minimum Quarterly Distribution	$0.30		98	%		2	%	$0.60
First Target Distribution	up to $0.345		98	%		2	%	up to $0.69(1)
Second Target Distribution	above $0.345 up to $0.375		85	%		15	%	above $0.69 up to $0.75(2)
Third Target Distribution	above $0.375 up to $0.45		75	%		25	%	above $0.75 up to $0.90(3)
Thereafter	above $0.45		50	%		50	%	above $0.90(3)


(1)		This amount is 115% of the hypothetical reset minimum quarterly distribution.

(2)		This amount is 125% of the hypothetical reset minimum quarterly distribution.

(3)		This amount is 150% of the hypothetical reset minimum quarterly distribution.

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The following table illustrates the total amount of available cash from operating surplus that would be distributed to the unitholders and the general partner, including in respect of incentive distribution rights, or IDRs, based on an average of the amounts distributed per quarter for the two quarters immediately prior to the reset. The table assumes that there are 31,307,064 common units and 638,920 general partner units, representing a 2% general partner interest, outstanding, and that the average distribution to each common unit is $0.60 for the two quarters prior to the reset. The assumed number of outstanding units assumes the conversion of all subordinated units into common units and no additional unit issuances.


	Quarterly		Common		General Partner Cash Distributions Prior to Reset
	Distribution		Unitholders				2%
	per Unit		Cash				General
	Prior to		Distributions		Class B		Partner						Total
	Reset		Prior to Reset		Units		Interest		IDRs		Total		Distributions

Minimum Quarterly Distribution	$	0.30	$	9,392,120		—	$	191,676		—	$	191,676	$	9,583,796
First Target Distribution	$	0.345		1,408,818		—		28,752		—		28,752		1,437,570
Second Target Distribution	$	0.375		939,212		—		22,100		143,643		165,743		1,104,955
Third Target Distribution	$	0.45		2,348,030		—		62,614		720,063		782,677		3,130,707
Thereafter	$	0.45		4,696,060		—		187,842		4,508,218		4,696,060		9,392,120

Total			$	18,784,240		—	$	492,984		5,371,924	$	5,864,908	$	24,649,148

The following table illustrates the total amount of available cash from operating surplus that would be distributed to the unitholders and the general partner with respect to the quarter in which the reset occurs. The table reflects that as a result of the reset there are 31,307,064 common units, 8,953,207 Class B units and 821,639 general partner units, outstanding, and that the average distribution to each common unit is $0.60. The number of Class B units was calculated by dividing (x) $5,371,924 as the average of the amounts received by the general partner in respect of its incentive distribution rights, or IDRs, for the two quarters prior to the reset as shown in the table above by (y) the $0.60 of available cash from operating surplus distributed to each common unit as the average distributed per common unit for the two quarters prior to the reset.


			Common
	Quarterly		Unitholders		General Partner Cash Distributions After Reset
	Distribution		Cash				2% General
	per Unit		Distributions				Partner						Total
	After Reset		After Reset		Class B Units		Interest		IDRs		Total		Distributions

Minimum Quarterly Distribution	$	0.60	$	18,784,240	$	5,371,924	$	492,984		—	$	5,864,908	$	24,649,148
First Target Distribution	$	0.69		—		—		—		—		—		—
Second Target Distribution	$	0.75		—		—		—		—		—		—
Third Target Distribution	$	0.90		—		—		—		—		—		—
Thereafter	$	0.90		—		—		—		—		—		—

Total			$	18,784,240	$	5,371,924	$	492,984	$	—	$	5,864,908	$	24,649,148

Our general partner will be entitled to cause the minimum quarterly distribution amount and the target distribution levels to be reset on more than one occasion, provided that it may not make a reset election except at a time when it has received incentive distributions for the prior four consecutive fiscal quarters based on the highest level of incentive distributions that it is entitled to receive under our partnership agreement.

Distributions from Capital Surplus

How Distributions from Capital Surplus Will Be Made. Our partnership agreement requires that we make distributions of available cash from capital surplus, if any, in the following manner:


	•	first, 98% to all unitholders, pro rata, and 2% to the general partner, until we distribute for each common unit that was issued in this offering an amount of available cash from capital surplus equal to the initial public offering price;

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	•	second, 98% to the common unitholders, pro rata, and 2% to the general partner, until we distribute for each common unit an amount of available cash from capital surplus equal to any unpaid arrearages in payment of the minimum quarterly distribution on the common units; and

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

Effect of a Distribution from Capital Surplus. Our partnership agreement treats a distribution of capital surplus as the repayment of the initial unit price from this initial public offering, which is a return of capital. The initial public offering price less any distributions of capital surplus per unit is referred to as the “unrecovered initial unit price.” Each time a distribution of capital surplus is made, the minimum quarterly distribution and the target distribution levels will be reduced in the same proportion as the corresponding reduction in the unrecovered initial unit price. Because distributions of capital surplus will reduce the minimum quarterly distribution, after any of these distributions are made, it may be easier for the general partner to receive incentive distributions and for the subordinated units to convert into common units. However, any distribution of capital surplus before the unrecovered initial unit price is reduced to zero cannot be applied to the payment of the minimum quarterly distribution or any arrearages.

Once we distribute capital surplus on a unit issued in this offering in an amount equal to the initial unit price, our partnership agreement specifies that the minimum quarterly distribution and the target distribution levels will be reduced to zero. Our partnership agreement specifies that we then make all future distributions from operating surplus, with 50% being paid to the holders of units and 50% to the general partner. The percentage interests shown for our general partner include its 2% general partner interest and assume the general partner has not transferred the incentive distribution rights.

Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels

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


	•	the minimum quarterly distribution;

	•	target distribution levels;

	•	the unrecovered initial unit price; and

	•	the number of common units into which a subordinated unit is convertible.

For example, if a two-for-one split of the common units should occur, the minimum quarterly distribution, the target distribution levels and the unrecovered initial unit price would each be reduced to 50% of its initial level and each subordinated unit would be convertible into two common units. Our partnership agreement provides that we not make any adjustment by reason of the issuance of additional units for cash or property.

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

Distributions of Cash Upon Liquidation

General. If we dissolve in accordance with the partnership agreement, we will sell or otherwise dispose of our assets in a process called liquidation. We will first apply the proceeds of liquidation to the payment of

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our creditors. We will distribute any remaining proceeds to the unitholders and the general partner, in accordance with their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation.

The allocations of gain and loss upon liquidation are intended, to the extent possible, to entitle the holders of outstanding common units to a preference over the holders of outstanding subordinated units upon our liquidation, to the extent required to permit common unitholders to receive their unrecovered initial unit price plus the minimum quarterly distribution for the quarter during which liquidation occurs plus any unpaid arrearages in payment of the minimum quarterly distribution on the common units. However, there may not be sufficient gain upon our liquidation to enable the holders of common units to fully recover all of these amounts, even though there may be cash available for distribution to the holders of subordinated units. Any further net gain recognized upon liquidation will be allocated in a manner that takes into account the incentive distribution rights of the general partner.

Manner of Adjustments for Gain. The manner of the adjustment for gain is set forth in the partnership agreement. If our liquidation occurs before the end of the subordination period, we will allocate any gain to the partners in the following manner:


	•	first, to the general partner and the holders of units who have negative balances in their capital accounts to the extent of and in proportion to those negative balances;

	•	second, 98% to the common unitholders, pro rata, and 2% to the general partner, until the capital account for each common unit is equal to the sum of: (1) the unrecovered initial unit price; (2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs; and (3) any unpaid arrearages in payment of the minimum quarterly distribution;

	•	third, 98% to the subordinated unitholders, pro rata, and 2% to the general partner until the capital account for each subordinated unit is equal to the sum of: (1) the unrecovered initial unit price; and (2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs;

	•	fourth, 98% to all unitholders, pro rata, and 2% to the general partner, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the first target distribution per unit over the minimum quarterly distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the minimum quarterly distribution per unit that we distributed 98% to the unitholders, pro rata, and 2% to the general partner, for each quarter of our existence;

	•	fifth, 85% to all unitholders, pro rata, and 15% to the general partner, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the second target distribution per unit over the first target distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the first target distribution per unit that we distributed 85% to the unitholders, pro rata, and 15% to the general partner for each quarter of our existence;

	•	sixth, 75% to all unitholders, pro rata, and 25% to the general partner, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the third target distribution per unit over the second target distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the second target distribution per unit that we distributed 75% to the unitholders, pro rata, and 25% to the general partner for each quarter of our existence; and

	•	thereafter, 50% to all unitholders, pro rata, and 50% to the general partner.

The percentage interests set forth above for our general partner include its 2% general partner interest and assume the general partner has not transferred the incentive distribution rights.

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If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that clause (3) of the second bullet point above and all of the third bullet point above will no longer be applicable.

Manner of Adjustments for Losses. If our liquidation occurs before the end of the subordination period, we will generally allocate any loss to the general partner and the unitholders in the following manner:


	•	first, 98% to holders of subordinated units in proportion to the positive balances in their capital accounts and 2% to the general partner, until the capital accounts of the subordinated unitholders have been reduced to zero;

	•	second, 98% to the holders of common units in proportion to the positive balances in their capital accounts and 2% to the general partner, until the capital accounts of the common unitholders have been reduced to zero; and

	•	thereafter, 100% to the general partner.

If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that all of the first bullet point above will no longer be applicable.

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

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SELECTED HISTORICAL AND PRO FORMA FINANCIAL AND OPERATING DATA

The following table shows (i) selected historical financial and operating data of Columbia Gulf and (ii) selected pro forma financial data of NiSource Energy Partners, L.P. for the periods and as of the dates indicated. The selected historical financial data of Columbia Gulf as of December 31, 2005 and 2006 and for the years ended December 31, 2004, 2005 and 2006 are derived from the historical audited financial statements of Columbia Gulf appearing elsewhere in this prospectus. The selected historical financial data for Columbia Gulf as of September 30, 2007 and for the nine months ended September 30, 2006 and 2007 are derived from the historical unaudited financial statements of Columbia Gulf, appearing elsewhere in this prospectus. The selected historical financial data of Columbia Gulf as of December 31, 2002, 2003 and 2004 and for the years ended December 31, 2002 and 2003 are derived from unaudited financial statements not included herein. The table should also be read together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

The selected pro forma financial data of NiSource Energy Partners, L.P. for the year ended December 31, 2006, and as of and for the nine months ended September 30, 2007 are derived from the unaudited pro forma financial statements of NiSource Energy Partners, L.P. included elsewhere in this prospectus. The pro forma adjustments have been prepared as if certain transactions to be effected at the closing of this offering had taken place on September 30, 2007, in the case of the pro forma balance sheet, and as of January 1, 2006, in the case of the pro forma statements of operations for the year ended December 31, 2006, and for the nine months ended September 30, 2007. These transactions include:


	•	Columbia Gulf’s distribution of accounts receivable of $62.4 million to NiSource;

	•	Our receipt of $250.0 million in gross proceeds from the issuance and sale of 12,500,000 common units to the public;

	•	Our borrowing approximately $37.0 million in term debt and $163.0 million in revolving debt under our new $250.0 million credit facility;

	•	Our use of proceeds from this offering and related borrowings to pay transaction fees and expenses and underwriting commissions, retire assumed indebtedness, reimburse subsidiaries of NiSource for certain capital expenditures, make distributions to subsidiaries of NiSource, fund working capital and anticipated capital expenditures and purchase qualifying investment grade securities; and

	•	The disposition of certain offshore assets currently owned by Columbia Gulf.

The following table includes the non-GAAP financial measure of EBITDA. We define our EBITDA as net income plus interest expense (net of AFUDC), income taxes and depreciation and amortization, less interest income and other, net. For a reconciliation of EBITDA to its most directly comparable financial measures calculated and presented in accordance with GAAP, please read “ — Non-GAAP Financial Measures.”

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																						NiSource Energy Partners,
																						L.P. Pro Forma
	Columbia Gulf																								Nine Months
																Nine Months						Year Ended			Ended
	Year Ended December 31,															Ended September 30,						December 31,			September 30,
	2002			2003			2004			2005			2006			2006			2007			2006			2007
	(In millions, except per unit and operating data)

Statement of Operations Data:
Total operating revenues	$	142.8		$	135.4		$	127.0		$	116.1		$	123.3		$	90.8		$	99.6		$	117.3		$	94.5
Operating expenses:
Operation and maintenance		69.7			55.5			55.7			51.3			61.2			41.2			44.4			55.1			38.4
Loss (gain) on sale or impairment of assets		(0.2	)		—			—			—			—			—			—			—			—
Depreciation and amortization		23.2			23.2			23.2			22.2			22.0			16.5			16.4			19.1			14.8
Other taxes		8.3			8.7			7.8			8.5			8.1			6.0			6.2			8.1			6.2

Total operating expenses		101.0			87.4			86.7			82.0			91.3			63.7			67.0			82.3			59.4

Operating income		41.8			48.0			40.3			34.1			32.0			27.1			32.6			35.0			35.1

Other income (deductions)
Interest expense (net of AFUDC)		(6.4	)		(6.1	)		(5.4	)		(5.0	)		(2.7	)		(2.2	)		(1.8	)		(15.2	)		(10.7	)
Interest income		—			—			0.4			0.6			0.5			0.5			—			1.5			0.8
Other, net		(0.1	)		—			—			0.5			0.7			0.7			—			0.7			—
Income taxes		(13.5	)		(16.2	)		(13.1	)		(11.7	)		(12.2	)		(9.2	)		(10.7	)		(0.1	)		(0.1	)

Net income	$	21.8		$	25.7		$	22.2		$	18.5		$	18.3		$	16.9		$	20.1		$	21.9		$	25.1

Net income per limited partners’ unit
Common unit																						$	1.02		$	0.90
Subordinated unit																							—			0.55
Balance Sheet Data (at period end):
Total assets	$	676.0		$	671.2		$	700.6		$	716.0		$	763.1					$	783.3					$	841.2
Net property plant and equipment		308.6			303.0			292.5			305.5			310.6						321.5						321.5
Long-term debt-affiliated, excluding amounts due within one year		67.9			67.9			58.3			67.9			67.9						67.9						265.9
Total capitalization		515.4			540.8			555.1			552.6			556.1						576.2						701.8
Other Financial Data:
Net cash provided by operating activities								45.3			51.0			40.1			26.7			20.0			43.7			25.0
EBITDA								63.5			56.3			54.0			43.6			49.0			54.1			49.9
Maintenance capital expenditures(1)								7.0			31.4			22.2			13.2			11.6			22.2			11.6
Expansion capital expenditures(1)								—			0.1			2.9			1.1			10.5			2.9			10.5
Columbia Gulf Operating Data:
Mainline:
Transportation capacity (Bcf/d)(2)								2.156			2.156			2.156			2.156			2.156
Contracted firm capacity (Bcf/d)(3)								2.453			2.177			2.266			2.245			2.471
Transported volumes (Bcf)								523.6			506.7			519.7			392.3			477.4
Laterals (East and West):
Transportation capacity (Bcf/d)(4)								2.157			2.157			2.157			2.157			2.157
Contracted firm capacity (Bcf/d)								0.616			0.589			0.680			0.634			0.870
Transported volumes (Bcf)								428.9			422.1			379.7			291.3			247.6


(1)		Maintenance capital expenditures are capital expenditures made to replace partially or fully depreciated assets, to maintain the existing operating capacity of our assets and to extend their useful lives, or other capital expenditures that are incurred in maintaining existing system volumes and related cash flows. Expansion capital expenditures are made to acquire additional assets to grow our business, to expand and

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		upgrade our systems and facilities, and to construct or acquire similar systems or facilities. This includes projects designed to reduce costs or enhance revenues.

(2)		Represents one-way peak-design capacity from Rayne, Louisiana to Leach, Kentucky.

(3)		Our contracted firm capacity exceeds our one-way peak-design capacity during the indicated periods as a result of our ability to transport natural gas in multiple directions on our pipeline system.

(4)		Represents the maximum combined peak-design capacity of the two laterals — East (1.054 Bcf/d) and West (1.103 Bcf/d).

Non-GAAP Financial Measures

We define our EBITDA as net income plus interest expense (net of AFUDC), income taxes and depreciation and amortization, less interest income and other, net. EBITDA is used as a supplemental financial measure by management and by external users of our financial statements, such as investors and commercial banks, to assess:


	•	the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;

	•	the ability of our assets to generate cash sufficient to pay interest on our indebtedness and to make distributions to our partners; and

	•	our operating performance and return on invested capital as compared to those of other publicly traded limited partnerships that own energy infrastructure assets, without regard to their financing methods and capital structure.

EBITDA should not be considered an alternative to net income, operating income, net cash provided by operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. EBITDA excludes some, but not all, items that affect net income and operating income and these measures may vary among other companies. Therefore, EBITDA as presented may not be comparable to similarly titled measures of other companies.

The following tables present reconciliations of the non-GAAP financial measure of EBITDA to the respective GAAP financial measures of net income and net cash provided (used) by operating activities on a historical basis and on a pro forma basis as adjusted for this offering.

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															NiSource Energy
	Columbia Gulf														Partners, L.P. Pro Forma
																		Nine
															Year			Months
															Ended			Ended
									Nine Months Ended						December			September
	Year Ended December 31,								September 30,						31,			30,
	2004		2005			2006			2006			2007			2006			2007
	(In millions)

Reconciliation of Non-GAAP “EBITDA” to GAAP “Net Income”
Net income	$	22.2	$	18.5		$	18.3		$	16.9		$	20.1		$	21.9		$	25.1
Add:
Interest expense (net of AFUDC)		5.4		5.0			2.7			2.2			1.8			15.2			10.7
Income taxes		13.1		11.7			12.2			9.2			10.7			0.1			0.1
Depreciation and amortization		23.2		22.2			22.0			16.5			16.4			19.1			14.8
Less:
Interest income		0.4		0.6			0.5			0.5			—			1.5			0.8
Other, net		—		0.5			0.7			0.7			—			0.7			—

EBITDA	$	63.5	$	56.3		$	54.0		$	43.6		$	49.0		$	54.1		$	49.9

Reconciliation of Non-GAAP “EBITDA” to GAAP “Net cash provided by operating activities”
Net cash provided by operating activities	$	45.3	$	51.0		$	40.1		$	26.7		$	20.0		$	43.7		$	25.0
Less:
Interest income		0.4		0.6			0.5			0.5			—			1.5			0.8
Add:
Interest expense (net of AFUDC)		5.4		5.0			2.7			2.2			1.8			15.2			10.7
Income taxes paid		10.3		10.7			9.4			9.2			10.0			0.1			0.1
Other		1.0		1.1			(4.3	)		(5.1	)		(2.8	)		(10.0	)		(5.1	)
Changes in operating working capital		1.9		(10.9	)		6.6			11.1			20.0			6.6			20.0

EBITDA	$	63.5	$	56.3		$	54.0		$	43.6		$	49.0		$	54.1		$	49.9

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion of financial condition and results of operations should be read in conjunction with Columbia Gulf’s historical financial statements and notes and the partnership’s pro forma financial statements and notes included elsewhere in this prospectus.

Overview

We are a growth-oriented Delaware limited partnership recently formed to own and operate natural gas transportation pipelines and related energy infrastructure assets. Our initial asset is the Columbia Gulf pipeline system, a FERC-regulated interstate natural gas transportation pipeline system which is wholly-owned and operated by us and has approximately 3,400 miles of transmission pipelines and 11 compressor stations with approximately 445,450 certificated horsepower. This system’s transportation assets are located in Kentucky, Louisiana, Mississippi and Tennessee with non-contiguous assets located in Texas, Wyoming, and the offshore Gulf of Mexico. The Columbia Gulf pipeline system is the primary interstate natural gas transportation system serving Columbia Gas Transmission’s Midwestern and Mid-Atlantic end-use markets.

We continually evaluate organic as well as greenfield development opportunities to increase the volume of natural gas transportation capacity reserved and transported on our system. Our expansion strategy centers on our efforts to expand deliveries to rapidly growing markets in the Southeast, Midwest and Mid-Atlantic, while continuing to increase supply from new and diverse basins, particularly the Gulf Coast, North Texas (Barnett Shale) and Rocky Mountain supply regions. Since January 1, 2006, we have either commenced or completed construction of expansion projects representing a total capital cost to us of approximately $13.4 million through September 30, 2007, with approximately $8.8 million in additional costs to be paid through December 31, 2007 and an estimated $55.8 million to be paid in 2008.

Factors That Impact Our Business

Key factors that impact our business are the supply of and demand for natural gas in the markets in which we operate; our customers and their requirements; the extent to which our Columbia Gulf pipeline system is interconnected to diverse supply sources and end markets; and the government regulation of natural gas pipelines and storage. These key factors also play an important role in how we evaluate our business and how we implement our long-term strategies.

Supply and Demand of Natural Gas. Our business is dependent on the continued availability of natural gas production and reserves in the regions we access, and we monitor our market areas closely for shifts in natural gas supply and demand. The Columbia Gulf pipeline system provides our customers with gas supply transportation services to market demand areas. However, low prices for natural gas or regulatory limitations could adversely affect development of additional reserves and production that are accessible by our pipeline. Production from existing wells and natural gas supply basins with access to our pipelines will naturally decline over time. Additionally, 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. Accordingly, to maintain or increase the volume of natural gas transported on our pipelines and cash flows associated with the transportation of gas, our customers must continually obtain new supplies of natural gas. Demand for natural gas is typically impacted by shifts in residential usage, the amount of natural gas fired power generation utilized and commodity price volatility.

Customers. Our customer mix for natural gas transportation services includes LDCs, municipal utilities, direct industrial users, electric power generators, marketers, producers and LNG importers. The Columbia Gulf pipeline system is the primary interstate gas transmission system serving Columbia Gas Transmission’s Midwestern and Mid-Atlantic end-use markets. Our customers use our transportation services for a variety of reasons:


	•	LDCs and electric power generators typically require a secure and reliable supply of natural gas over a sustained period of time to meet the needs of their customers. Our LDC customers will typically enter

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		into long-term firm transportation contracts to ensure both a ready supply of natural gas and sufficient transportation capacity over the life of the contract;


	•	Producers of natural gas require the ability to deliver their product to market typically enter into firm transportation contracts to ensure that they will have sufficient capacity available to deliver their product to delivery points with greater market liquidity; and

	•	Marketers use our transportation services to capitalize on natural gas price volatility over time or between markets.

Interconnections to Diverse Supply Sources and End-Use Markets. Our customers seek capacity on pipelines that have access to diverse natural gas supply sources and multiple end-use markets in order to reduce the risk of supply interruption, improve price transparency and increase transactional liquidity. The Columbia Gulf pipeline system was originally constructed for the sole purpose of moving natural gas produced on the Gulf Coast to Midwestern and Mid-Atlantic end-use markets. Since 2006, approximately 1.5 Bcf/d of access to new supply and approximately 0.7 Bcf/d of access to new markets have been added to the system through new interconnects and other system modifications. As a result of this development of laterals and interconnects the functionality of this system has fundamentally changed. In addition to traditional supplies on the Gulf Coast, we now have access to multiple strategic natural gas supply sources, including basins in North Texas (Barnett Shale), East Texas, North Louisiana and the Appalachian Basin. Similarly, through interconnections with major interstate and intrastate pipelines, we also access large and growing markets in the Northeast, Midwest, Mid-Atlantic and Southeast United States, and serve industrial, commercial, electric generation and residential customers in Tennessee, Mississippi and Louisiana. We continue to seek to increase the flexibility and diversity of the Columbia Gulf pipeline system by attracting new interconnects that broaden our access to diverse supplies and markets. New interconnect opportunities will allow us to market our services to new customers and develop new services for existing customers. For example, a new interconnection with Midwestern Gas Transmission near Nashville, Tennessee currently under construction is expected to provide us with access to the Chicago hub, and to add additional sources of natural gas supply from the Rocky Mountain region.

Regulation. Government regulation of natural gas transportation significantly impacts our business. FERC regulatory policies govern the rates that pipelines are permitted to charge customers for interstate transportation and storage of natural gas. The operation and maintenance of our assets are also governed by other federal and state regulatory agencies, including the DOT.

Under the rate design utilized by our pipeline system as approved by the FERC, a majority of our fixed costs are recovered through a capacity reservation fee charged to firm customers. This capacity reservation fee is charged on a monthly basis to reserve daily capacity, based on the customer’s peak period requirements. Interruptible customers do not reserve daily capacity and are not charged a reservation fee. Variable costs under both firm and interruptible contracts are recovered through a usage fee applied on a volumetric basis to the gas actually transported.

Under certain circumstances we are permitted to enter into contracts with customers under “negotiated rates.” These rates are different from the rates imposed by the FERC, and as such, certain revenues collected may be subject to possible refunds upon final FERC orders.

How We Evaluate Our Operations

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


	•	Sales and percentage of physical capacity sold, including the contract mix of firm service revenues compared to interruptible service revenues;

	•	Operating expenses; and

	•	EBITDA.

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Sales and Percentage of Physical Capacity Sold. We compete for transportation customers based on the type of service a customer needs, operating flexibility, available capacity and price. We provide a significant portion of our transportation services under firm contracts and derive a smaller portion of our revenues through interruptible contracts, however, we seek to maximize the portion of our physical capacity sold under firm contracts.

Firm service contracts require us to reserve pipeline capacity for a given customer between certain receipt and delivery points. Firm customers generally pay a “capacity reservation” fee based on the amount of capacity being reserved regardless of whether the capacity is used, plus an incremental usage fee when the capacity is used. Annual capacity reservation revenues derived from firm service contracts generally remain constant over the life of the contract because the revenues are based upon capacity reserved and not whether the capacity is actually used. The high percentage of our revenue derived from capacity reservation fees mitigates the risk to us of revenue fluctuations due to changes in near-term supply and demand conditions, and our ability to maintain or increase the amount of firm service we provide is key to assuring a consistent revenue stream. For the twelve months ended September 30, 2007 approximately 80.1% of our transportation revenues were derived from capacity reservation fees paid under firm contracts and 8.7% of our transportation revenues were derived from usage fees under firm contracts.

Interruptible transportation service is typically short term in nature and is generally used by customers that either do not need firm service or have been unable to contract for firm service. These customers pay a usage fee only for the volume of gas actually transported. Our obligation to provide this service is limited to available capacity not otherwise used by our firm customers, and customers receiving services under interruptible contracts are not assured capacity in our pipeline facilities. We provide our interruptible service at competitive prices in order to position ourselves to capture short term market opportunities as they occur. We view interruptible service as an important part of our strategy to optimize revenues from our assets. For the twelve months ended September 30, 2007, approximately 11.2% of our transportation revenues were derived from interruptible contracts.

Operating Expenses. Our operating expenses typically do not vary significantly based upon the amount of gas we transport. We obtain in-kind fuel reimbursements from customers in accordance with each individual tariff or applicable contract terms. While expenses may not materially vary with throughput, our expenses can vary significantly from period to period. The timing of our expenditures during a year generally fluctuate with customer demands as we typically schedule planned maintenance during off-peak periods. Additionally, fluctuations in project development costs are impacted by the level of project development activity during a given period and the timing of project approval. Changes in regulation can also impact our maintenance requirements and affect the timing and amount of our costs and expenditures.

NiSource Corporate Services Company and Columbia Gas Transmission, both wholly-owned subsidiaries of NiSource, have provided general and administrative services to Columbia Gulf and will continue to provide certain services to us. These services include human resources, finance and accounting, legal and insurance among others. Please read “Certain Relationships and Related Party Transactions — Contracts with Affiliates — Services Agreements”

EBITDA. EBITDA is used as a supplemental financial measure by our management and by external users of our financial statements such as investors, commercial banks and others, to assess:


	•	the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;

	•	the ability of our assets to generate cash sufficient to pay interest on our indebtedness and to make distributions to our partners; and

	•	our operating performance and return on invested capital as compared to those of other publicly traded limited partnerships that own energy infrastructure assets, without regard to their financing methods and capital structure.

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We define our EBITDA as net income plus interest expense (net of AFUDC), income taxes and depreciation and amortization, less interest income and other, net. EBITDA is not a presentation made in accordance with GAAP and is defined differently by different companies in our industry. As such, our definition of EBITDA may not be comparable to similarly titled measures of other companies. EBITDA should not be considered an alternative to net income, operating income, cash from operations or any other measure of financial performance or liquidity presented in accordance with GAAP. EBITDA excludes some, but not all, items that affect net income and operating income and these measures may vary among other companies. Therefore, EBITDA as presented may not be comparable to similarly titled measures of other companies. For a reconciliation of our EBITDA to the most directly comparable financial measures calculated and presented in accordance with GAAP, please read “Selected Historical and Pro Forma Financial and Operating Data — Non-GAAP Financial Measures.”

Results of Operations

The following table and discussion is a summary of our results of operations for the years ended December 31, 2004, 2005 and 2006, and the nine months ended September 30, 2006 and 2007.


	Year Ended December 31,									Nine Months Ended September 30,
	2004			2005			2006			2006			2007
							(In millions)

Operating Revenues
Transportation revenues	$	124.6		$	114.3		$	121.8		$	89.7		$	98.4
Other revenues		2.4			1.8			1.5			1.1			1.2

Total Operating Revenues		127.0			116.1			123.3			90.8			99.6

Operating Expenses
Operation and maintenance		55.7			51.3			61.2			41.2			44.4
Depreciation and amortization		23.2			22.2			22.0			16.5			16.4
Other taxes		7.8			8.5			8.1			6.0			6.2

Total Operating Expenses		86.7			82.0			91.3			63.7			67.0

Operating Income		40.3			34.1			32.0			27.1			32.6

Other Income (Deductions)
Interest expense (net of AFUDC)		(5.4	)		(5.0	)		(2.7	)		(2.2	)		(1.8	)
Interest income		0.4			0.6			0.5			0.5			—
Other, net		—			0.5			0.7			0.7			—

Total Other Income (Deductions)		(5.0	)		(3.9	)		(1.5	)		(1.0	)		(1.8	)

Income Before Income Taxes		35.3			30.2			30.5			26.1			30.8
Income Taxes		13.1			11.7			12.2			9.2			10.7

Net Income	$	22.2		$	18.5		$	18.3		$	16.9		$	20.1

EBITDA(a)		63.5			56.3			54.0			43.6			49.0


(a)		We define EBITDA as net income plus interest expense (net of AFUDC), income taxes and depreciation and amortization, less interest income and other, net. For a reconciliation of our EBITDA to the most directly comparable financial measures calculated and presented in accordance with GAAP, please read “Selected Historical and Pro Forma Financial and Operating Data — Non-GAAP Financial Measures.”

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Nine Months Ended September 30, 2007 Compared to the Nine Months Ended September 30, 2006

Operating Revenues — Operating revenues increased $8.8 million, or 9.7%, for the first nine months of 2007 compared to the same period of 2006. This increase was primarily due to $9.9 million in increased firm capacity reservation fees and net revenues of $1.0 million recognized for a business interruption claim, partially offset by a reduction in firm and interruptible usage fees of $1.7 million and the impact of $1.5 million in revenues recognized in 2006 for a bankruptcy claim involving Enron.

Operating Expenses — Operating expenses increased $3.3 million, or 5.2%, for the first nine months of 2007 compared to the same period of 2006. This increase was primarily due to a $3.8 million increase in employee and administrative expenses, including increased allocated service costs under a NiSource agreement with a third-party service provider and higher compensation and benefit expenses. Also contributing to this increase was $2.5 million in higher insurance premiums related to offshore and onshore facilities located in or near the Gulf of Mexico, partially offset by a $2.8 million reduction of a reserve for a legal matter.

Other Income (Deductions) — Other Income (Deductions) for the first nine months of 2007 reduced income by $1.8 million compared to a reduction in income of $1.0 million for the first nine months of 2006 as a result of higher interest rates in 2007 compared to 2006.

Income Tax Expense — Income taxes increased $1.5 million in the first nine months of 2007 compared to the same period of 2006 primarily due to higher pre-tax income in the first nine months of 2007.

Year Ended December 31, 2006 Compared to the Year Ended December 31, 2005

Operating Revenues — Operating revenues increased $7.2 million, or 6.2%, for the year ended December 31, 2006 compared to the same period of 2005. This increase was primarily due to $7.0 million in increased firm capacity reservation fees and $1.5 million in revenues recognized for a bankruptcy claim involving Enron, partially offset by $1.5 million due to lower revenues from power production customers.

Operating Expenses — Operating expenses increased $9.3 million, or 11.3%, for the year ended December 31, 2006 compared to the same period of 2005. This increase was primarily due to a $5.4 million increase in insurance premiums related to offshore and onshore facilities located in or near the Gulf of Mexico and a $4.8 million reserve for a legal matter, partially offset by a $2.3 million decrease in employee and administrative expenses.

Other Income (Deductions) — Other Income (Deductions) in 2006 reduced income by $1.5 million compared to a reduction in income of $3.9 million in 2005 due primarily to lower interest expense of $2.3 million as a result of the refinancing of senior unsecured notes of an affiliate in November 2005 at reduced interest rates.

Income Tax Expense — Income taxes increased $0.5 million in 2006 compared to 2005 primarily due to higher pre-tax income and a higher effective tax rate. The effective income tax rate in 2006 of 40.0% was 1.3% higher due to the accrual of non-deductible expenses partially offset by lower state income tax expense in 2006 as a result of a state tax settlement.

Year Ended December 31, 2005 Compared to the Year Ended December 31, 2004

Operating Revenues — Operating revenues decreased $10.9 million, or 8.6%, for the year ended December 31, 2005 compared to the same period of 2004. This decrease was primarily due to the 2004 renegotiation of firm service contracts with major pipeline customers which resulted in a revenue reduction of approximately $8.5 million and a reduction in firm and interruptible usage fees of $1.8 million in 2005.

Operating Expenses — Operating expenses decreased $4.7 million in 2005, or 5.4%, from 2004. This decrease was primarily due to $3.3 million of pipeline integrity management costs that were capitalized in accordance with FERC rules which the company had previously expensed, $1.6 million reimbursed by customers for repairs incurred on behalf of those customers and reduced outside services expense of $1.1 million. These expense decreases were partially offset by a $2.0 million increase in employee and administrative expenses.

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Other Income (Deductions) — Other Income (Deductions) in 2005 reduced income by $3.9 million compared to a reduction in income of $5.0 million in 2004, the change between periods was due to higher affiliated interest income and other miscellaneous income.

Income Tax Expense — Income taxes decreased $1.4 million in 2005 compared to 2004 primarily due to lower pre-tax income in 2005, and was partially offset by a higher effective tax rate in 2005 than 2004. The effective income tax rate in 2005 of 38.7% was 1.6% higher due to state income tax benefits recognized in 2004.

Future Trends and Outlooks

We expect our business to continue to be affected by the following key trends. Our expectations are based on management assumptions and currently available information. To the extent management’s underlying assumptions about or interpretations of available information prove to be incorrect, actual results could vary materially from our expected results. Please read “Risk Factors.”

Benefits from System Expansions. We expect that our results of operations for the year ending December 31, 2007 and thereafter will benefit from increased revenues associated with the following expansion projects for the Columbia Gulf pipeline system: 3.0 Bcf/d of new gas supply pipeline interconnections in the vicinity of our Delhi, Louisiana compressor station (Perryville area), recently completed Rayne, Louisiana compressor station modifications, and expanded interstate pipeline interconnections in Kentucky and Louisiana. These projects have provided our customers with increased access to new sources of supply while extending their market reach. In addition, a new bi-directional interconnect with an interstate pipeline near Nashville, Tennessee is currently under construction, and is expected to provide us with direct access to the Chicago hub and to Rocky Mountain gas supplies.

We are also pursuing expansions and extensions of our Mainline System and our Louisiana Laterals to further increase market access in the New Orleans-Baton Rouge Industrial Corridor and to serve growing demand in the Southeastern and Florida residential, commercial, industrial and electric generation markets. Various third parties have also announced interconnections between Columbia Gulf and new Gulf Coast high deliverability salt dome storage projects, several of which are currently under construction. We expect that completion of these projects will increase utilization along our pipeline system.

Growing Markets. Our system provides upstream supply to Mid-Atlantic, Midwestern and Southeastern end-use markets where the Energy Information Administration (EIA) estimates natural gas consumption will grow by approximately 1.3%, 0.8%, and 2.3% respectively, per year between 2007 and 2017. In addition, we have expanded our access to serve Florida markets where growth is expected from the construction of new natural gas fired electric generation facilities which are projected to account for over 90% of forecast nameplate capacity additions between 2007 and 2011. The EIA estimates that natural gas powered electric generation in Florida will increase by 2.1% per year from 88.6 Gigawatt hours in 2007 to 108.6 Gigawatt hours in 2017.

Diversity of Supply Sources. Domestic gas production in the United States is not expected to keep pace with domestic consumption. According to the EIA, production in the lower 48 states is estimated to grow approximately 0.4% per year, from 51.4 Bcf/d in 2007 to 53.4 Bcf/d in 2012, while U.S. natural gas demand in 2012 is estimated to be 70.1 Bcf/d. While supply in some areas in which we operate is increasing due to new discoveries and increased production, traditional supply in other areas in which we operate is beginning to decline. As supply from these areas declines, or becomes less attractive because of vulnerability to hurricanes and other disruptions, the national supply profile is shifting to new sources of gas, including basins in the Mid-Continent and Appalachia as well as non-conventional sources. A significant portion of the supply shortfall is expected to be met through LNG imports, which are expected to be delivered predominately through terminals along the Gulf Coast.

Growth of Natural Gas Storage Facilities. Natural gas storage is becoming an increasingly important factor in the natural gas transportation marketplace, and will play a significant role in handling the increased deliveries of LNG expected in the coming years. As a consequence, a substantial number of natural gas

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storage projects have been announced and are under development, especially in the Texas and Louisiana areas. According to an October 2006 EIA report, as of July 2006, there were 38 underground storage projects underway in the United States, including 13 storage projects in Texas and Louisiana, with expected in-service dates between 2006 and 2008, of which 15 are new facilities and 23 are expansions. These projects, assuming full implementation, would increase the working gas capacity in the U.S. by 5% by the end of 2008. We believe the Columbia Gulf pipeline system is well positioned to take advantage of future transportation opportunities created from increased storage capacity in Texas and Louisiana.

Liquidity and Capital Resources

Our ability to finance our operations, including funding to meet debt obligations, capital expenditures, working capital needs and other requirements, will depend on our ability to generate cash in the future. Historically, our sources of liquidity included cash generated from operations and from long-term debt issuances and short-term borrowings from NiSource Finance. Our cash receipts were historically deposited in NiSource’s money pool accounts and cash disbursements were made from those accounts. Consequently, our historical financial statements have reflected minimal cash balances. Cash transactions processed on our behalf by NiSource Finance were reflected as intercompany advances between us and NiSource Finance. Following this offering, we plan to maintain our own bank accounts but will continue to rely on NiSource personnel to manage cash and investment through our management arrangements with NiSource Corporate Services Company.

Subsequent to this offering, we expect our sources of liquidity to include:


	•	the retention of a portion of the proceeds from our initial public offering, as described below;

	•	cash generated from operations;

	•	borrowings under our $250.0 million credit facility;

	•	cash realized from the liquidation of qualifying investment grade securities that will be pledged under our credit facility;

	•	issuances of additional partnership units; and

	•	debt offerings.

We expect to use $91.3 million retained from the proceeds of our initial public offering to offset future capital expenditures and fund working capital. We believe that cash generated from these sources described above will be sufficient to meet our short-term working capital requirements, long-term capital expenditure requirements and quarterly cash distributions.

Working Capital. Working capital is the amount by which current assets exceed current liabilities. Our working capital requirements will be primarily driven by changes in accounts receivable and accounts payable. These changes are primarily impacted by such factors as credit and the timing of collections from customers and the level of spending for maintenance and expansion activity.

Changes in the terms of our transportation arrangements have a direct impact on our generation and use of cash from operations due to their impact on net income, along with the resulting changes in working capital. A material adverse change in operations or available financing may impact our ability to fund our requirements for liquidity and capital resources.

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Columbia Gulf Cash Flow. Net cash provided by operating activities, net cash (used in) provided by investing activities and net cash provided by (used in) financing activities for the years ended December 31, 2004, 2005 and 2006, and for the nine months ended September 30, 2006 and 2007, were as follows:


										For the Nine Months Ended
	For the Years Ended December 31,									September 30,
	2004			2005			2006			2006			2007
							(In millions)

Net cash provided by operating activities	$	45.3		$	51.0		$	40.1		$	26.7		$	20.0
Net cash (used in) provided by investing activities	$	(34.6	)	$	(20.3	)	$	(38.8	)	$	(22.9	)	$	(33.0	)
Net cash provided by (used in) financing activities	$	(10.7	)	$	(30.7	)	$	(1.3	)	$	(3.8	)	$	13.0

Operating Activities

Net cash flows provided by operating activities decreased by $6.7 million for the first nine months of 2007 compared to the first nine months of 2006 primarily due to expenditures incurred to repair damages resulting from hurricanes Katrina, Rita and Ivan and the turbine failure at the Delhi compressor station along with other increases in working capital which were partially offset by the receipt of business interruption proceeds related to these events.

Net cash provided by operating activities decreased by $10.9 million in 2006 compared to 2005 primarily due to expenditures incurred to repair damage resulting from hurricanes Katrina, Rita and Ivan and the turbine failure at the Delhi compressor station along with other increases to working capital.

Investing Activities

The changes in cash used for investing activities are driven by the level of capital expenditures from period to period. The pipeline transportation business is capital intensive, requiring significant investment to maintain and upgrade existing operations.

Capital costs to replace assets damaged by hurricanes Katrina, Rita and Ivan and the turbine failure at the Delhi compressor station, net of insurance recoveries are also contributing to the fluctuations within investing activities. For more information related to these costs, please read Note 14 “Capital Costs for Damages” to the Notes to the Financial Statements for the years ended December 31, 2006, 2005 and 2004 as well as Note 11 “Capital Costs for Damages” to the Notes to the Financial Statements for the nine months ended September 30, 2006 and 2007.

Cash flows used in investing activities are also driven by money pool deposits. The large money pool deposit in 2004 resulted from a relatively low amount of capital expenditures and the delay of a dividend payment until 2005.

The following table and discussion is a summary of capital expenditures for the years ended December 31, 2004, 2005 and 2006, and the nine months ended September 30, 2006 and 2007.


							Nine Months Ended
	Year Ended December 31,						September 30,
	2004		2005		2006		2006		2007

Capital Expenditures
Maintenance	$	7.0	$	31.4	$	22.2	$	13.2	$	11.6
Expansion		—		0.1		2.9		1.1		10.5

Total Capital Expenditures	$	7.0	$	31.5	$	25.1	$	14.3	$	22.1

We typically incur capital expenditures for maintenance and for expansion. Maintenance capital expenditures are capital expenditures made to replace partially or fully depreciated assets, to maintain the existing operating capacity of our assets and to extend their useful lives, or other capital expenditures that are incurred in maintaining existing system volumes and related cash flows. Expansion capital expenditures are

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made to acquire additional assets to grow our business, to expand and upgrade our systems and facilities, and to construct or acquire similar systems or facilities. This includes projects designed to reduce costs or enhance revenues.

Capital expenditures for the first nine months of 2007 compared to the first nine months of 2006 increased due to higher expansion expenditures related to the Terrebonne and Evangeline projects and modifications to the Rayne compressor station partially offset by lower maintenance costs. Capital expenditures for 2006 compared to 2005 decreased due to lower maintenance expenditures partially offset by higher expansion expenditures. The lower maintenance spending in 2006 was the result of spending in 2005 for DOT-mandated pipeline upgrades of $16.0 million and capitalized pipeline integrity costs of $5.1 million, partially offset by environmental emissions compliance work of $6.0 million performed during 2006. Capital expenditures for 2005 compared to 2004 increased due to higher maintenance expenditures during 2005. The major drivers for the increase in 2005 maintenance expenditures were the $16.0 million of DOT-mandated pipeline upgrades and capitalized pipeline integrity costs of $5.1 million.

We expect maintenance capital expenditures and expansion capital expenditures for the twelve months ending March 31, 2009 to be $24.1 million and $62.0 million, respectively. Of the $24.1 million, approximately $15.6 million relates to pipeline retirements for offshore assets, pipeline relocation costs as a result of highway and Mississippi levee construction, the modification of facilities for the integrity management program, upgrades to ancillary compressor systems and measurement equipment modifications. We estimate that the maintenance capital expenditures of a recurring nature for the twelve months ending March 31, 2009 will be approximately $8.5 million. Our anticipated expansion capital expenditures for the twelve months ending March 31, 2009 relate to proposed interconnects and compression expansions to deliver gas to Florida Gas Transmission and other markets on the East Lateral.

We expect to fund future capital expenditures with funds generated from our operations, borrowings under our new credit facility and the issuance of additional partnership units and debt offerings.

Financing Activities

Cash flow used for financing activities primarily consisted of dividends paid to Columbia Energy and changes in borrowings from the NiSource money pool.

Description of Credit Agreement. In connection with the closing of this offering, we will enter into a $250.0 million credit facility under which we expect to borrow approximately $37.0 million of term debt and $163.0 million of revolving debt upon the closing of this offering. We will distribute the aggregate net amount of the proceeds of such borrowings to subsidiaries of NiSource, which distribution will be made in partial consideration of the assets contributed to us upon the closing of this offering. Please read “Certain Relationships and Related Party Transactions — Distributions and Payments to our General Partner and its Affiliates.” We expect that the credit facility will also be available for general partnership purposes, including working capital and capital expenditures.

We expect that our obligations under the revolving portion of our credit facility will be unsecured and that term borrowings will be secured at all times by qualifying investment grade securities in an amount equal to or greater than the outstanding principal amount of the term loan. We expect that upon any prepayment of term borrowings, the amount of the revolving portion of our credit facility will be automatically increased to the extent that the prepayment of our term borrowings is made in connection with a permitted acquisition or permitted capital expenditure. We expect that revolving indebtedness under the credit facility will rank equally with all our outstanding unsecured and unsubordinated debt.

We expect that the credit facility will prohibit us from making distributions of available cash to unitholders if any default or event of default (as defined in the credit facility) exists. In addition, we expect the credit facility will contain other covenants. If an event of default exists under the credit facility, we expect that the lenders will be able to accelerate the maturity of all borrowings under the credit facility and exercise other rights and remedies. The credit facility is subject to a number of conditions, including the negotiation, execution and delivery of definitive documentation.

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Proceeds From Sale of Units. We expect to receive net proceeds from this offering of approximately $235.0 million after deducting underwriting discounts but before paying expenses associated with the offering and related formation transactions. We anticipate using the aggregate net proceeds of this offering to:


	•	pay approximately $3.9 million of expenses associated with the offering and related formation transactions, including a structuring fee payable to Lehman Brothers Inc. for evaluation, analysis and structuring of our partnership;

	•	distribute $71.7 million in cash to subsidiaries of NiSource as reimbursement for capital expenditures related to the Columbia Gulf assets incurred by subsidiaries of NiSource prior to this offering related to the assets to be contributed to us upon the closing of this offering;

	•	retire approximately $31.1 million of indebtedness owed to a subsidiary of NiSource;

	•	purchase approximately $37.0 million of qualifying investment grade securities, which will be assigned as collateral to secure the term loan portion of our credit facility;

	•	use approximately $64.0 million to fund working capital; and

	•	use the remaining amount of $27.3 million to offset identified maintenance capital expenditures expected to be incurred through 2010, including an amount to offset costs we expect to incur in connection with government-mandated pipeline improvements.

If the underwriters’ option to purchase additional common units is exercised in full, we will (1) use the net proceeds of approximately $35.1 million from the sale of these additional securities to purchase an equivalent amount of qualifying investment grade securities and (2) borrow an additional amount of term debt equal to the net proceeds to be received from the exercise of the underwriters’ option. The qualifying securities purchased will be assigned as collateral to secure such additional term loan borrowings. The proceeds of the additional term loan borrowings will be used to redeem from a subsidiary of NiSource a number of common units equal to the number of common units issued upon exercise of the underwriters’ option, at a price per common unit equal to the proceeds per common unit before expenses but after underwriting discounts and a structuring fee.

Total Contractual Cash Obligations. A summary of our total contractual cash obligations as of December 31, 2006, is as follows:


	Total		2007		2008		2009		2010		2011		After
			(In millions)

Long-term debt	$	67.9	$	—	$	—	$	—	$	—	$	—	$	67.9
Interest payments on long-term debt		41.8		3.8		3.8		3.7		3.7		3.7		23.1
Operating leases		4.6		0.4		0.2		0.1		0.1		0.1		3.7

Total contractual obligations	$	114.3	$	4.2	$	4.0	$	3.8	$	3.8	$	3.8	$	94.7

As of September 30, 2007, there have been no material changes to our contractual cash obligations.

In addition to the obligations existing as of December 31, 2006, upon the closing of this offering, we expect to incur approximately $37.0 million in term debt and $163.0 million in revolving debt under our new credit facility. We expect interest payments on these amounts to approximate $12.5 million per year for each year that such borrowings are outstanding. Additionally, in connection with the closing of this offering we will enter into an omnibus agreement with NiSource under which we will make annual payments to NiSource for general and administrative services under the agreement.

Market Risk Disclosures

Risk is an inherent part of our business and the extent to which management properly and effectively identifies, assesses, monitors and manages each of the various types of risk involved in the business can significantly impact profitability. We seek to identify, assess, monitor and manage, in accordance with defined policies and procedures, interest rate risk and credit risk. In addition, we are exposed to market risk associated

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with the supply of and demand for natural gas and the impact of changes in natural gas prices, and can also be negatively affected by sustained downturns or sluggishness in the regional economy.

As risk management is a multi-faceted process, the owner of our general partner, NiSource, maintains a Risk Management Committee which oversees our operations and provides insight into specialized products and markets to assist us with risk assessment and risk management. Senior management takes an active role in the risk management process and has developed policies and procedures that require specific administrative and business functions to assist in the identification, assessment and control of various risks. In recognition of the increasingly varied and complex nature of the energy business, our risk management policies and procedures continue to evolve and are subject to ongoing review and modification.

Interest Rate Risk. Changes in interest rates expose us to risk as a result of our issuance of variable rate debt. Senior management monitors market interest rates to identify the need to mitigate this risk, including consideration of using derivative instruments to hedge against unfavorable changes in interest rates. A 100-basis point change in the interest rate of our existing variable-rate debt would not result in a material change to our interest expense. Therefore, we have not previously entered into hedging contracts to mitigate this risk.

Credit Risk. Our exposure to credit risk is monitored by a Corporate Credit Risk function of NiSource. Credit risk arises due to the possibility that a customer, supplier or counterparty will not be able or willing to fulfill its obligations on a transaction on or before the settlement date. Exposure to credit risk is measured in terms of both current obligations and the market value of any forward positions. Current credit exposure is generally measured by the notional or principal value of obligations and direct credit substitutes, such as commitments, stand-by letters of credit and guarantees. In determining exposure, we consider collateral that we hold to reduce individual counterparty credit risk.

Off Balance Sheet Arrangements

We do not have off balance sheet financing entities or structures to third parties and maintain no debt obligations that contain provisions requiring accelerated payment of the related obligation in the event of specified declines in credit ratings.

Critical Accounting Policies and Estimates

The accounting policies discussed below are considered by management to be critical to an understanding of our financial statements as their application places the most significant demands on management’s judgment. Due to the inherent uncertainties involved with this type of judgment, actual results could differ significantly from estimates and may have a material adverse impact on our results of operations, equity or cash flows. For additional information concerning our other accounting policies, please see the Notes to the financial statements of Columbia Gulf included elsewhere in this prospectus.

Accounting for Regulation. We follow the accounting and reporting requirements of Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation” (SFAS No. 71). SFAS No. 71 provides that rate-regulated companies account for and report assets and liabilities consistent with the economic effect of the way in which regulators establish rates, if the rates established are designed to recover the costs of providing the regulated service and it is probable that such rates can be charged and collected. Certain expenses and credits subject to utility regulation or rate determination normally reflected in income are deferred on the balance sheet and are recognized in income as the related amounts are included in service rates and recovered from or refunded to customers.

We have designed our rates to recover the costs of providing our regulated service and determined it is probable that such rates can be charged and collected. In the event that regulation significantly changes the opportunity for us to recover our costs in the future, we may no longer meet the criteria for the application of SFAS No. 71. In such event, a write-down of all or a portion of our existing regulatory assets and liabilities could result. If transition cost recovery was approved by the FERC that would meet the requirements under generally accepted accounting principles for continued accounting as regulatory assets and liabilities during such recovery period, the regulatory assets and liabilities would be reported at the recoverable amounts. If

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unable to continue to apply the provisions of SFAS No. 71, we would be required to apply the provisions of SFAS No. 101, “Regulated Enterprises — Accounting for the Discontinuation of Application of Financial Accounting Standards Board Statement No. 71.” In management’s opinion, we will be subject to SFAS No. 71 for the foreseeable future.

Goodwill. Goodwill represents the excess of purchase price over fair value of net assets acquired. We evaluate goodwill for potential impairment under the guidance of SFAS No. 142, “Goodwill and Other Intangible Assets (SFAS No. 142).” Under this provision, goodwill is subject to an annual test for impairment. We have designated June 30 as the date we perform the annual review for goodwill impairment. Additional impairment tests are performed between the annual reviews if events or changes in circumstances make it more likely than not that the fair value is below its carrying amount.

Impairment testing of goodwill consists of a two-step process. The first step involves a comparison of the implied fair value of a reporting unit with its carrying amount. If the carrying amount of the reporting unit exceeds its fair value, the second step of the process involves a comparison of the fair value and carrying value of the goodwill of that reporting unit. If the carrying value of the goodwill of a reporting unit exceeds the implied fair value of that goodwill, an impairment loss is recognized in an amount equal to the excess.

We use a discounted cash flow analysis to determine fair value. Key assumptions in the determination of fair value include the use of an appropriate discount rate and estimated future cash flows. We did not record any impairment of our goodwill in 2006, 2005 and 2004. Goodwill was $321.3 million at December 31, 2006 and 2005.

Recently Issued Accounting Pronouncements

SFAS No. 157 — Fair Value Measurements (SFAS No. 157). In September 2006, the FASB issued SFAS No. 157 to define fair value, establish a framework for measuring fair value and to expand disclosures about fair value measurements. We are currently reviewing the provisions of SFAS No. 157 to determine the impact it may have on our financial statements and Notes to Financial Statements. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007 and should be applied prospectively, with limited exceptions.

SFAS No. 159 — The Fair Value Option for Financial Assets and Financial Liabilities — Including an amendment of FASB Statement No. 115. In February 2007, the FASB issued SFAS No. 159 which permits entities to choose to measure certain financial instruments at fair value that are not currently required to be measured at fair value. Upon adoption, a cumulative adjustment will be made to beginning retained earnings for the initial fair value option remeasurement. Subsequent unrealized gains and losses for fair value option items will be reported in earnings. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007 and should not be applied retrospectively, except as permitted for certain conditions for early adoption. We are currently reviewing the provisions of SFAS No. 159 to determine whether to elect fair value measurement for any of our financial assets or liabilities when we adopt this standard in 2008.

FIN 48 — Accounting for Uncertainty in Income Taxes (FIN 48). In June 2006, the FASB issued FIN 48 to reduce the diversity in practice associated with certain aspects of the recognition and measurement requirements related to accounting for income taxes. Specifically, this interpretation requires that a tax position meet a “more-likely-than-not recognition threshold” for the benefit of an uncertain tax position to be recognized in the financial statements and requires that benefit to be measured at the largest amount of benefit that is greater than 50% likely of being realized upon ultimate settlement. When determining whether a tax position meets the more-likely-than-not recognition threshold, it is to be based on whether it is probable of being sustained on audit by the appropriate taxing authorities, based solely on the technical merits of the position. Additionally, FIN 48 provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. FIN 48 is effective for fiscal years beginning after December 15, 2006.

On January 1, 2007, we adopted the provisions of FIN 48. There was no impact to the opening balance of retained earnings as a result of the implementation of FIN 48.

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INDUSTRY OVERVIEW

Natural gas is a critical component of energy consumption in the United States. The U.S. natural gas pipeline grid is the link between upstream exploration and production activities and downstream end-use markets. This network is a highly integrated transmission and distribution grid that transports natural gas from producing regions to customers such as LDCs, industrial users and electric generation facilities. It is capable of transporting gas to and from nearly any location in the lower 48 states. According to the Energy Information Administration, the natural gas pipeline grid comprises:


	•	More than 210 natural gas pipeline systems;

	•	300,000 miles of interstate and intrastate transmission pipelines;

	•	181 Bcf/d of natural gas transportation capacity;

	•	More than 1,400 compressor stations that maintain pressure on the natural gas pipeline network; and assure continuous forward movement of supplies;

	•	More than 11,000 delivery points, 5,000 receipt points, and 1,400 interconnection points that provide for the transfer of natural gas throughout the United States;

	•	29 hubs or market centers that provide additional interconnections;

	•	394 underground natural gas storage facilities;

	•	55 locations where natural gas can be imported/exported via pipelines; and

	•	5 LNG (liquefied natural gas) import facilities and 100 LNG peaking facilities.

U.S. Natural Gas Pipeline Network


Source:	Energy Information Administration, Office of Oil & Gas, Natural Gas Division, Gas Transportation Information System, June 2007.

Interstate pipelines carry natural gas across state boundaries and are subject to FERC regulation on (1) the rates charged for their services, (2) the terms and conditions of their services, and (3) the location, construction and abandonment of their facilities. Intrastate pipelines transport natural gas within a particular state and are typically not subject to FERC regulation.

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The map below shows various market hubs throughout the pipeline network, including the Henry Hub and Columbia Gas TCO Pool, and illustrates the flow of gas that connects areas of supply to end-use markets. These market hubs provide two key services: transportation between and interconnections with other pipelines, and the physical coverage of short-term receipt/delivery balancing needs. They are critical to the inter/intrastate pipeline network and to the transportation of natural gas throughout the continental U.S.

U.S. Natural Gas Market Hubs

Source: Energy Information Administration, August 2004.

Natural Gas Demand

Substantially all natural gas consumed in the United States is transported to end-users on the natural gas pipeline grid. Therefore, utilization of the pipeline grid is highly correlated with the level of domestic consumption of natural gas. According to EIA, natural gas consumption in the United States is expected to grow from 55.0 Bcf/d in 2006 to 65.3 Bcf/d in 2017.

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U.S. Natural Gas Consumption

Source: Energy Information Administration, Annual Energy Outlook, February 2007.

The industrial and electricity generation sectors are the largest users of natural gas in the United States. During the three years ended December 31, 2006, these two sectors accounted for approximately 62% of the total natural gas consumed in the United States. The electricity generation sector is the fastest growing demand sector in the natural gas market. Over 200 GW of new natural gas fired generation capacity has been brought online between 1997 and 2006 and from 2007-2011, the EIA projects that an additional 46 GW of gas fired electricity generation will be constructed.

Historically, demand for natural gas is greater during the winter, primarily due to residential and commercial heating applications. Natural gas produced in excess of that which is used during the summer months is typically stored to meet the increased demand for natural gas during the winter months. However, with the recent trend towards natural gas fired electric generation, demand for natural gas during the summer months is now increasing to satisfy additional electricity requirements for residential and commercial cooling.

According to the EIA, which uses U.S. census divisions for its regional forecasts, the East South Central region is projected to be the fastest growing region for natural gas demand over the next five years. For the period from 2007-2012, the regional growth rates vary from 1% per year in the Mountain and East North Central regions to over 5% in the East South Central region, which is projected to increase from 2.8 Bcf/d in 2007 to 3.7 Bcf/d in 2017. Consumption in New England is expected to go from 2.4 Bcf/d in 2007 to 2.7 Bcf/d in 2017 and growth in the East North Central region is expected to increase from 10.5 Bcf/d to 11.4 Bcf/d in that same period.

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Projected U.S. Natural Gas Consumption by Region

Source: Energy Information Administration, Annual Energy Outlook, February 2007.

Natural Gas Supply

According to the EIA, domestic gas production in the United States is not expected to keep pace with domestic consumption. Production in the lower 48 states is estimated to grow approximately 0.4% per year, from 51.4 Bcf/d in 2007 to 53.4 Bcf/d in 2017. This compares to estimated U.S. natural gas demand in 2012 of 62.6 Bcf/d.

While the Gulf Coast region of the United States, which includes offshore Gulf of Mexico and East Texas, has historically been the most prolific U.S. natural gas producing region, production in the region declined by as much as 10% between 2002-2004 and even more dramatically in the aftermath of hurricanes Rita and Katrina. Despite this decline, total natural gas production for the United States increased by approximately 2.5% from 2005 to 2006 and is projected to grow approximately 3.0% from 2006 to 2007, according to the EIA. The projected decline in production from the shallow waters of the Gulf of Mexico is expected to continue to be offset by expanding natural gas exploration and development activities in onshore unconventional tight gas plays, such as the Barnett Shale and Bossier Sands of North and East Texas, as well as increased exploration activities in deepwater Gulf of Mexico.

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U.S. Natural Gas Production

Source: Energy Information Administration, Annual Energy Outlook, February 2007.

At the same time, production in the Rocky Mountains has increased while consumption and pipeline export capacity have remained limited. Natural gas reserves in the Rocky Mountain States account for nearly 22% of the total natural gas reserves in the United States, and are mostly located in unconventional tight-gas or coalbed formations. Dry natural gas production in Colorado, Utah, and Wyoming has increased from an average of 5.49 Bcf/d in 2000 to 8.61 Bcf/d in 2006. Total natural gas volumes delivered to consumers in Colorado, Utah, and Wyoming are much less than volumes produced in those states averaging 1.66 Bcf/d in 2006 which was only slightly above the level of deliveries in 2001. Pipeline capacity that exports natural gas flows from this region was 8.49 Bcf/d in 2006. Efforts to increase the pipeline infrastructure in the Rocky Mountain States are expected to add roughly 1.5 Bcf/d of capacity to transport natural gas from the region by the end of 2008.

Projected Natural Gas Production by Region


Source:	Energy Information Administration, Annual Energy Outlook. Gulf Coast includes on and offshore production, February 2007.

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Despite an overall increase, the U.S. is still projected to encounter a supply shortfall. In conjunction with this supply/demand imbalance, as gas from regions like the Gulf of Mexico becomes less attractive due to vulnerability to hurricanes and other disruptions, the national supply profile is shifting to new, and, in some cases, to non-conventional sources of gas. This shortfall is expected to be met through natural gas imports from Canada as well as through LNG imports, the majority of which are expected to be delivered through terminals along the U.S. Gulf Coast. LNG imports are expected to grow approximately 15% per year for the period between 2007 and 2017. The table below shows the EIA’s estimate of LNG imports into the Gulf Coast region through 2017.

U.S. Liquefied Natural Gas Import Volume

Source: Energy Information Administration, Annual Energy Outlook, February 2007.

LNG is expected to become an important part of the U.S. energy market. According to the EIA, LNG’s share of total U.S. natural gas supply could increase from approximately 4% in 2007 to approximately 15% by 2017. Unlike domestic production however, LNG imports will not provide a steady stream of supply because the number and timing of deliveries are driven by spot prices that fluctuate with market dynamics, and individual deliveries involve the receipt of large volumes within a relatively short period of time. Given the extensive pipeline infrastructure and available natural gas processing capability in and around the region, nearly 20 LNG terminals are in various stages of planning, approval, construction, and operation on the Gulf Coast. LNG projects for this area are, on average, larger than those planned for other U.S. locations. In addition, due to the large existing industrial base located in the region and less anticipated resistance from the local population, more of these projects are likely to obtain the necessary regulatory approvals and be developed more expeditiously than proposed projects located in other areas of the country.

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BUSINESS

Overview

We are a growth-oriented Delaware limited partnership recently formed by NiSource to own and operate natural gas transportation pipelines and related energy infrastructure assets. Our initial asset is the Columbia Gulf pipeline system, a FERC-regulated interstate natural gas transportation pipeline system owned by our wholly owned subsidiary, Columbia Gulf Transmission Company, LLC (Columbia Gulf).

The Columbia Gulf pipeline system consists of approximately 3,400 miles of pipelines and 11 compressor stations with approximately 445,450 horsepower located primarily in Louisiana, Mississippi, Tennessee and Kentucky. These pipelines include:


	•	The Mainline System. Columbia Gulf’s Mainline System extends from southern Louisiana to a pipeline interconnection with Columbia Gas Transmission Corporation (Columbia Gas Transmission), a subsidiary of NiSource, in northeastern Kentucky. The Mainline System consists of approximately 2,550 miles of pipelines with peak-design throughput capacity of 2.2 Bcf/d; and

	•	The Louisiana Laterals. The Louisiana Laterals consist of the West Lateral and the East Lateral. The West Lateral extends from an interconnection with the Mainline System along the southern tier of Louisiana westward to Hackberry, Louisiana, while the East Lateral extends eastward to New Orleans and Venice, Louisiana. The Louisiana Laterals consist of approximately 850 miles of pipelines with maximum peak-design capacity in excess of 1.0 Bcf/d on each lateral.

The Columbia Gulf pipeline system was originally constructed for the sole purpose of moving natural gas produced on the Gulf Coast to Midwestern and Mid-Atlantic end-use markets. Since 2006, approximately 1.5 Bcf/d of access to new supply and approximately 0.7 Bcf/d of access to new markets have been added to the system through new interconnects and other system modifications. As a result of this development of laterals and pipeline interconnects the functionality of this system has fundamentally changed. In addition to traditional supplies on the Gulf Coast, we now have access to multiple strategic natural gas supply sources, including basins in North Texas (Barnett Shale), East Texas, North Louisiana and the Appalachian Basin. Similarly, we now provide a pathway for delivery to growing markets in the Southeast in addition to our traditional Midwestern and Mid-Atlantic markets. With interconnections to 29 interstate and 13 intrastate pipelines as of September 30, 2007, we no longer operate solely as a supplier of point-to-point gas transportation services, but as a flexible network that connects multiple producing areas to multiple end-use markets. By continuing to develop the Columbia Gulf pipeline system as a flexible transportation link, we believe we can increase the amount of cash we are able to distribute to you.

Business Strategies

Our primary business objectives are to generate predictable and stable cash flow and, over time, to increase our quarterly cash distribution per unit. We intend to achieve these objectives by executing the following strategies:


	•	Pursue economically attractive organic expansion opportunities and greenfield development projects. We continually evaluate opportunities in both existing and new markets to increase the volume of natural gas transportation capacity reserved and the volume of natural gas transported on our system. We focus on expansion and development opportunities that generate value for our customers and acceptable returns for us. We intend to implement this strategy by doing the following:


	•	Expanding the physical capacity of our system to serve existing and new markets;

	•	Creating operational flexibility which allows customers to move volumes of natural gas using non-traditional paths; and

	•	Creating market flexibility to provide incremental opportunities to customers.

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		To execute this strategy, we are pursuing expansions and extensions to further increase our market access in the New Orleans-Baton Rouge industrial corridor and the growing Southeastern and Florida residential, commercial, industrial and electric generation markets.

	•	Optimize our asset base and increase profitability by expanding our points of supply and market access. While we traditionally operated the Columbia Gulf pipeline system as a point-to-point delivery system, we now pursue a “connectivity” strategy which seeks to increase the flexibility and diversity of our system by leveraging its strong geographic position to attract new interconnects that broaden our access to multiple supply sources and markets. New interconnect opportunities will allow us to market our services to new customers and develop new services for existing customers. For example, a new interconnection with Midwestern Gas Transmission near Nashville, Tennessee currently under construction is expected to provide us with access to the Chicago hub, and to add access to additional sources of natural gas supply from the Rocky Mountain region.

	•	Grow through joint ventures, partnerships and accretive acquisitions of energy infrastructure assets from both NiSource and third parties. We intend to expand our current business by pursuing joint ventures, partnerships and acquisitions that are accretive to distributable cash flow. We will seek acquisitions that provide the opportunity for operational efficiencies or higher capacity utilization of our existing assets, as well as acquisitions in new business lines and geographic areas of operation. We will consider certain factors in deciding whether to pursue an acquisition, including, but not limited to:


	•	economic characteristics of the acquisition such as return on capital and cash flow stability;

	•	the region in which the assets are located (both contiguous and non-contiguous to our existing assets); and

	•	the availability and sources of capital required to finance the acquisition.

We also intend to pursue commercial and acquisition opportunities either independently or jointly with NiSource and/or with third parties. Additionally, we may have the opportunity to acquire assets directly from NiSource, although we cannot predict whether any such opportunities will be made available to us and NiSource is under no obligation to offer such opportunities to us.

Competitive Strengths

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


	•	Our strategic location allows us to transport natural gas from diverse supply sources to high-demand markets at competitive transportation rates. Our customers benefit from our numerous interstate and intrastate pipeline interconnections, which reduce the risk of supply interruptions, increase price transparency and transactional liquidity, and provide a variety of downstream market opportunities. Our ability to transport gas from diverse supply sources to multiple end-use markets on a competitive cost basis provides us with a significant advantage because our customers value the flexibility and reliability this provides.


	•	Access to diverse and growing supply sources. Our pipeline assets have direct access to the Gulf of Mexico and onshore Louisiana supply sources and, through major pipeline interconnects, access to numerous natural gas producing regions, including the South Texas and Louisiana Gulf Coast, North Louisiana, East Texas, North Texas (Barnett Shale) and Appalachian regions. A new bi-directional interconnect with Midwestern Gas Transmission near Nashville, Tennessee is currently under construction and is expected to provide us with access to the Chicago hub and to add Rocky Mountain gas supplies. In addition, we are well positioned to provide access to other non-traditional sources of supply such as the developing Fayette Shale in Arkansas and LNG imported on the Gulf Coast.

	•	Access to multiple attractive and liquid end-use markets. Our system provides customers with direct access to the Henry Hub and TCO Pool, two of the most actively traded markets in North

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		America. Through 29 interstate and 13 intrastate pipeline interconnections, our system provides upstream supply to serve growing markets in the Mid-Atlantic, Midwest, Florida and Southeast. Based on published FERC tariff rates, we believe we are in a position to provide competitively-priced transportation services along our system.


	•	Our firm contracts and capacity reservation fees provide cash flow stability. Our FERC-approved rate structure reduces the risk that weather or changing market conditions will create revenue volatility. This rate structure provides us with more stable and predictable cash flows than other contractual forms. For the twelve months ended September 30, 2007 we generated approximately 80.1% of our transportation revenues from capacity reservation fees paid under firm contracts. As of September 30, 2007, our firm mainline system contracts had a weighted contract term of 5.7 years and a weighted average remaining contract life of approximately 3.8 years, and our firm contracts for the Louisiana Laterals had a weighted average contract term of 4.4 years and a weighted average remaining contract life of 2.5 years, in each case based on contracted volumes. In addition, because we do not own the gas we transport and we retain a portion of the gas transported in our system to use as fuel for our compressors to transport our customers’ gas, we have no direct commodity price exposure.

	•	Our pipeline assets have been prudently operated and well maintained. Our prudently operated and well maintained assets enable us to provide reliable customer service while minimizing the cost of ongoing maintenance and operation. We have completed mandated internal inspections of nearly half of our pipeline system, including 67% of the high consequence areas along our system and have found them to be in good condition and in compliance with all federal pipeline safety regulations. Our affiliation with NiSource provides access to state-of-the-art in-line inspection tools that enhance our ability to maintain system integrity with greater scheduling flexibility and cost certainty. In addition, we operate our pipelines to provide safe and reliable service and have been recognized for our outstanding employee safety record by the American Gas Association.

	•	Our affiliation with NiSource. We will have an ongoing affiliation with NiSource. As the owner of the 2% general partner interest, all of our incentive distribution rights, and a 58.9% limited partner interest in us, we believe that NiSource has an incentive to promote and support the successful execution of our business plan, and to pursue projects that directly or indirectly enhance our value. Through our relationship with NiSource, we will have access to a significant pool of management talent, strong commercial relationships throughout the energy industry and access to NiSource’s broad operational, commercial, technical, risk management and administrative infrastructure. NiSource also has a long history of successfully executing pipeline and storage expansion projects through a disciplined approach of evaluating, marketing, permitting and constructing both organic and greenfield expansions. We also believe that our relationship with NiSource offers the opportunity for increased access to strategic acquisitions of complementary energy infrastructure assets from affiliates and third parties.

	•	Our experienced management team has a proven track record of operating large and complex interstate natural gas transportation, storage and marketing assets. The management team employed by our general partner has a proven track record of successfully managing, operating, developing, building, acquiring and integrating energy infrastructure assets. The operating executives of our general partner’s management team have experience in various aspects of the energy industry, including significant commercial, marketing, operational, engineering, legal, regulatory, financial, acquisition and business development expertise.

Our Relationship with NiSource

One of our principal strengths is our relationship with NiSource, which following this offering will own our 2% general partner, all of our incentive distribution rights, and a 58.9% limited partner interest in us. NiSource is an 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. NiSource is the largest natural gas distribution company operating east of the Rocky Mountains, as measured by number of customers. We intend to utilize the significant experience

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of NiSource’s management team to execute our growth strategy, including the construction and acquisition of additional energy infrastructure assets. NiSource’s common stock is traded on the New York Stock Exchange under the symbol “NI.”

NiSource’s Gas Transmission and Storage Operations subsidiaries own and operate approximately 16,000 miles of interstate pipelines (including the Columbia Gulf pipeline system) and operate one of the nation’s largest underground natural gas storage systems with 36 storage fields capable of storing approximately 252 Bcf of working gas as of December 31, 2006. Through its subsidiaries, NiSource owns and operates an interstate pipeline network extending from offshore in the Gulf of Mexico to Lake Erie, New York and the eastern seaboard. Together, these companies serve customers in 19 northeastern, Mid-Atlantic, Midwestern and southern states and the District of Columbia. The Gas Transmission and Storage Operations subsidiaries are engaged in several projects that will expand their facilities and throughput. The Millennium Pipeline is currently under construction and will connect the Empire Pipeline to the Algonquin Pipeline in order to transport natural gas to the greater New York City metropolitan area. In addition, Hardy Storage, a partnership that owns a natural gas storage field in West Virginia and serves the eastern United States, commenced operations in April 2007 and will be fully operational in 2009. In addition to its Gas Transmission and Storage Operations, NiSource’s Natural Gas Distribution Operations serves customers in nine states, and its Electric Operations generates, transmits and distributes electricity to customers in the northern part of Indiana and engages in wholesale and transmission transactions.

We will enter into an omnibus agreement with NiSource, our general partner, and certain of their affiliates that will govern our relationship with them regarding certain reimbursement and indemnification matters. Please read “Certain Relationships and Related Party Transactions — Omnibus Agreement.” While our relationship with NiSource and its subsidiaries is a significant attribute, it may also be a source of conflicts. For example, neither NiSource nor any of its affiliates are prohibited from competing with us. NiSource and its affiliates may acquire, construct or dispose of assets in the future without any obligation to offer us the opportunity to purchase or construct those assets. Please read “Conflicts of Interest and Fiduciary Duties.”

Columbia Gulf Pipeline System

General. Our pipeline system provides direct access to Gulf of Mexico and onshore Louisiana supply sources and, through major pipeline interconnects, access to numerous natural gas producing regions, including the South Texas and Louisiana Gulf Coast, North Louisiana, East Texas, North Texas (Barnett Shale) and Appalachian regions. Our system is connected to 109 natural gas receipt points, 60 natural gas delivery points and seven bi-directional meter stations.

We offer our customers direct physical access to two of the most actively traded markets in North America, the Henry Hub in South Louisiana and the TCO Pool at Leach, Kentucky. Through 29 interstate and 13 intrastate pipeline interconnections, our system provides upstream supply to serve growing markets in the Mid-Atlantic, Midwest, Florida and Southeast. Based on published FERC tariff rates, we believe we are in a position to provide competitively-priced transportation services along our system. Our average daily throughput on our Mainline System has grown from approximately 1.4 Bcf/d during 2004 to approximately 1.75 Bcf/d during the first nine months of 2007.

Due to changing market dynamics, such as a decline in Gulf Coast production, we experienced a decline in throughput on our Louisiana Laterals since 2004. However, with the expansion in our market access through our connectivity strategy we increased the amount of capacity on our Louisiana Laterals under firm contracts by approximately 37% over the twelve month period ended September 30, 2007. We believe our connectivity strategy and projects undertaken will ultimately lead to an increase in throughput on our Louisiana Laterals.

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The following table sets forth the throughput data of our system for the periods presented.


	Columbia Gulf Throughput (Bcf)
							Nine Months Ended		Nine Months Ended
	Year Ended December 31,						September 30,		September 30,
	2004		2005		2006		2006		2007

Mainline:
Transportation capacity (Bcf/d)(1)		2.156		2.156		2.156		2.156		2.156
Contracted firm capacity (Bcf/d)(2)		2.453		2.177		2.266		2.245		2.471
Transported volumes (Bcf)		523.6		506.7		519.7		392.3		477.4
Laterals (East and West):
Transportation capacity (Bcf/d)(3)		2.157		2.157		2.157		2.157		2.157
Contracted firm capacity (Bcf/d)		0.616		0.589		0.680		0.634		0.870
Transported volumes (Bcf)		428.9		422.1		379.7		291.3		247.6


(1)		Represents one-way peak design capacity from Rayne, Louisiana to Leach, Kentucky.

(2)		Our contracted firm capacity exceeds our one-way peak-design capacity during the indicated periods as a result of our ability to transport natural gas in multiple directions on our pipeline system.

(3)		Represents the maximum combined peak-design capacity of the two laterals — East (1.054 Bcf/d) and West (1.103 Bcf/d).

Customers. We transport natural gas for a broad mix of customers, including LDCs, municipal utilities, direct industrial users, electric power generators, marketers and producers and LNG importers. In addition to serving markets directly connected to our system, we serve markets and customers in a variety of other regions through numerous interconnections with third-party interstate and intrastate pipelines.

As of September 30, 2007, we had 88 firm contract customers. Our three largest customers for the year ended December 31, 2006 were Columbia Gas of Ohio Inc. (a subsidiary of NiSource), Washington Gas Light Company and Baltimore Gas & Electric Company. Contracts with these three customers accounted for approximately 13.1%, 9.1% and 7.0% of our contracted revenues, respectively, during 2006, although each of these customers contracted a portion of their reserved capacity to third parties that paid us directly for the subcontracted amounts. Our three largest customers for the nine months ended September 30, 2007 were Columbia Gas of Ohio, Inc., Washington Gas Light Company and BG Energy Merchants, LLC. Contracts with these customers accounted for approximately 11.6%, 8.2% and 7.5% of our contracted revenues, respectively for the nine months ended September 30, 2007. For the nine months ended September 30, 2007 our top 25 largest non-affiliated customers measured by contracted revenues generated approximately 63.4% of our transportation revenue and 21 of those customers were investment grade as of September 30, 2007 as determined by ratings by Moody’s or Standard and Poor’s credit rating agencies. As a result of our recent mainline and lateral expansion projects, we have expanded the capacity under contract with several long-term customers, while also increasing the number of counterparties with which we do business.

Contracts. Our customers contract with us for services primarily under three types of contracts:


	•	Firm contracts. Under firm contracts our customers are obligated to pay monthly capacity reservation fees over the term of the contract. These monthly capacity reservation fees are payable to us regardless of the actual pipeline capacity utilized. An incremental usage fee based on the actual volume of natural gas transported is applied when a customer utilizes the capacity it has reserved under these firm contracts. Though they are typically a small percentage of the total revenue we receive under our firm contracts, usage fees enable us to recover our variable costs incurred for the transportation of natural

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		gas on our pipeline system. For the twelve months ended September 30, 2007 approximately 80.1% of our transportation revenues were derived from capacity reservations fees paid under firm contracts, and approximately 8.7% of our transportation revenues were derived from usage fees under firm contracts including revenues under negotiated rate contracts.


	•	Interruptible contracts. Under interruptible contracts we market the physical capacity that is contracted for firm service contracts but that is not fully utilized by those firm customers. We derive a smaller portion of our revenues through these interruptible contracts under which customers pay fees based on their actual utilization of our assets for transportation and other related services. Customers who have executed interruptible contracts are not assured capacity in our pipeline facilities. For the twelve months ended September 30, 2007 approximately 11.2% of our transportation revenues were derived from interruptible contracts.

	•	Negotiated rate contracts. Negotiated rate contracts are firm contracts under which our customers may agree to pay rates that are above or below the “recourse rate” set by our FERC tariffs, provided the customers agree to such rates and the FERC has approved the negotiated rate. As of September 30, 2007 we had four negotiated rate contracts on file with the FERC, and for the nine months ended September 30, 2007 approximately 4.7% of our transportation revenues were derived from negotiated rate contracts.

The high percentage of our earnings derived from capacity reservation fees mitigates the risk to us of earnings fluctuations caused by changing supply and demand conditions. In addition, we do not own the gas we transport and we retain a portion of the gas transported in our system to use as fuel for our compressors. As such, we have no direct commodity price exposure. For additional information about our contracts, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — How We Evaluate Our Operations” and “— FERC Regulation.”

Tariff Rates. Our operations are subject to regulation by the FERC under the NGA. The FERC has jurisdiction over, among other things, the construction and operation of facilities used in the transportation, storage, and wholesale of natural gas in interstate commerce, including the extension, enlargement, or abandonment of such facilities. The FERC also has jurisdiction over the rates, terms, and conditions for the transportation of natural gas in interstate commerce. All of our transportation rates and terms of service are regulated by the FERC.

Our maximum and minimum recourse rates for transportation services are governed by Columbia Gulf’s FERC-approved natural gas tariff. Terms and conditions for service under this tariff are based on firm capacity reservation charges and both firm and interruptible usage fees for transportation across different zones. As of September 30, 2007, the rates in effect for 96.8% of our firm contracts on the Mainline System were at the maximum recourse rates prescribed for in our tariff. As of September 30, 2007 the rates in effect for approximately 90.6% of our firm contracts on the Louisiana Laterals were at the maximum recourse rates prescribed for in our tariff.

In 1998, Columbia Gulf entered into a rate settlement with its customers which established new base rates under Columbia Gulf’s FERC tariff. The 1998 rate settlement does not require us to file for new rates, thereby providing us rate certainty, subject to further negotiation, the filing of a rate case, or a customer filing a complaint. There are no FERC regulations that require us to file a rate case. Please read “— FERC Regulation.”

Expansion Projects. We continually evaluate organic and greenfield development opportunities to increase the volume of natural gas transportation capacity reserved and natural gas transported on our system. Our expansion strategy centers on our efforts to expand deliveries to growing markets in the Southeast, Midwest and Mid-Atlantic, while continuing to increase supply from new and diverse basins, particularly the Gulf Coast, North Texas (Barnett Shale) and Rocky Mountain supply regions. Since January 1, 2006, we have either commenced or completed construction of several expansion projects, including the following, for a total

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capital cost to us of approximately $13.4 million through September 30, 2007, with approximately $8.8 million in additional costs to be paid through December 31, 2007 and an estimated $55.8 million to be paid in 2008:


	•	Adair Expansion Project. In October 2006, we completed a new interconnection with Texas Eastern Transmission Company in Adair County, Kentucky. This interconnection enables us to deliver up to 200 MMcf/d to downstream markets in the Northeast and Mid-Atlantic. We have secured firm contracts for the full delivery volume. Market interest in this delivery remains strong, and we are currently exploring opportunities to further increase the size of this interconnection.

	•	Rayne Compressor Station Modifications. In July 2007, we completed piping modifications at our Rayne compressor station in southern Louisiana to enable the station to compress natural gas bi-directionally. The Rayne station retains its ability to compress up to 2.2 Bcf/d north to serve mainline markets in the Midwest and Mid-Atlantic, but now also possesses the ability to compress up to 1.0 Bcf/d south to link expanding supply at Delhi, Louisiana (Perryville area) with growing markets in the Southeast via our Louisiana Laterals. The project also provides us greater operational flexibility, increases our ability to deliver to the Henry Hub by 30 MMcf/d and positions us for further expansion of our Louisiana Lateral markets.

	•	Shadyside Expansion Project. In August 2007, we completed the expansion of our existing interconnection with Southern Natural Gas in St. Mary Parish, Louisiana. This expanded interconnection enables us to deliver an additional 85 MMcf/d to downstream markets in Mississippi, Alabama and Georgia. We have secured firm contracts for the full capacity with a weighted average contract life of 4.4 years as of its in-service date.

	•	Evangeline Expansion Project. In November 2007, we completed a new interconnection with Transcontinental Gas Pipeline in Evangeline Parish, Louisiana. This new interconnection will enable us to deliver up to 180 MMcf/d to downstream markets in the Northeast and Mid-Atlantic. We have secured firm contracts for the full capacity with a weighted average contract life of 1.8 years as of its in-service date.

	•	Terrebonne Expansion Project. In October 2007, we completed a new interconnection with Transcontinental Gas Pipeline in Terrebonne Parish, Louisiana. This new interconnection will enable us to deliver up to 200 MMcf/d to downstream markets in the Northeast and Mid-Atlantic. We have secured firm contracts for the full delivery volume with a weighted average contract life of 2.1 years as of its in-service date.

	•	FGT — Lafayette Expansion Project. We are pursuing an expansion of our existing interconnection with Florida Gas Transmission near Lafayette, Louisiana. This expansion would enable us to deliver an additional 180 MMcf/d to serve downstream markets in Florida. The projected capital cost for the expansion is $18.1 million, and it is scheduled to be in service in June 2008. We conducted an “open season” in October 2007 and received a high level of customer interest. We are in the process of negotiating definitive agreements for firm service.

In addition to the expansion opportunities we initiate, the strategic location of our pipeline makes it an attractive system for third parties to connect with at their expense, which benefits us and complements our connectivity strategy. For example, approximately 1.5 Bcf/d of major new gas supply pipeline interconnections to our Mainline System were completed by CenterPoint Energy Gas Transmission and Regency Energy Partners in 2006 and 2007 in the vicinity of our Delhi, Louisiana compressor station (Perryville area). These interconnections allow us access to supply from North Louisiana, East Texas and North Texas (Barnett Shale). Additional third-party initiated interconnections are expected to bring up to 6.5 Bcf/d of potential new supply in the same vicinity between 2008 and 2010. Similarly, construction of a new interconnection with Midwestern Gas Transmission near Nashville, Tennessee is scheduled to be completed in December 2007. This 120 MMcf/d bi-directional interconnection will provide us with access to the Chicago hub and Rocky Mountain gas supplies.

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We are also pursuing other expansions and extensions of our Mainline System and our Louisiana Laterals to further increase our market access in the New Orleans-Baton Rouge Industrial Corridor and the growing Southeastern and Florida residential, commercial, industrial and electric generation markets.

Competition. We compete primarily with other interstate pipelines for customers seeking upstream transportation service to markets in the Northeast, Mid-Atlantic, Midwest and Southeast. Our primary competitors are Tennessee Gas Pipeline Company, Transcontinental Gas Pipeline Company, Texas Eastern Transmission Company, Texas Gas Pipeline, Natural Gas Pipeline of America, Trunkline Gas Company and ANR Pipeline Company. An increase in competition in our key markets could arise from new ventures or expanded operations from existing competitors. The Southeast Supply Header, Midcontinent Express Pipeline and Boardwalk Partners projects all are designed to provide market outlets for the increasing natural gas supplies being delivered to Delhi, Louisiana (Perryville area) and represent a competitive threat to some of our expansion projects. The Rockies Express Pipeline project could compete with us as an alternate source of upstream natural gas supply to be delivered to the TCO Pool in Leach, Kentucky. Other competitive factors include the quantity, location and physical flow characteristics of interconnected pipelines, which could enable our competitors to better meet customer delivery requirements, to offer greater service flexibility or to decrease their cost of service and transportation rates.

We are well-positioned to compete, as we provide low cost service, including fuel, to the markets we serve. We are also managing competitive threats by increasing the flexibility and optionality available to customers on our system. By increasing the number and diversity of supply sources and markets that we interconnect with, the Columbia Gulf pipeline system becomes a more dynamic system that presents greater value to our customers. This not only increases the potential universe of customers that have interest in our transportation services, it also lessens the possibility that market shifts will affect the value of our pipeline system. We anticipate the increase in supply at Delhi will exceed the amount of downstream transportation being constructed by Boardwalk Partners, Midcontinent Express Pipeline and Southeast Supply Header, thus creating demand for additional market expansions. We believe our existing infrastructure and low cost transportation will enable us to compete effectively with these projects and will give us an advantage in pursuing any further expansion.

Natural Gas Supply. We provide direct access to the Gulf of Mexico and onshore Louisiana supply sources and, through major pipeline interconnects, access to numerous natural gas producing regions, including the South Texas and Louisiana Gulf Coast, North Louisiana, East Texas, North Texas (Barnett Shale) and Appalachian regions. In addition to the development of non-traditional sources of gas supply like the Fayette Shale in Arkansas, we anticipate that LNG imported on the Gulf Coast will become another significant source of supply accessible to our markets. A new bi-directional interconnect with Midwestern Gas Transmission near Nashville, Tennessee currently under construction is expected to provide us with new access to the Chicago hub and Rocky Mountain gas supplies.

Other Assets

In addition to Columbia Gulf’s Mainline System and the Louisiana Laterals, we also own interests in various non-contiguous pipeline assets located in the Gulf of Mexico, Texas and Wyoming. These assets generate revenues of less than $2.0 million a year.

Safety and Maintenance

We are subject to regulation by the DOT under the Natural Gas Pipeline Safety Act of 1968 (NGPSA), and the Pipeline Safety Improvement Act of 2002, which was recently reauthorized and amended by the Pipeline Inspection, Protection, Enforcement, and Safety Act of 2006. The NGPSA regulates safety requirements in the design, construction, operation and maintenance of gas pipeline facilities while the Pipeline Safety Improvement Act of 2002 establishes mandatory inspections for all United States oil and natural gas transportation pipelines, and some gathering lines in “high consequence areas,” such as high population centers, areas that are difficult to evacuate and locations where people congregate.

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DOT regulations implementing the Pipeline Safety Improvement Act of 2002 require pipeline operators to conduct integrity management programs, which involve frequent inspections and other measures to ensure pipeline safety in high consequence areas. The DOT may assess fines and penalties for violations of these and other requirements imposed by its regulations. We believe that we are in material compliance with all regulations imposed by the DOT on our natural gas pipeline operations.

We completed in-line inspections on approximately 67% of our high consequence areas by December 2007. We expect to complete in-line inspections on 100% of our high consequence areas by 2012. We currently estimate we will incur aggregate operation and maintenance costs of approximately $1.3 million annually between 2008 and 2012 to conduct the initial assessment of the remaining 33% of our high consequence areas. As part of our pipeline integrity program, we intend to make improvements to our East Lateral over the next several years to reduce the costs of in-line inspections. The total capital cost of these infrastructure improvements is expected to be approximately $4.0 million in 2008. We will retain a portion of the proceeds of this offering to offset the expected costs of these improvements. The expensed costs to be incurred will relate to internal inspection of the high consequence areas across the Columbia Gulf pipeline system. These estimates do not include the capital costs, if any, for major repair, remediation, preventative or mitigating actions that may be determined to be necessary as a result of the testing program.

On December 14, 2007, one of the three trunklines (Line 100) comprising our Mainline System suffered a rupture near Delhi, Louisiana that resulted in one death, one other person injured and damage to nearby property. As a result of the rupture, an 8.8 mile section of Line 100 has been taken out of service indefinitely. As a precautionary measure, the other two trunklines (Lines 200 and 300) were also temporarily taken out of service for integrity assessment. Following this assessment, Lines 300 and 200 were placed back in service on December 14 and December 15, 2007, respectively.

The cause of the rupture has not been determined at this time. The portion of Line 100 that suffered the rupture was not located in a high consequence area and had not previously been inspected as part of the initial assessment under our integrity management program. We are cooperating with the Pipeline and Hazardous Materials Safety Administration (PHMSA) in connection with an investigation of the incident. On December 19, 2007, we received a corrective action order from PHMSA under which (i) we may not resume operation of the 8.8 mile section of Line 100 where the rupture occurred until we prepare, and PHMSA approves, a written restart plan, (ii) the operating pressure on Line 100 from Rayne, Louisiana to Corinth, Mississippi may not exceed 80% of the actual operating pressure in effect immediately prior to the incident without the approval of PHMSA, (iii) we are required to complete certain testing analysis of the failed pipe within 30 days, and (iv) we are required to develop and submit to PHMSA for approval a remedial work plan within 60 days.

While we currently cannot quantify the total financial impact this rupture may have on our business, results of operations and financial condition, which impact could be material, we expect to incur approximately $1.0 million of capital expenditures in the fourth quarter of 2007 for the replacement of pipe on Line 100 and approximately $1.0 million in integrity assessment expenses related to the inspection of Line 100 in the first quarter of 2008. These estimates do not include the capital costs, if any, for major replacement, repair, remediation, preventative or mitigating actions that may be determined to be necessary as a result of the testing of Line 100 or any other lines. In addition, any remedial actions PHMSA may require us to take under the remedial work plan contemplated by the December 19th corrective action order, or in response to other corrective action orders, notices of probable violation or other findings issued by PHMSA, or any fines assessed by PHMSA with respect to this incident, could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to you. This incident could also result in actions by other governmental agencies, including fines or orders impacting our operations. Other adverse impacts of this event could include lawsuits from private individuals for damages to person or property (to the extent not covered by insurance), increased insurance costs, increased costs associated with any resulting acceleration of the integrity testing of other sections of our pipeline system, and expenses associated with our internal investigation of the incident and our response to governmental investigations or proceedings.

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States are largely preempted by federal law from regulating pipeline safety but may assume responsibility for enforcement of federal intrastate pipeline safety regulations and inspection of intrastate pipelines. In practice, states vary considerably in their authority and capacity to address pipeline safety. We do not anticipate any significant problems in complying with state laws and regulations applicable to our operations. Our natural gas pipelines have inspection and compliance programs designed to maintain compliance with federal and state pipeline safety and pollution control requirements. For instance, we maintain a corrosion control program to protect the integrity of the pipeline and prolong its life. The corrosion control program includes the installation and operation of groundbeds and rectifiers along the pipeline system to maintain adequate cathodic protection, as required by the DOT. We determine the adequacy of this program through bi-monthly monitoring of the output of these systems, annual checks of cathodic protection readings at various points along the pipeline and at compressor stations as well as by performing close interval potential surveys. We also monitor the pipeline both internally by sampling any liquids or solids that we remove from the pipeline and by performing an internal inspection whenever the interior of the pipeline is exposed. We inspect the external coating condition of the pipeline every time we excavate and expose the pipeline. The application of these monitoring and inspection techniques assist us in controlling and reducing metal loss and limiting corrosion, which we believe will extend the service life of the pipeline.

Due to population growth adjacent to our system, approximately nine miles of pipeline near the Nashville metropolitan area have been designated as operations in a high consequence area and, as a result of such designation, we are required by the Pipeline Safety Improvement Act to upgrade those portions to meet its safety standards. To fully meet these statutory requirements, we estimate we would be required to spend approximately $22.5 million to upgrade these nine miles of pipeline located near Nashville, Tennessee. The DOT is authorized to grant permits and waivers which relieve operators from required safety upgrades if and to the extent the operator demonstrates that its pipeline meets certain quality parameters. We believe our pipeline is of a quality that would support a waiver by the DOT. We filed for such a permit and waiver in December 2007 and, if granted, our expenditures associated with upgrades on these nine miles of pipeline would be reduced from approximately $22.5 million to approximately $5.5 million. Whether or not the permit and waiver is granted by the DOT, we do not expect to incur any expenditures to upgrade this portion of our pipeline before 2010. We will retain $5.5 million from the proceeds of this offering to offset these expected costs. If our ultimate costs exceed the $5.5 million retained, NiSource has agreed to indemnify us for the next $17.0 million of such costs.

We are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act (OSHA), and comparable state statutes, whose purpose is to protect the health and safety of workers, both generally and within the pipeline industry. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act, and comparable state statutes require that information be maintained concerning hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities, and citizens. We are also subject to OSHA Process Safety Management regulations, which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. These regulations apply to any process which involves a chemical at or above specified thresholds, or any process which involves 10,000 pounds or more of a flammable liquid or gas in one location. Flammable liquids stored in atmospheric tanks below their normal boiling point without the benefit of chilling or refrigeration are exempt. We have an internal program of inspection designed to monitor and enforce compliance with worker safety requirements. We believe that we are in material compliance with all applicable laws and regulations relating to worker health and safety.

FERC Regulation

General. Our interstate natural gas transportation system operations are regulated by the FERC under the NGA, the Natural Gas Policy Act of 1978 (NGPA) and the Energy Policy Act of 2005. Our system operates under a tariff approved by the FERC that establishes rates, cost recovery mechanisms, terms and conditions of service for our customers. Generally, the FERC’s authority extends to:


	•	transportation of natural gas;

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	•	rates and charges for natural gas transportation;

	•	certification and construction of new facilities;

	•	initiation, extension or abandonment of services;

	•	maintenance of accounts and records;

	•	commercial relationships and communications between pipelines and certain affiliates;

	•	terms and conditions of service and service contracts with customers;

	•	depreciation and amortization policies; and

	•	acquisition, extension and abandonment of facilities.

Columbia Gulf’s interstate pipeline holds a certificate of public convenience and necessity issued by the FERC pursuant to Section 7 of the NGA permitting the construction, ownership, and operation of its interstate natural gas pipeline facilities and the provision of related activities and services. This certificate authorization requires our interstate pipeline facilities to provide on a non-discriminatory basis open-access services to all customers who qualify under its FERC gas tariff. Under Section 8 of the NGA, the FERC has the power to prescribe the accounting treatment of items for regulatory purposes. Thus, the books and records of our interstate pipeline may be periodically audited by the FERC.

The FERC regulates the rates and charges for transportation in interstate commerce. Natural gas companies may only charge rates that they have been authorized to charge by the FERC.

The maximum and minimum recourse rates that may be charged by our pipeline for its services are established through the FERC’s ratemaking process. Generally, the maximum filed recourse rates for interstate pipelines are based on the cost of service including recovery of and a return on the pipeline’s actual prudent historical cost investment. Key determinants in the ratemaking process are costs of providing service, allowed rate of return and volume throughput and contractual capacity commitment assumptions. The maximum applicable recourse rates and terms and conditions for service are set forth in each pipeline’s FERC-approved tariff. Rate design and the allocation of costs also can impact a pipeline’s profitability. Our interstate pipeline is permitted to discount its firm and interruptible rates without further FERC authorization down to the minimum rate set forth in its FERC-approved tariff, provided they do not “unduly discriminate.”

Our interstate pipeline may also use “negotiated rates” which may involve rates above or below the “recourse rate,” provided that the affected customers are willing to agree to such rates and that the FERC has approved the negotiated rate agreement. A prerequisite for having the right to agree to negotiated rates is that negotiated rate customers must have had the option to take service under the pipeline’s maximum recourse rates. As of December 31, 2006, Columbia Gulf had four negotiated rate contracts on file with the FERC.

Columbia Gulf’s currently effective recourse rates were established in a rate case settlement in Docket No. RP97-52 approved by the FERC on April 29, 1998. Columbia Gulf has the option but not the obligation to propose changes to the FERC approved recourse rates established in this settlement at any time.

Columbia Gulf and Columbia Gas Transmission are cooperating with the FERC on an informal non-public investigation in connection with an audit initiated in 2003 that covers a period beginning in 1999 that evaluates whether Columbia Gulf and Columbia Gas Transmission properly followed the FERC’s regulations. We cannot predict what the result of that audit will be, but the FERC has indicated that it may seek to impose penalties under the Natural Gas Policy Act. Should a penalty be imposed, we do not expect to incur any material liability.

Affiliate Relationships. Commencing in 2003, the FERC issued a series of orders adopting rules for new Standards of Conduct for Transmission Providers (Order No. 2004) which applied to interstate natural gas pipelines. Order No. 2004 became effective in 2004. Among other matters, Order No. 2004 required our interstate pipelines to operate independently from its energy affiliates, prohibited our interstate pipeline from providing non-public transportation or customer information to its energy affiliates, prohibited our interstate pipeline from favoring its energy affiliates in providing service and obligated our interstate pipeline to post on

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its website a number of items of information concerning the company, including its organizational structure, facilities shared with energy affiliates, discounts given for service and instances in which the company has agreed to waive discretionary terms of its tariff.

Late in 2006, the United States Court of Appeals for the District of Columbia Circuit vacated and remanded Order No. 2004, as it relates to natural gas transportation providers, including our natural gas pipeline. The court objected to the FERC’s expansion of the prior standards of conduct to include energy affiliates, and vacated the entire rule as it relates to natural gas transportation providers. On January 9, 2007, and as clarified on March 21, 2007, the FERC issued an interim rule re-promulgating on an interim basis the standards of conduct that were not challenged before the court while the FERC decides how to respond to the court’s decision on a permanent basis. The interim rule makes the standards of conduct apply to the relationship between natural gas transportation providers and their marketing affiliates, but not to energy affiliates who are not also marketing affiliates. Several companies requested rehearing and clarification of the interim rule. The March 21, 2007 order on clarification granted some of the requested clarifications and stated that it would address the other requests in its proceeding establishing a permanent rule. The FERC has issued a notice of proposed rulemaking, or NOPR, that proposes permanent standards of conduct that the FERC states will avoid the aspects of the previous standards of conduct rejected by the court. With respect to natural gas transportation providers, the NOPR proposes (1) that the permanent standards of conduct apply only to the relationship between natural gas transportation providers and their marketing affiliates, and (2) to make permanent the changes adopted in the interim rule permitting risk management employees to be shared by natural gas transportation providers and their marketing affiliates and requiring that tariff waivers be maintained in a written waiver log and available upon request. We have no way to predict with certainty the scope of the FERC’s permanent rules on the standards of conduct. However, we do not believe that our natural gas pipeline will be affected by any action taken previously or in the future on these matters materially differently than other natural gas service providers with whom we compete.

FERC Policy Statement on Income Tax Allowances. In a decision issued in July 2004 involving an oil pipeline limited partnership, BP West Coast Products, LLC v. FERC, the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit) vacated the portion of a FERC decision applying the Lakehead policy. In its Lakehead decision, the FERC allowed an oil pipeline publicly traded partnership to include in its cost-of-service an income tax allowance to the extent that its unitholders were corporations subject to income tax. In May and June 2005, the FERC issued a policy statement, as well as an order on remand of BP West Coast, respectively, in which it stated it will permit pipelines to include in cost-of-service a tax allowance to reflect actual or potential tax liability on their public utility income attributable to all partnership or limited liability company interests, if the ultimate owner of the interest has an actual or potential income tax liability on such income. Whether a pipeline’s owners have such actual or potential income tax liability will be determined by the FERC on a case-by-case basis. The new policy entails rate risk due to the case-by-case review requirement. The FERC’s BP West Coast remand decision and the new tax allowance policy were appealed to the D.C. Circuit. The D.C. Circuit issued an order on May 29, 2007 in which it denied these appeals and upheld the FERC’s new tax allowance policy and the application of that policy in the December 16, 2005 order on all points subject to appeal. On August 20, 2007, the D.C. Circuit denied a request for rehearing of the May 29, 2007 decision. The period for appeals has now passed.

On December 8, 2006, the FERC issued a new order addressing rates on one of the interstate oil pipelines of SFPP, L.P. (SFPP). In that order, the FERC addressed challenges to the policy statement raised by customers in filings in another docket earlier in 2006. In the new order, the FERC refined its income tax allowance policy, and notably raised a new issue regarding the implication of the policy statement for publicly traded partnerships. It noted that the tax deferral features of a publicly traded partnership may cause some investors to receive, for some indeterminate duration, cash distributions in excess of their taxable income, which the FERC characterized as a “tax savings.” The FERC stated that it is concerned that this created an opportunity for those investors to earn an additional return, funded by ratepayers. Responding to this concern, the FERC chose to adjust the pipeline’s equity rate of return downward based on the percentage by which the publicly traded partnership’s cash flow exceeded taxable income. On February 7, 2007, SFPP asked the FERC to reconsider this ruling. The ultimate outcome of this proceeding is not certain and could result in changes to

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the FERC’s treatment of income tax allowances in cost of service and to potential adjustment in a future rate case of our pipeline’s equity rates of return that underlie its recourse rates to the extent that cash distributions in excess of taxable income are allowed to some unitholders. If the FERC were to disallow a substantial portion of our pipeline’s income tax allowance, it may cause our pipeline’s recourse rates to be set at a level that is different, and in some instances lower, than the level otherwise in effect.

FERC Policy Statement on Proxy Groups for Rates of Return Determinations. On July 19, 2007, the FERC issued a proposed policy statement regarding the composition of proxy groups for determining the appropriate returns on equity for natural gas and oil pipelines. The proposed policy statement would permit the inclusion of master limited partnerships (MLPs) in the proxy group for purposes of calculating allowed returns on equity under the Discounted Cash Flow (DCF) analysis, a change from its prior view that MLPs had not been shown to be appropriate for such inclusion. Specifically, the FERC proposes that MLPs may be included in the proxy group provided that the DCF analysis recognizes as distributions only the pipeline’s reported earnings, and not other sources of cash flow subject to distribution. According to the proposed policy statement, under the DCF analysis, the return on equity is calculated by adding the dividend or distribution yield (dividends divided by share/unit price) to the projected future growth rate of dividends or distributions (weighted one third for long-term growth of the economy as a whole and two-thirds short term growth as determined by analysts’ five-year forecasts for the pipeline). This change would only impact maximum allowed recourse tariff rates in the course of a rate case proceeding to adjust those rates. The determination of which MLPs should be included will be made on a case by case basis, after a review of whether an MLP’s earnings have been stable over a multi-year period. The FERC proposes to apply the final policy statement to all natural gas rate cases that have not completed the hearing phase as of the date the FERC issues the final policy statement. The FERC received comments on the proposed policy in September 2007. The FERC’s proposed policy statement is subject to change based on comments filed and therefore we cannot predict the scope of the final policy statement.

Energy Policy Act of 2005. On August 8, 2005, Congress enacted the Energy Policy Act of 2005 (EPAct 2005). Among other matters, EPAct 2005 amends the NGA, to add an anti-market manipulation provision which makes it unlawful for any entity to engage in prohibited behavior in contravention of rules and regulations to be prescribed by the FERC and provides the FERC with additional civil penalty authority. On January 19, 2006, the FERC issued Order No. 670, a rule implementing the anti-market manipulation provision of EPAct 2005, and subsequently denied rehearing. The rules make it unlawful to: (1) in connection with the purchase or sale of natural gas subject to the jurisdiction of the FERC, or the purchase or sale of transportation services subject to the jurisdiction of the FERC, for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud; (2) to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (3) to engage in any act or practice that operates as a fraud or deceit upon any person. The new anti-market manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but does apply to activities of gas pipelines and storage companies that provide interstate services, as well as otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction. EPAct 2005 also amends the NGA and the NGPA to give the FERC authority to impose civil penalties for violations of these statutes up to $1,000,000 per day per violation for violations occurring after August 8, 2005. In connection with this enhanced civil penalty authority, the FERC issued a policy statement on enforcement to provide guidance regarding the enforcement of the statutes, orders, rules and regulations it administers, including factors to be considered in determining the appropriate enforcement action to be taken. The anti-market manipulation rule and enhanced civil penalty authority reflect an expansion of the FERC’s NGA enforcement authority. Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, the FERC and the courts. The natural gas industry historically has been heavily regulated. Accordingly, we cannot assure you that present policies pursued by the FERC and Congress will continue.

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Seasonality

Our revenues are not generally seasonal in nature, nor are they typically affected by weather and price volatility. During 2006, approximately 27% of our transportation revenues were in the first calendar quarter, 23% in the second quarter, 24% in the third quarter and 26% in the fourth quarter.

Environmental Regulation

General. Our natural gas transportation activities are subject to stringent and complex federal, state, and local laws and regulations governing environmental protection, including air emissions, water quality, wastewater discharges, and solid waste management. Such laws and regulations generally require us to obtain and comply with a wide variety of environmental registrations, licenses, permits, and other approvals. These laws and regulations also can restrict or impact our business activities in many ways, such as restricting the way we handle or dispose of our wastes; requiring remedial action to mitigate pollution conditions that may be caused by our operations or that are attributable to former operators; and preventing continued operation of facilities deemed in non-compliance with permits issued pursuant to such environmental laws and regulations. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and/or criminal penalties, the imposition of remedial requirements, and the issuance of orders enjoining future operations.

We accrue for expenses associated with environmental liabilities when the costs are probable and reasonably estimable. The amount of any accrual for environmental liabilities could change substantially in the future due to factors including the nature and extent of any contamination that we may be required to remediate, changes in remedial requirements, technological changes, discovery of new information, and the involvement and direction taken by the EPA, FERC, DOT and any other governmental authorities on these matters.

We believe that compliance with existing federal, state and local environmental laws and regulations are not likely to have a material adverse effect on our business, financial position, or results of operations. Nevertheless, the trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. As a result, there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate. The following is a discussion of some of the environmental laws and regulations that are applicable to our natural gas transportation activities.

Waste Management. Our operations generate hazardous and non-hazardous solid wastes that are subject to the federal Resource Conservation and Recovery Act (“RCRA”) and comparable state laws, which impose detailed requirements for the handling, storage, treatment and disposal of hazardous and non-hazardous solid wastes. For instance, RCRA prohibits the disposal of certain hazardous wastes on land without prior treatment, and requires generators of wastes subject to land disposal restrictions to provide notification of pre-treatment requirements to disposal facilities that are in receipt of these wastes. Generators of hazardous wastes also must comply with certain standards for the accumulation and storage of hazardous wastes, as well as recordkeeping and reporting requirements applicable to hazardous waste storage and disposal activities. RCRA imposes fewer restrictions on the handling, storage and disposal of non-hazardous wastes, which includes certain wastes associated with the exploration and production of oil and natural gas.

Site Remediation. The Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), also known as “Superfund,” and comparable state laws and regulations impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons responsible for the release of hazardous substances into the environment. Such classes of persons include the current and past owners or operators of sites where a hazardous substance was released, and companies that disposed or arranged for the disposal of hazardous substances at offsite locations, such as landfills. CERCLA authorizes the U.S. Environmental Protection Agency (EPA), and in some cases third parties, to take actions in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. If in the future we are considered a responsible party under CERCLA, we could be subject to joint and several, strict liability for the costs of cleaning up and restoring sites where hazardous

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substances have been released into the environment, for damages to natural resources, and for the costs of certain health studies. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of substances or wastes into the environment.

We currently own or lease properties that for many years have been used for the transportation and compression of natural gas. Although we typically have used operating and disposal practices that were standard in the industry at the time, wastes may have been disposed of or released on or under the properties owned or leased by us or on or under other locations where such substances have been taken for disposal. In addition, some of the properties may have been operated by third parties or by previous owners whose treatment and disposal or release of wastes was not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove previously disposed wastes, including waste disposed of by prior owners or operators; remediate contaminated property, including groundwater contamination, whether from prior owners or operators or other historic activities or spills; or perform remedial closure operations to prevent future contamination.

Air Emissions. The Clean Air Act (CAA) and comparable state laws regulate emissions of air pollutants from various industrial sources, including compressor stations, and also impose various monitoring and reporting requirements. Such laws and regulations may require pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in an increase of existing air emissions; application for, and strict compliance with, air permits containing various emissions and operational limitations; or the utilization of specific emission control technologies to limit emissions. Failure to comply with these requirements could result in monetary penalties, injunctions, conditions or restrictions on operations, and potentially criminal enforcement actions.

We may incur significant expenditures in the future for air pollution control equipment in connection with revised regulatory requirements and in obtaining or maintaining operating permits and approvals for air emissions. For instance, we may be required to supplement or modify our air emission control equipment and strategies due to changes in EPA’s national ambient air quality standards for ozone and fine particulates, changes in state implementation plans for controlling air emissions in areas that have not achieved EPA’s air quality standards, or stricter regulatory requirements for sources of hazardous air pollutants. However, we do not believe that any such future requirements will have a material adverse affect on our operations.

Water Discharges. The Clean Water Act (CWA) and analogous state laws impose strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by EPA or an analogous state agency. The CWA also regulates storm water runoff from certain industrial facilities. Accordingly, some states require industrial facilities to obtain and maintain storm water discharge permits, and monitor and sample storm water runoff from their facilities. Under the CWA, federal and state regulatory agencies may impose administrative, civil and/or criminal penalties for non-compliance with discharge permits or other requirements of the CWA and analogous state laws and regulations.

The Oil Pollution Act of 1990 (OPA), which amends and augments the CWA, establishes strict liability for owners and operators of facilities that are the source of a release of oil into waters of the United States. OPA and its associated regulations impose a variety of requirements on responsible parties related to the prevention of oil spills and liability for damages resulting from such spills. For example, operators of certain oil and gas facilities must develop, implement and maintain facility response plans, conduct annual spill training for certain employees and provide varying degrees of financial assurance to cover costs that could be incurred in responding to an oil spill.

Environmental Impact Assessments. Significant federal decisions, such as issuance of a permit authorizing construction of a new interstate gas transmission pipeline or authorizing natural gas transportation activities to be conducted on federal lands, are subject to the National Environmental Policy Act (NEPA). NEPA requires federal agencies, including the FERC and the Department of Interior, to evaluate major agency

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actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. Our current activities, as well as any proposed plans for future activities, on federal lands are subject to the requirements of NEPA.

Other Laws and Regulations. Recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases” and including carbon dioxide and methane, may be contributing to warming of the Earth’s atmosphere. In response to such studies, the U.S. Congress is actively considering legislation to reduce emissions of greenhouse gases. In addition, several states have declined to wait on Congress to develop and implement climate control legislation and have already taken legal measures to reduce emissions of greenhouse gases. Also, as a result of the U.S. Supreme Court’s decision on April 2, 2007 in Massachusetts, et al. v. EPA, the EPA may be required to regulate greenhouse gas emissions from mobile sources (e.g. cars and trucks) even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. Other nations have already agreed to regulate emissions of greenhouse gases pursuant to the United Nations Framework Convention on Climate Change, also known as the “Kyoto Protocol,” an international treaty pursuant to which participating countries (not including the United States) have agreed to reduce their emissions of greenhouse gases to below 1990 levels by 2012. Passage of climate control legislation or other regulatory initiatives by Congress or various states of the U.S. or the adoption of regulations by the EPA and analogous state agencies that restrict emissions of greenhouse gases in areas in which we conduct business could have an adverse effect on our operations and demand for natural gas.

The Department of Homeland Security Appropriations Act of 2007 requires the Department of Homeland Security, DHS, to issue regulations establishing risk-based performance standards for the security of chemical and industrial facilities, including oil and gas facilities that are deemed to present “high levels of security risk.” The DHS is currently in the process of adopting regulations that will determine whether some of our facilities or operations will be subject to additional DHS-mandated security requirements. Presently, it is not possible to estimate the costs to comply with any such facility security laws or regulations, but such expenditures could be substantial.

Title to Properties and Rights-of-Way

Our real property falls into two categories: (1) parcels that we own in fee and (2) parcels in which our interest derives from leases, easements, rights-of-way, permits or licenses from landowners or governmental authorities permitting the use of such land for our operations. Portions of the land on which our major facilities are located are owned by us in fee title, and we believe that we have satisfactory title to these lands. The remainder of the land on which our major facilities are located are held by us (or entities in which we own an interest) pursuant to ground leases between us, as lessee, and the fee owner of the lands, as lessors. We, our predecessor or our or their affiliates, have leased these lands, in some cases, for many years without any material challenge known to us relating to the title to the land upon which the assets are located, and we believe that we have satisfactory leasehold estates to such lands. We have no knowledge of any challenge to the underlying fee title of any material lease, easement, right-of-way, permit or license held by us or to our title to any material lease, easement, right-of-way, permit or lease, and we believe that we have satisfactory title to all of our material leases, easements, rights-of-way, permits and licenses.

Insurance

Our insurance program includes general liability insurance, auto liability insurance, worker’s compensation insurance, and property insurance in amounts which management believes are reasonable and appropriate.

Facilities

We lease our offices in Houston, Texas under a lease which expires on June 30, 2011. Other office space is shared with NiSource affiliates and we are charged an allocation for the use of space by our employees.

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Employees

We are managed and operated by the directors and officers of our general partner. To carry out our operations, as of September 30, 2007, our general partner or its affiliates employed approximately 260 people who will spend at least a majority of their time operating the Columbia Gulf pipeline system.

Legal Proceedings

Other than the legal proceedings described below, we are not a party to any legal proceeding other than legal proceedings arising in the ordinary course of our business. We are a party to various administrative and regulatory proceedings that have arisen in the ordinary course of our business. Please read “— FERC Regulation.”

Stand Energy Corporation, et al. v. Columbia Gas Transmission Corporation, et al., Kanawha County Court, West Virginia. On July 14, 2004, Stand Energy Corporation filed a complaint in Kanawha County Court in West Virginia. The complaint contains allegations against various NiSource companies, including Columbia Gas Transmission and Columbia Gulf, and asserts that those companies and certain “select shippers” engaged in an “illegal gas scheme” that constituted a breach of contract and violated state law. The “illegal gas scheme” complained of by the plaintiffs relates to the Columbia Gas Transmission and Columbia Gulf gas imbalance transactions that were the subject of the FERC enforcement staff investigation and subsequent settlement approved in October 2000. Columbia Gas Transmission and Columbia Gulf filed a Motion to Dismiss on September 10, 2004. In October 2004, however, the plaintiffs filed their Second Amended Complaint, which clarified the identity of some of the “select shipper” defendants and added a federal antitrust cause of action. To address the issues raised in the Second Amended Complaint, the Columbia companies revised their briefs in support of the previously filed motions to dismiss. In June 2005, the Court granted in part and denied in part the Columbia companies’ motion to dismiss the Second Amended Complaint. The Columbia companies have filed an answer to the Second Amended Complaint. On December 1, 2005, Plaintiffs filed a motion to certify this case as a class action. The Court has ordered that discovery will proceed on the issue of class certification as well as the merits.

United States of America ex rel. Jack J. Grynberg v. Columbia Gas Transmission Corporation, et al., U.S. District Court, E.D. Louisiana. The plaintiff filed a complaint in 1997, under the False Claims Act, on behalf of the United States of America, against approximately seventy pipelines, including Columbia Gulf and Columbia Gas Transmission. The plaintiff claimed that the defendants had submitted false royalty reports to the government (or caused others to do so) by mis-measuring the volume and heating content of natural gas produced on Federal land and Indian lands. The plaintiff’s original complaint was dismissed without prejudice for misjoinder of parties and for failing to plead fraud with specificity. The plaintiff then filed over sixty-five new False Claims Act complaints against over 330 defendants in numerous Federal courts. One of those complaints was filed in the Federal District Court for the Eastern District of Louisiana against Columbia Gulf and thirteen affiliated entities.

Plaintiff’s second complaint, filed in 1997, repeats the mis-measurement claims previously made and adds valuation claims alleging that the defendants have undervalued natural gas for royalty purposes in various ways, including sales to affiliated entities at artificially low prices. Most of the Grynberg cases were transferred to Federal court in Wyoming in 1999.

On October 20, 2006, the Federal District Court issued an Order granting the Columbia defendants’ motion to dismiss for lack of subject matter jurisdiction. The Plaintiff has appealed the dismissal of the defendants.

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MANAGEMENT

Management of NiSource Energy Partners, L.P.

Under our partnership agreement, our general partner, NiSource GP, LLC will manage our operations and activities. Our general partner is not elected by our unitholders and will not be subject to re-election on a regular basis in the future. Unitholders will not be entitled to elect our general partner’s directors or directly or indirectly participate in our management or operation. Our general partner owes a fiduciary duty to our unitholders. Our general partner will be liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made expressly nonrecourse to it. Our general partner therefore may cause us to incur indebtedness or other obligations that are nonrecourse to it.

The board of directors of our general partner (the “GP Board”) will oversee our operations. Upon the closing of this offering, the GP Board will have at least five directors and intends to increase the size of the board of directors to seven following the closing of this offering. NiSource will elect all members of the GP Board and we expect that, when the size of the board increases to seven directors, there will be at least three directors that are independent as defined under the independence standards established by the New York Stock Exchange. The New York Stock Exchange does not require the GP Board to have a majority of independent directors nor does it require the GP Board to have a nominating or governance committee.

In compliance with the requirements of the New York Stock Exchange, NiSource has appointed as an independent member to the GP Board. NiSource intends to appoint a second independent director within 90 days of listing and a third independent member within 12 months of listing. The independent members of the GP Board will serve as the initial members of the conflicts and audit committees of the GP Board.

At least two members of the GP Board will serve on a conflicts committee to review specific matters that the GP Board believes may involve conflicts of interest. The conflicts committee will determine if the resolution of the conflict of interest is fair and reasonable to us. The members of the conflicts committee may not be officers, employees or security holders of our general partner nor directors, officers, or employees of its affiliates, and must meet the independence and experience standards established by the New York Stock Exchange and the Securities Exchange Act of 1934, as amended, to serve on an audit committee of a board of directors, and certain other requirements. Any matters approved by the conflicts committee in good faith will be conclusively deemed to be fair and reasonable to us, approved by all of our partners, and not a breach by our general partner of any duties it may owe us or our unitholders.

In addition, our general partner will have an audit committee of at least three directors who meet the independence and experience standards established by the New York Stock Exchange and the Securities Exchange Act of 1934, as amended. The audit committee will assist the GP Board in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and corporate policies and controls. The audit committee will have the sole authority to retain and terminate our independent registered public accounting firm, approve all auditing services and related fees and the terms thereof, and pre-approve any non-audit services to be rendered by our independent registered public accounting firm. The audit committee will also be responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm will be given unrestricted access to the audit committee.

All of the executive officers of our general partner listed below are employed by an affiliate of NiSource and will provide services to the general partner under the terms of the Services Agreement. The executive officers of our general partner will allocate their time between managing our business and affairs and the business and affairs of NiSource and its affiliates. The executive officers of our general partner may face a conflict regarding the allocation of their time between our business and the other business interests of NiSource. The GP Board will cause the executive officers of our general partner to devote as much time to the management of our business and affairs as is necessary for the proper conduct of our business and affairs. We will also utilize a significant number of other employees of NiSource or its affiliates to operate our business and provide us with general and administrative services. We will reimburse NiSource for allocated expenses of

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operational personnel who perform services for our benefit, allocated general and administrative expenses and certain direct expenses. Please read ‘‘— Reimbursement of Expenses of our General Partner.”

Directors and Executive Officers

The following table shows information regarding the current directors and executive officers of NiSource GP, LLC, our general partner. Directors are elected for one-year terms.


Name	Age		Position

Robert C. Skaggs, Jr.		53	Chairman of the Board
Christopher A. Helms		53	President, Chief Executive Officer and Director
Michael W. O’Donnell		63	Executive Vice President, Chief Financial Officer and Director
James F. Thomas		47	Executive Vice President, Chief Commercial Officer and Director
Carrie J. Hightman		50	Executive Vice President and Chief Legal Officer

Directors of our general partner hold office until the earlier of their death, resignation, removal or disqualification or until their successors have been elected and qualified. Officers serve at the discretion of the GP Board. There are no family relationships among any of the directors or executive officers.

Robert C. Skaggs, Jr. was elected Chairman of the Board of NiSource GP, LLC in December 2007. Mr. Skaggs is currently the President and Chief Executive Officer of NiSource and also a director of NiSource. Mr. Skaggs became President of NiSource in October 2004 and was named CEO in July 2005. Prior to October 2004, Mr. Skaggs served as the Executive Vice President, Regulated Revenue of NiSource from October 2003 to October 2004; the President of Columbia Gas of Ohio and Columbia Gas of Kentucky, both NiSource subsidiaries, from early 1997 to October 2003; President of Bay State and Northern Utilities, both NiSource subsidiaries, from November 2000 to October 2003; and President of Columbia Gas of Virginia, Columbia Gas of Maryland, and Columbia Gas of Pennsylvania, all NiSource subsidiaries from December 2001 to October 2003.

Christopher A. Helms was elected President, Chief Executive Officer and a Director of NiSource GP, LLC in December 2007. Mr. Helms is currently the Pipeline Group President of NiSource, a position that he assumed in April 2005. He currently serves as President and Director of the following NiSource subsidiaries; Columbia Gas Transmission Corporation; Granite State Gas Transmission, Inc.; Central Kentucky Transmission Company; and, Columbia Deep Water Services Company. Mr. Helms was Chairman of the Board of Managers of Millennium Pipeline Company LLC from January 2006 until January 2007 and was the NiSource’s member representative to the Board of Managers from April 2005 to January 2007. Prior to that time, Mr. Helms acted as a principal of Helms & Company LP from December 2003 to March 2005. Before that he was the President and Chief Executive Officer of the CMS Panhandle Companies from March 1999 to June 2003 and Executive Vice President of CMS Gas Transmission Corp. from March 1999 to June 2003. During this period, Mr. Helms was President and Chief Executive Officer of Panhandle Pipe Line Company LLC, Trunkline Gas Company, LLC, Trunkline LNG Company LLC; a Southwest Gas Storage Company; and President of Centennial Pipeline Company LLC, a liquid petroleum joint venture company with affiliates of Marathon Oil Company and Texas Eastern Products Pipeline Company LLC.

Michael W. O’Donnell was elected Executive Vice President, Chief Financial Officer and a Director of NiSource GP, LLC in December 2007. Mr. O’Donnell is currently Executive Vice President and Chief Financial Officer of NiSource. He has held that position since November 2000.

James F. Thomas was elected Executive Vice President, Chief Commercial Officer and a Director of NiSource GP, LLC in December 2007. Mr. Thomas is currently the Senior Vice President and Chief Commercial Officer for the following NiSource subsidiaries: Central Kentucky Transmission Company, Columbia Deep Water Services Company, Crossroads Pipeline Company, Granite State Gas Transmission, Inc., Columbia Gas Transmission Corporation and Columbia Hardy Corporation. He assumed these positions in March 2006. Mr. Thomas has also served as a Manager of Hardy Storage Company, LLC since June 2007.

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Prior to March 2006, Mr. Thomas served as a principal and the Vice President for Ceritas Energy, LLC from February 2003 to March 2006 and as a principal for his own energy consulting practice Franklin Management from June 2000 to February 2003.

Carrie J. Hightman was elected Executive Vice President, Chief Legal Officer of NiSource GP, LLC in December 2007. Ms. Hightman is currently an Executive Vice President and Chief Legal Officer for NiSource. She assumed this position in December 2007. From April 2001 to October 2006, Ms. Hightman served as President of AT&T Illinois (formerly SBC). At AT&T, Ms. Hightman was responsible for all regulatory, legislative, government and external affairs activities, as well as community and industry relations, throughout Illinois.

Reimbursement of Expenses of Our General Partner

Our general partner will not receive any management fee or other compensation for its management of our partnership under the omnibus agreement or otherwise. We will reimburse two entities affiliated with NiSource for the provision of various general and administrative services under agreements (the “Services Agreement”) with them, and we expect the aggregate costs to us will be approximately $ per year for these expenses. These agreements consist of services agreements with Columbia Gas Transmission and NiSource Corporate Services Company. We will also reimburse NiSource’s affiliates for direct expenses incurred on our behalf and expenses allocated to us as a result of our becoming a public entity. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us. Please read “Certain Relationships and Related Party Transactions — Services Agreements.”

Executive Compensation

Our general partner was formed in December 2007. Accordingly, our general partner has not accrued any obligations with respect to management incentive or retirement benefits for its directors and officers for the 2007 fiscal year. The compensation of the executive officers of our general partner will be set by the compensation committee of NiSource and ratified by the GP Board. Our general partner’s officers participate in employee benefit plans and arrangements sponsored by NiSource. Our general partner has not entered into any employment agreements with any of its officers. We anticipate that the GP Board will grant awards to our officers and other employees of NiSource’s affiliates who provide services to our general partner and our outside directors pursuant to the Long Term Incentive Plan described below following the closing of this offering; however, the GP Board has not yet made any determination as to the number of awards, the type of awards or when the awards would be granted.

Compensation Discussion and Analysis

We do not directly employ any of the persons responsible for managing our business and we do not have a compensation committee. We are managed by our general partner, the executive officers of which are employees of NiSource’s affiliates. Our reimbursement for the compensation of executive officers is governed by the Services Agreement and will generally be based on time allocated to us and other affiliates of NiSource during any period.

Although we were formed in December 2007, our executive officers were not specifically compensated for time expended in 2007 with respect to our business or assets. Accordingly, we are not presenting any compensation for historical periods. Compensation paid or awarded by us in 2008 with respect to our Chief Executive Officer and President (our principal executive officer), our Chief Legal Officer and our Chief Financial Officer (our principal financial officer, and together with these other two officers, our “named executive officers”) will reflect only the portion of compensation paid by NiSource’s affiliates that is allocated to us pursuant to NiSource’s allocation methodologies and subject to the terms of the Services Agreement. Our named executive officers will not devote 100% of their time to our business and affairs and we expect that for the period from the completion of this offering until December 31, 2008, less than half of the compensation paid by NiSource to our named executive officers will be allocated to us. The compensation committee of NiSource has ultimate decision making authority with respect to the compensation, other than equity based

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compensation under our long-term incentive plan, of our named executive officers. The elements of compensation discussed below, other than equity based compensation under our long term incentive plan, and NiSource’s decisions with respect to determinations on payments, will not be subject to approval by the GP Board. Compensation of our executive officers will be approved by the compensation committee of the NiSource Board or its delegate and ratified by the GP Board. Awards under our long term incentive plan will be recommended by the compensation committee of the NiSource Board and approved by the GP Board.

With respect to compensation objectives and decisions regarding our named executive officers for 2008, the compensation committee of NiSource will approve the compensation, and recommend equity based compensation, of our named executive officers based on its compensation philosophy. NiSource’s executive compensation program is designed to attract and retain highly qualified executives and provide compensation in a manner that is designed to relate total compensation to corporate performance, while remaining competitive with the compensation practices of competitors in the energy industry and, to a lesser extent, general industry. Accordingly, NiSource’s philosophy is to provide a competitive total compensation program based on the approximate 50th percentile of the range of compensation paid by similar energy companies, taking into account NiSource’s performance and individual performance.

NiSource’s compensation committee engaged Hewitt Associates (“Hewitt”), an independent compensation consulting firm, to advise it with respect to compensation design, comparative compensation practices, and other compensation matters. For its 2007 compensation considerations, NiSource’s compensation committee engaged Hewitt to provide it with survey information for (1) a group of energy companies, including gas, electric or combination utility companies and (2) a diversified group of companies representing general industry. The NiSource compensation committee primarily considered the survey information for the energy companies. However, the compensation committee also considered, to a lesser extent, general industry information for those executive positions where NiSource would compete among general industry firms for executive talent. For its 2007 considerations, NiSource’s compensation committee approved the following executive compensation comparative groups:

Energy Company Comparative Group


AGL Resources Inc		Nicor Inc.
Allegheny Energy, Inc.		Pepco Holdings, Inc.
Ameren Corporation		PG&E Corporation
American Electric Power Company, Inc.		PNM Resources, Inc.
Aquila, Inc.		PPL Corporation
CenterPoint Energy, Inc.		Public Service Enterprise Group
Cinergy Corp.		SCANA Corporation
CMS Energy Corporation		Sempra Energy
Dominion Resources, Inc.		Southern Company
DTE Energy Company		TXU Corp.
Duke Energy Corporation		WGL Holdings, Inc.
FirstEnergy Corp

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General Industry Comparative Group


3M Company		Illinois Tool Works Inc.
ALLTEL Company		ITT Industries, Inc.
American Standard Companies Inc.		Kellogg Company
Automatic Data Processing, Inc.		Kennemetal Inc.
Avon Products, Inc.		Kimberly-Clark Corporation
Baxter International Inc.		Masco Corporation
The Black & Decker Corporation		Newell Rubbermaid Inc.
Boise Cascade Corporation		Rockwell Automation, Inc.
Briggs & Stratton Corporation		The Scotts Company
Campbell Soup Company		The Sherwin-Williams Company
The Clorox Company		Tribune Company
FMC Corporation		W.W. Grainger, Inc.
General Mills, Inc.		Whirlpool Corporation
The Goodyear Tire & Rubber Company

NiSource intends to consult with Hewitt with respect to determining 2008 compensation for the named executive officers in a manner consistent with its current compensation philosophy. All compensation determinations are discretionary and are, as noted above, subject to NiSource’s decision-making authority.

NiSource’s executive compensation program consists of: base salary; an annual incentive plan; long-term incentive compensation; benefit programs (including pension, retirement savings, deferred compensation and health and welfare); a limited amount of perquisites; and post-termination benefits. With respect to balancing these elements, NiSource considers competitive conditions, internal comparisons, NiSource and individual performance, and historical Company practices.

NiSource’s compensation committee considers various factors when making decisions regarding the components of executive compensation, including:


	•	The competitiveness of NiSource’s programs, based upon competitive market data (described more fully below);

	•	The attainment of established NiSource business and financial goals; and

	•	An executive’s position, level of responsibility, and performance, as measured by his or her individual contribution to NiSource’s achievement of its business objectives.

For 2008, elements of compensation for our named executive officers are expected to be the following:


	•	base pay;

	•	NiSource annual incentive plan;

	•	performance awards under NiSource’s and possibly our long-term incentive plan;

	•	NiSource’s contributions under its 401(k) and profit sharing plan; and

	•	NiSource’s other benefit plans on the same basis as all other NiSource employees.

The portion of annual base salary, annual cash bonuses, awards under NiSource’s long-term incentive plan, NiSource’s contributions under its 401(k) and profit sharing plan and other benefit plans allocable to us will be based on NiSource’s methodologies used for allocating general and administrative expenses, subject to the limitations in the Omnibus Agreement.

NiSource’s Annual Incentive Plan. NiSource’s compensation committee will determine the annual incentive ranges for our general partner’s named executive officers in accordance with NiSource’s annual

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incentive plan, which is a broad-based plan that extends to most employees within NiSource and its affiliates. This component provides an incentive opportunity for employees based upon NiSource’s annual performance.

The incentive ranges for our named executive officers, stated as a percentage of base salary, under NiSource’s annual incentive plan for 2007 were 32.5% to 97.5% for each of Michael O’Donnell and Christopher Helms. Ms. Hightman joined NiSource in December 2007 and did not have an incentive range fixed under the NiSource 2007 annual incentive plan.

NiSource’s annual incentive plan establishes a trigger amount of financial performance below which no annual incentive is paid. At that trigger level, employees in good standing are eligible to receive an incentive in accordance with the plan and their individual incentive opportunity. Additionally, a profit sharing contribution of between 0.5% and 1.5% of an employee’s eligible earnings may be made to an employee’s account in NiSource’s Retirement Savings Plan on behalf of all eligible employees, including our named executive officers, based on the identical overall corporate financial performance measure.

NiSource’s Long-term Incentive Plan. NiSource’s long-term incentive plan is designed to achieve the following purposes:


	•	Aligning executives’ compensation with NiSource’s long-term strategic plan;

	•	Aligning the interests of the executives with the interests of NiSource’s long-term stockholders in increasing the value of NiSource’s stock; and

	•	Providing competitive compensation so that NiSource can recruit and retain executive talent.

Under NiSource’s Long-Term Incentive Plan, the NiSource compensation committee may award stock options, stock appreciation rights, performance units, restricted stock awards, and contingent stock awards. The NiSource compensation committee considers base salaries of the executive officers, prior awards under the Long-Term Incentive Plan, and NiSource’s total compensation target in establishing long-term incentive awards. The actual compensation value of awards under the Long-Term Incentive Plan depends on actual stock price appreciation and total stockholder return.

In addition, we plan to issue our named executive officers long-term equity based awards under our long-term incentive plan which are intended to compensate the officers based on the performance of our common units and their continued employment during the vesting period. These awards will be made pursuant to a long-term incentive plan adopted by us and administered by NiSource; provided, however, that awards under our long-term incentive plan will be recommended by the compensation committee of the NiSource Board and approved by our GP Board. Please read “— Long-Term Incentive Plan.” The cost of such awards will be allocated to us pursuant to NiSource’s allocation methodologies and subject to the terms of the Omnibus Agreement. The equity-based awards that we will make under our long-term incentive plan to our GP’s named executive officers and directors are intended to align their long-term interests with those of our unitholders.

The terms and amount of the equity awards that we intend to make to our GP Board’s directors under our long-term incentive plan will be recommended by NiSource’s compensation committee or its delegate and approved by our general partner.

NiSource 401(k) Plan. Under NiSource’s 401(k) plan, employees, including our named executive officers, may defer a portion of their base salary and receive employer matching contributions that vary according to the terms of the respective pension plans in which they participate. In addition, NiSource sponsors the NiSource Savings Restoration Plan which provides for a supplemental benefit equal to the difference between (i) the benefit an employee would have received under the NiSource 401(k) plan had such benefit not been limited by sections 415 (a limitation on annual contributions under a defined contribution plan of $44,000) and 401(a)(17) (a limitation on annual compensation of $220,000) of the Internal Revenue Code, reduced by his or her deferrals into the Company’s Executive Deferred Compensation Plan, minus (ii) the actual benefit he or she received under the Retirement Savings Plan. All of our named executive officers are eligible to participate in the Savings Restoration Plan.

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Other NiSource Benefit Plans. NiSource provides a variety of health and welfare benefits to its employees, including a number of health care plans, vision, dental, and life insurance. Our named executive officers are eligible to participate in these plans as employees of NiSource.

NiSource also has the following plans in which our named executive officers may participate:

Executive Deferred Compensation Plan. The NiSource Executive Deferred Compensation Plan allows employees at certain job levels and other key employees designated by the NiSource compensation committee to defer and invest between 5% and 80% of their compensation and between 5% and 100% of their incentive payment on a pre-tax basis. Employees designate how their contributions will be invested; the investment options generally are the same as those available under NiSource’s 401(k) plan. Employee contributions and any earnings thereon are 100% vested.

Pension Plans. NiSource and its affiliates sponsor several qualified pension plans for their respective employees. The plan in which an employee participates, including our named executive officers, differs depending upon the affiliate into which the employee was hired. The pensions are payable out of a trust fund, which consists of contributions made by NiSource and the earnings of the fund. Over a period of years the contributions are intended to result in overall actuarial solvency of the trust fund. The pension plans of NiSource have been determined by the Internal Revenue Service to be qualified under Section 401 of the Internal Revenue Code.

We believe that each of the base salary, cash award, and equity awards fit our overall compensation objectives and those of NiSource, as stated above, i.e., to attract and retain highly qualified executives and provide compensation in a manner that is designed to relate total compensation to corporate performance, while remaining competitive with the compensation practices of competitors in the energy industry and, to a lesser extent, general industry.

Compensation of Directors

Officers or employees of our general partner or its affiliates who also serve as directors of our general partner will not receive additional compensation for their service as a director of our general partner. Each non-employee director will be reimbursed for the director’s out-of-pocket expenses in connection with attending meetings of the board of directors or committees. Each director will be fully indemnified by us for the director’s actions associated with being a director to the fullest extent permitted under Delaware law.

Long-Term Incentive Plan

General. Our general partner intends to adopt a Long-Term Incentive Plan, or the Plan, for employees and directors of our general partner and its affiliates who perform services for us. The summary of the Plan contained herein does not purport to be complete and is qualified in its entirety by reference to the Plan. The Plan provides for the grant of restricted units, phantom units, unrestricted units, unit options, substitute awards, performance awards and distribution equivalent rights, or DERs. Subject to adjustment for certain events, an aggregate of 2,100,000 common units may be delivered pursuant to awards under the Plan. Units subject to awards that are cancelled, forfeited, exercised, withheld to satisfy our general partner’s tax withholding obligations or otherwise terminate or expire without the actual delivery of common units are available for delivery pursuant to other awards. The Plan will be administered by the NiSource Board’s compensation committee, provided that administration may be delegated to such other committee as appointed by our GP Board and to the chair of our GP Board with respect to any individuals who are not subject to Rule 16b-3 under the Exchange Act.

Restricted Units and Phantom Units. A restricted unit is a common unit that is subject to forfeiture. Upon vesting, the grantee receives a common unit that is not subject to forfeiture. A phantom unit is a notional unit that entitles the grantee to receive a common unit upon the vesting of the phantom unit or, in the discretion of the compensation committee, cash equal to the fair market value of a common unit. The compensation committee may make grants of restricted units and phantom units under the Plan to eligible individuals containing such terms, consistent with the Plan, as the compensation committee may determine,

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including the period over which restricted units and phantom units granted will vest. The compensation committee may, in its discretion, base vesting on the grantee’s completion of a period of service or upon the achievement of specified financial objectives or other criteria. In addition, the restricted and phantom units will vest upon a change of control (as defined in the applicable award agreement) of us or our general partner, if so provided in the award agreement.

If a grantee’s employment or membership on our GP Board terminates for any reason, the grantee’s restricted units and phantom units will be automatically forfeited unless, and to the extent, the award agreement or the compensation committee provides otherwise. Common units to be delivered with respect to these awards may be common units acquired by our general partner in the open market, common units already owned by our general partner, common units acquired by our general partner directly from us or any other person, or any combination of the foregoing. Our general partner will be entitled to reimbursement by us for the cost incurred in acquiring common units. If we issue new common units with respect to these awards, the total number of common units outstanding will increase.

Distributions made by us with respect to awards of restricted units may, in the compensation committee’s discretion, be subject to the same vesting requirements as the restricted units. The compensation committee, in its discretion, may also grant tandem DERs with respect to phantom units on such terms as it deems appropriate. DERs are rights that entitle the grantee to receive, with respect to a phantom unit, cash equal to the cash distributions made by us on a common unit.

We intend for the restricted units and phantom units granted under the Plan to serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation of the common units. Therefore, participants will not pay any consideration for the common units they receive with respect to these types of awards, and neither we nor our general partner will receive remuneration for the units delivered with respect to these awards.

Unit Options. The Plan also permits the grant of options covering common units. Unit options may be granted to such eligible individuals and with such terms as the compensation committee may determine, consistent with the Plan; however, a unit option must have an exercise price equal to the fair market value of a common unit on the date of grant. A unit option will vest upon a change of control (as defined in the applicable award agreement) of us or our general partner, if so provided in the award agreement.

Upon exercise of a unit option, our general partner will acquire common units in the open market at a price equal to the prevailing price on the principal national securities exchange upon which the common units are then traded, or directly from us or any other person, or use common units already owned by our general partner, or any combination of the foregoing. Our general partner will be entitled to reimbursement by us for the difference between the cost incurred by our general partner in acquiring the common units and the proceeds received by our general partner from an optionee at the time of exercise. Thus, we will bear the cost of the unit options. If we issue new common units upon exercise of the unit options, the total number of common units outstanding will increase, and our general partner will remit the proceeds it received from the optionee upon exercise of the unit option to us. The unit option plan has been designed to furnish additional compensation to employees and directors and to align their economic interests with those of common unitholders.

Substitution Awards. The compensation committee, in its discretion, may grant substitute or replacement awards to eligible individuals who, in connection with an acquisition made by us, our general partner or an affiliate, have forfeited an equity-based award in their former employer. A substitute award that is an option may have an exercise price less than the value of a common unit on the date of grant of the award.

Performance Awards. The compensation committee, in its discretion, may grant performance awards to eligible individuals based upon the individuals’ satisfaction of pre-established performance criteria as determined by the committee.

Distribution Equivalent Rights. The compensation committee, in its discretion, may grant DERs as stand-alone awards or in combination with another award.

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Termination of Long-Term Incentive Plan. The GP Board, in its discretion, may terminate the Plan at any time with respect to the common units for which a grant has not theretofore been made. The Plan will automatically terminate on the earlier of the 10th anniversary of the date it was initially approved by our unitholders or when common units are no longer available for delivery pursuant to awards under the Plan. The GP Board will also have the right to alter or amend the Plan or any part of it from time to time and the compensation committee may amend any award; provided, however, that no change in any outstanding award may be made that would materially impair the rights of the participant without the consent of the affected participant. Subject to unitholder approval, if required by the rules of the principal national securities exchange upon which the common units are traded, the GP Board may increase the number of common units that may be delivered with respect to awards under the Plan.

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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth the beneficial ownership of our common and subordinated units that will be issued upon the consummation of this offering and the related transactions and held by:


	•	each person who then will beneficially own 5% or more of the then outstanding common and subordinated units;

	•	all of the directors of NiSource GP, LLC;

	•	each named executive officer of NiSource GP, LLC; and

	•	all directors and officers of NiSource GP, LLC as a group.


											Percentage of
											Total
			Percentage of					Percentage of			Common and
	Common		Common			Subordinated		Subordinated			Subordinated
	Units to be		Units to be			Units to be		Units to be			Units to be
	Beneficially		Beneficially			Beneficially		Beneficially			Beneficially
Name of Beneficial Owner(1)	Owned		Owned			Owned		Owned			Owned

NiSource Inc.(2)		8,584,349		40.7	%		10,222,715		100	%		60.0	%
Columbia Energy Holdings Corporation		8,584,349		40.7	%		10,222,715		100	%		60.0	%
Robert C. Skaggs, Jr.(3)		—		—	%		—		—	%		—	%
Christopher A. Helms(3)(4)		—		—	%		—		—	%		—	%
Michael W. O’Donnell(3)		—		—	%		—		—	%		—	%
James F. Thomas(3)(4)		—		—	%		—		—	%		—	%
Carrie J. Hightman(3)		—		—	%		—		—	%		—	%
All directors and executive officers as a group ( persons)		—		—	%		—		—	%		—	%


(1)		Unless otherwise indicated, the address for all beneficial owners in this table is 801 East 86th Avenue, Merrillville, Indiana 46410.

(2)		NiSource Inc. is the ultimate parent company of Columbia Energy Holdings Corporation and may be deemed to beneficially own the units held by Columbia Energy Holdings Corporation.

(3)		Does not include common units that may be purchased in the directed unit program.

(4)		The address for Mr. Helms and Mr. Thomas is 5151 San Felipe, Suite 2500, Houston, Texas 77056.

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

After this offering, NiSource and its affiliates will own 8,584,349 common units and 10,222,715 subordinated units representing an aggregate 58.9% limited partner interest in us. In addition, our general partner will own a 2% general partner interest in us and the incentive distribution rights.

Distributions and Payments to Our General Partner and its Affiliates

The following table summarizes the distributions and payments to be made by us to our general partner and its affiliates in connection with the formation, ongoing operation and any liquidation of NiSource Energy Partners, L.P. These distributions and payments were determined by and among affiliated entities and, consequently, are not the result of arm’s-length negotiations.

Formation Stage


The consideration received by NiSource and its subsidiaries for the contribution of the assets and liabilities to us		• 8,584,349 common units;

		• 10,222,715 subordinated units;

		• 638,920 general partner units;

		• the incentive distribution rights; and

		• $269.7 million cash payment from the proceeds of this offering and related borrowings under our credit facility.

Operational Stage


Distributions of available cash to our general partner and its affiliates		We will generally make cash distributions 98% to our unitholders pro rata, including our general partner and its affiliates, as the holders of an aggregate 8,584,349 common units 10,222,715 subordinated units, and 2% to our general partner. In addition, if distributions exceed the minimum quarterly distribution and other higher target distribution levels, our general partner will be entitled to increasing percentages of the distributions, up to 50% of the distributions above the highest target distribution level.

		Assuming we have sufficient available cash to pay the full minimum quarterly distribution on all of our outstanding units for four quarters, our general partner and its affiliates would receive an annual distribution of approximately $0.8 million on their general partner units and $22.6 million on their common and subordinated units.

Payments to our general partner and its affiliates		We will reimburse NiSource and its affiliates for the payment of certain operating expenses and for the provision of various general and administrative services for our benefit. For further information regarding the administrative fee, please read “— Omnibus Agreement — Reimbursement of Operating and General and Administrative Expense.”

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Withdrawal or removal of our general partner		If our general partner withdraws or is removed, its general partner interest and its incentive distribution rights will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests. Please read “The Partnership Agreement — Withdrawal or Removal of the General Partner.”

Liquidation Stage


Liquidation		Upon our liquidation, the partners, including our general partner, will be entitled to receive liquidating distributions according to their respective capital account balances.

Agreements Governing the Transactions

We and other parties have entered into or will enter into the various documents and agreements that will effect the offering transactions, including the vesting of assets in, and the assumption of liabilities by, us and our subsidiaries, and the application of the proceeds of this offering. These agreements will not be the result of arm’s-length negotiations, and they, or any of the transactions that they provide for, may not be effected on terms at least as favorable to the parties to these agreements as they could have been obtained from unaffiliated third parties. All of the transaction expenses incurred in connection with these transactions, including the expenses associated with transferring assets into our subsidiaries, will be paid from the proceeds of this offering.

Omnibus Agreement

Upon the closing of this offering, we will enter into an omnibus agreement with NiSource, our general partner and others that will address NiSource’s obligation to indemnify us for certain liabilities and our obligation to indemnify NiSource for certain liabilities.

Our general partner and its affiliates will also receive payments from us pursuant to the contractual arrangements described below under the caption “— Contracts with Affiliates.”

Competition

Neither NiSource or any of its affiliates will be restricted, under either our partnership agreement or the omnibus agreement, from competing with us. NiSource and any of its affiliates may acquire, construct or dispose of additional transportation and storage or other assets in the future without any obligation to offer us the opportunity to purchase or construct those assets.

Indemnification

Under the omnibus agreement, NiSource will indemnify us for three years after the closing of this offering against certain potential environmental and toxic tort claims, losses and expenses associated with the operation of the assets and occurring before the closing date of this offering. The maximum liability of NiSource for this indemnification obligation will not exceed $ million and NiSource will not have any obligation under this indemnification until our aggregate losses exceed $ . NiSource will have no indemnification obligations with respect to environmental claims made as a result of additions to or modifications of environmental laws relating to pollution or protection of the environment or natural resources promulgated after the closing date of this offering. We have agreed to indemnify NiSource against environmental liabilities related to our assets to the extent NiSource is not required to indemnify us. In addition, if our ultimate costs exceed the $5.5 million retained for certain government-mandated pipeline improvements near Nashville, Tennessee, NiSource has agreed to indemnify us for up to $17.0 million for expenditures incurred beyond the $5.5 million.

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Additionally, NiSource will indemnify us for losses attributable to title defects, failures to obtain consents or permits necessary for the transfer of the contributed assets, retained assets and liabilities (including preclosing litigation relating to contributed assets) and income taxes attributable to pre-closing operations. We will indemnify NiSource for all losses attributable to the postclosing operations of the assets contributed to us, to the extent not subject to NiSource’s indemnification obligations.

Contracts with Affiliates

Services Agreements

We have entered into service agreements with Columbia Gas Transmission and NiSource Corporate Services Company. Pursuant to these agreements, Columbia Gas Transmission and NiSource Corporate Services Company will perform centralized corporate functions for us, including legal, accounting, compliance, treasury, insurance, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit and tax. We will reimburse Columbia Gas Transmission and NiSource Corporate Services Company for the expenses to provide these services as well as other expenses it incurs on our behalf, such as salaries of personnel performing services for our benefit and the cost of their employee benefits and general and administrative expenses associated with such personnel, capital expenditures, maintenance and repair costs, taxes, and direct expenses, including operating expenses and certain allocated operating expenses, associated with the ownership and operation of the contributed assets.

Transportation Related Arrangements

We charge transportation fees to five NiSource subsidiaries. Management anticipates continuing to provide these services to these NiSource subsidiaries in the ordinary course of business. We are party to firm transportation contracts with Columbia Gas of Kentucky, Inc, Columbia Gas of Maryland, Inc. Columbia Gas of Ohio, Inc., Columbia Gas of Pennsylvania, Inc. and Columbia Gas of Virginia, Inc. for transportation on our Mainline System. All of these contracts are at full tariff rates and have terms that expire between 2008 and 2019.

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CONFLICTS OF INTEREST AND FIDUCIARY DUTIES

Conflicts of Interest

Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its affiliates (including NiSource) on the one hand, and our partnership and our limited partners, on the other hand. The directors and officers of NiSource GP, LLC have fiduciary duties to manage NiSource GP, LLC in a manner beneficial to its owners. At the same time, our general partner has a fiduciary duty to manage our partnership in a manner beneficial to us and our unitholders.

Whenever a conflict arises between our general partner or its affiliates, on the one hand, and us or any other partner, on the other hand, our general partner will resolve that conflict. Our partnership agreement contains provisions that modify and limit our general partner’s fiduciary duties to our unitholders. Our partnership agreement also restricts the remedies available to unitholders for actions taken that, without those limitations, might constitute breaches of fiduciary duty.

Our general partner will not be in breach of its obligations under the partnership agreement or its duties to us or our unitholders if the resolution of the conflict is:


	•	approved by the conflicts committee in good faith, although our general partner is not obligated to seek such approval;

	•	approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner or any of its affiliates;

	•	on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or

	•	fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.

Our general partner may, but is not required to, seek the approval of such resolution from the conflicts committee of the board of directors of NiSource GP, LLC. If our general partner does not seek approval from the conflicts committee and the board of directors of NiSource GP, LLC determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the third and fourth bullet points above, then it will be presumed that, in making its decision, 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. Unless the resolution of a conflict is specifically provided for in our partnership agreement, our general partner or the conflicts committee may consider any factors it determines in good faith to consider when resolving a conflict. When our partnership agreement provides that someone act in good faith, it requires that person to believe he is acting in the best interests of the partnership.

Conflicts of interest could arise in the situations described below, among others.

NiSource and its affiliates are not limited in their ability to compete with us, which could cause conflicts of interest and limit our ability to acquire additional assets or businesses which in turn could adversely affect our results of operations and cash available for distribution to our unitholders.

Neither our partnership agreement nor the omnibus agreement between us, NiSource and others will prohibit NiSource and its affiliates from owning assets or engaging in businesses that compete directly or indirectly with us. In addition, NiSource and its affiliates may acquire, construct or dispose of additional transportation, storage or other assets in the future, without any obligation to offer us the opportunity to purchase or construct any of those assets. NiSource is a large, established participant in the transportation and storage business, and has significantly greater resources and experience than we have, which factors may make it more difficult for us to compete with NiSource with respect to commercial activities as well as for acquisitions candidates. As a result, competition from NiSource and its affiliates could adversely impact our results of operations and cash available for distribution.

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Neither our partnership agreement nor any other agreement requires NiSource to pursue a business strategy that favors us or utilizes our assets or dictates what markets to pursue or grow. NiSource’s directors have a fiduciary duty to make these decisions in the best interests of the owners of NiSource, which may be contrary to our interests.

Because certain of the directors of our general partner are also directors and/or officers of NiSource, such directors have fiduciary duties to NiSource that may cause them to pursue business strategies that disproportionately benefit NiSource or which otherwise are not in our best interests.

Our general partner is allowed to take into account the interests of parties other than us, such as NiSource, in resolving conflicts of interest.

Our partnership agreement contains provisions that reduce the standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include the exercise of its right to make a determination to receive Class B units in exchange for resetting the target distribution levels related to its incentive distribution rights, its limited call right, its rights to transfer or vote the units it owns, its registration rights and its determination whether or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement.

We will not have any employees and will rely on the employees of our general partner and its affiliates.

All of our executive management personnel will be employees of an affiliate of NiSource and will not devote 100% of their time to our business and affairs. We will also utilize a significant number of employees of NiSource to operate our business and provide us with general and administrative services for which we will reimburse NiSource for allocated expenses of operational personnel who perform services for our benefit and we will reimburse NiSource for allocated general and administrative expenses. Affiliates of our general partner and NiSource will also conduct businesses and activities of their own in which we will have no economic interest. If these separate activities are significantly greater than our activities, there could be material competition for the time and effort of the officers and employees who provide services to NiSource and its affiliates.

Our partnership agreement limits our general partner’s fiduciary duties to holders of our common units and subordinated units and restricts the remedies available to holders of our common units and subordinated units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

Our partnership agreement contains provisions that reduce the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty laws. For example, our partnership agreement:


	•	permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include the exercise of its right to make a determination to receive Class B units in exchange for resetting the target distribution levels related to its incentive distribution rights, the exercise of its limited call right, the exercise of its rights to transfer or vote the units it owns, the exercise of its registration rights and its determination whether or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement;

	•	provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as it acted in good faith, meaning it believed the decision was in the best interests of our partnership;

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	•	generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the conflicts committee of the board of directors of our general partner acting in good faith and not involving a vote of unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or must be “fair and reasonable” to us, as determined by our general partner in good faith and that, in determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us;

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

	•	provides that in resolving conflicts of interest, it will be presumed that in making its decision the general partner or its conflicts committee acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.

By purchasing a common unit, a common unitholder will agree to become bound by the provisions in the partnership agreement, including the provisions discussed above. Please read “Conflicts of Interest and Fiduciary Duties — Fiduciary Duties.”

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

Under our partnership agreement, our general partner has full power and authority to do all things, other than those items that require unitholder approval or with respect to which our general partner has sought conflicts committee approval, on such terms as it determines to be necessary or appropriate to conduct our business including, but not limited to, the following:


	•	the making of any expenditures, the lending or borrowing of money, the assumption or guarantee of or other contracting for, indebtedness and other liabilities, the issuance of evidences of indebtedness, including indebtedness that is convertible into our securities, and the incurring of any other obligations;

	•	the purchase, sale or other acquisition or disposition of our securities, or the issuance of additional options, rights, warrants and appreciation rights relating to our securities;

	•	the mortgage, pledge, encumbrance, hypothecation or exchange of any or all of our assets;

	•	the negotiation, execution and performance of any contracts, conveyances or other instruments;

	•	the distribution of our cash;

	•	the selection and dismissal of employees and agents, outside attorneys, accountants, consultants and contractors and the determination of their compensation and other terms of employment or hiring;

	•	the maintenance of insurance for our benefit and the benefit of our partners;

	•	the formation of, or acquisition of an interest in, the contribution of property to, and the making of loans to, any limited or general partnerships, joint ventures, corporations, limited liability companies or other relationships;

	•	the control of any matters affecting our rights and obligations, including the bringing and defending of actions at law or in equity and otherwise engaging in the conduct of litigation, arbitration or mediation and the incurring of legal expense and the settlement of claims and litigation;

	•	the indemnification of any person against liabilities and contingencies to the extent permitted by law;

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	•	the making of tax, regulatory and other filings, or rendering of periodic or other reports to governmental or other agencies having jurisdiction over our business or assets; and

	•	the entering into of agreements with any of its affiliates to render services to us or to itself in the discharge of its duties as our general partner.

Our partnership agreement provides that our general partner must act in “good faith” when making decisions on our behalf, and our partnership agreement further provides that in order for a determination by our general partner to be made in “good faith,” our general partner must believe that the determination is in our best interests. Please read “The Partnership Agreement — Voting Rights” for information regarding matters that require unitholder approval.

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

The amount of cash that is available for distribution to unitholders is affected by decisions of our general partner regarding such matters as:


	•	amount and timing of asset purchases and sales;

	•	cash expenditures;

	•	borrowings;

	•	the issuance of additional units; and

	•	the creation, reduction or increase of reserves in any quarter.

In addition, our general partner may use an operating surplus “basket,” which would not otherwise constitute available cash from operating surplus, in order to permit the payment of cash distributions on its units and incentive distribution rights. The amount of this basket is calculated as described in the definition of “Operating Surplus” contained in the glossary in Appendix D. All of these actions may affect the amount of cash distributed to our unitholders and the general partner and may facilitate the conversion of subordinated units into common units. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions.”

In addition, borrowings by us and our affiliates do not constitute a breach of any duty owed by the general partner to our unitholders, including borrowings that have the purpose or effect of:


	•	enabling our general partner or its affiliates to receive distributions on any subordinated units held by them or the incentive distribution rights; or

	•	hastening the expiration of the subordination period.

For example, in the event we have not generated sufficient cash from our operations to pay the minimum quarterly distribution on our common units and our subordinated units, our partnership agreement permit us to borrow funds, which would enable us to make this distribution on all outstanding units. Please read “Provisions of Our Partnership Agreement Related to Cash Distributions — Subordination Period.”

Our partnership agreement provides that we and our subsidiaries may borrow funds from our general partner and its affiliates. Our general partner and its affiliates may not borrow funds from us, our operating company, or its operating subsidiaries.

Our general partner determines which costs incurred by NiSource are reimbursable by us.

We will reimburse our general partner and its affiliates for costs incurred in managing and operating us, including costs incurred in rendering corporate staff and support services to us. The partnership agreement provides that our general partner will determine the expenses that are allocable to us in good faith.

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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 any of these entities on our behalf.

Our partnership agreement allows our general partner to determine, in good faith, any amounts to pay itself or its affiliates for any services rendered to us. Our general partner may also enter into additional contractual arrangements with any of its affiliates on our behalf. Neither our partnership agreement nor any of the other agreements, contracts or arrangements between us, on the one hand, and our general partner and its affiliates, on the other hand, that will be in effect as of the closing of this offering will be the result of arm’s length negotiations. Similarly, agreements, contracts or arrangements between us and our general partner and its affiliates that are entered into following the closing of this offering will not be required to be negotiated on an arm’s-length basis, although, in some circumstances, our general partner may determine that the conflicts committee of our general partner may make a determination on our behalf with respect to one or more of these types of situations.

Our general partner will determine, in good faith, the terms of any of these transactions entered into after the sale of the common units offered in this offering.

Our general partner and its affiliates will have no obligation to permit us to use any facilities or assets of our general partner or its affiliates, except as may be provided in contracts entered into specifically dealing with that use. There is no obligation of our general partner or its affiliates to enter into any contracts of this kind.

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

Our general partner intends to limit its liability under contractual arrangements so that the other party has recourse only to our assets, and not against our general partner or its assets. The partnership agreement provides that any action taken by our general partner to limit its liability is not a breach of our general partner’s fiduciary duties, even if we could have obtained more favorable terms without the limitation on liability.

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

Our general partner may exercise its right to call and purchase common units as provided in the partnership agreement or assign this right to one of its affiliates or to us. Our general partner is not bound by fiduciary duty restrictions in determining whether to exercise this right. As a result, a common unitholder may have his common units purchased from him at an undesirable time or price. Please read “The Partnership Agreement — Limited Call Right.”

Common unitholders will have no right to enforce obligations of our general partner and its affiliates under agreements with us.

Any agreements between us on the one hand, and our general partner and its affiliates, on the other, will not grant to the unitholders, separate and apart from us, the right to enforce the obligations of our general partner and its affiliates in our favor.

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

The attorneys, independent accountants and others who have performed services for us regarding this offering have been retained by our general partner. Attorneys, independent accountants and others who perform services for us are selected by our general partner or the conflicts committee and may perform services for our general partner and its affiliates. We may retain separate counsel for ourselves or the holders of common units in the event of a conflict of interest between our general partner and its affiliates, on the one hand, and us or

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the holders of common units, on the other, depending on the nature of the conflict. We do not intend to do so in most cases.

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

Our general partner has the right, at a time when there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled (48%) for each of the prior four consecutive fiscal quarters, to reset the initial cash target distribution levels at higher levels based on the distribution at the time of the exercise of the reset election. Following a reset election by our general partner, the minimum quarterly distribution amount will be reset to an amount equal to the average cash distribution amount per common unit for the two fiscal quarters 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 amount. We anticipate that our general partner 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; however, it is possible that our general partner could exercise this reset election at a time when we are experiencing declines in our aggregate cash distributions or at a time when our general partner expects that we will experience declines in our aggregate cash distributions in the foreseeable future. In such situations, our general partner may be experiencing, or may be expected to experience, declines in the cash distributions it receives related to its incentive distribution rights and may therefore desire to be issued our Class B units, which are entitled to specified priorities with respect to our distributions and which therefore may be more advantageous for the general partner to own in lieu of the right to receive incentive distribution payments based on target distribution levels that are less certain to be achieved in the then current business environment. As a result, a reset election may cause our common unitholders to experience dilution in the amount of cash distributions that they would have otherwise received had we not issued new Class B units to our general partner in connection with resetting the target distribution levels related to our general partner incentive distribution rights. Please read “Provisions of Our Partnership Agreement Related to Cash Distributions — General Partner Interest and Incentive Distribution Rights.”

Fiduciary Duties

Our general partner is accountable to us and our unitholders as a fiduciary. Fiduciary duties owed to unitholders by our general partner are prescribed by law and the partnership agreement. The Delaware Revised Uniform Limited Partnership Act, which we refer to in this prospectus as the Delaware Act, provides that Delaware limited partnerships may, in their partnership agreements, modify, restrict or expand the fiduciary duties otherwise owed by a general partner to limited partners and the partnership.

Our partnership agreement contains various provisions modifying and restricting the fiduciary duties that might otherwise be owed by our general partner. We have adopted these restrictions to allow our general partner or its affiliates to engage in transactions with us that would otherwise be prohibited by state-law fiduciary duty standards and to take into account the interests of other parties in addition to our interests when resolving conflicts of interest. We believe this is appropriate and necessary because our general partner’s board of directors will have fiduciary duties to manage our general partner in a manner beneficial to its owners, as well as to you. Without these modifications, the general partner’s ability to make decisions involving conflicts of interest would be restricted. The modifications to the fiduciary standards enable the general partner to take into consideration all parties involved in the proposed action, so long as the resolution is fair and reasonable to us. These modifications also enable our general partner to attract and retain experienced and capable directors. These modifications are detrimental to our common unitholders because they restrict the remedies available to unitholders for actions that, without those limitations, might constitute breaches of fiduciary duty, as described below, and permit our general partner to take into account the interests of third parties in addition to our

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interests when resolving conflicts of interest. The following is a summary of the material restrictions of the fiduciary duties owed by our general partner to the limited partners:


State-law fiduciary duty standards		Fiduciary duties are generally considered to include an obligation to act in good faith and with due care and loyalty. The duty of care, in the absence of a provision in a partnership agreement providing otherwise, would generally require a general partner to act for the partnership in the same manner as a prudent person would act on his own behalf. The duty of loyalty, in the absence of a provision in a partnership agreement providing otherwise, would generally prohibit a general partner of a Delaware limited partnership from taking any action or engaging in any transaction where a conflict of interest is present.

		The Delaware Act generally provides that a limited partner may institute legal action on behalf of the partnership to recover damages from a third party where a general partner has refused to institute the action or where an effort to cause a general partner to do so is not likely to succeed. In addition, the statutory or case law of some jurisdictions may permit a limited partner to institute legal action on behalf of himself and all other similarly situated limited partners to recover damages from a general partner for violations of its fiduciary duties to the limited partners.

Partnership agreement modified standards		Our partnership agreement contains provisions that waive or consent to conduct by our general partner and its affiliates that might otherwise raise issues about compliance with fiduciary duties or applicable law. For example, our partnership agreement provides that when our general partner is acting in its capacity as our general partner, as opposed to in its individual capacity, it must act in “good faith” and will not be subject to any other standard under applicable law. In addition, when our general partner is acting in its individual capacity, as opposed to in its capacity as our general partner, it may act without any fiduciary obligation to us or the unitholders whatsoever. These standards reduce the obligations to which our general partner would otherwise be held.

		In addition to the other more specific provisions limiting the obligations of our general partner, our partnership agreement further provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for errors of judgment or for any acts or omissions unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that the general partner or its officers and directors acted in bad faith or engaged in fraud or willful misconduct or in the case of a criminal matter, acted with knowledge that the indemnitee’s conduct was criminal.

		Special provisions regarding affiliated transactions. Our partnership agreement generally provides that affiliated transactions and resolutions of conflicts of interest not involving a vote of unitholders and that are not approved by the conflicts committee of the board of directors of our general partner must be:

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		• on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or

		• “fair and reasonable” to us, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to us).

		If our general partner does not seek approval from the conflicts committee and its board of directors determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the bullet points above, then it will be presumed that, in making its decision, the board of directors, which may include board members affected by the conflict of interest, 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. These standards reduce the obligations to which our general partner would otherwise be held.

By purchasing our common units, each common unitholder automatically agrees to be bound by the provisions in the partnership agreement, including the provisions discussed above. This is in accordance with the policy of the Delaware Act favoring the principle of freedom of contract and the enforceability of partnership agreements. The failure of a limited partner or assignee to sign a partnership agreement does not render the partnership agreement unenforceable against that person.

We must indemnify our general partner and its officers, directors, managers and certain other specified persons, to the fullest extent permitted by law, against liabilities, costs and expenses incurred by our general partner or these other persons. We must provide this indemnification unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that these persons acted in bad faith or engaged in fraud or willful misconduct. We must also provide this indemnification for criminal proceedings unless our general partner or these other persons acted with knowledge that their conduct was unlawful. Thus, our general partner could be indemnified for its negligent acts if it meets the requirements set forth above. To the extent these provisions purport to include indemnification for liabilities arising under the Securities Act, in the opinion of the SEC, such indemnification is contrary to public policy and, therefore, unenforceable. Please read “The Partnership Agreement — Indemnification.”

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DESCRIPTION OF THE COMMON UNITS

The Units

The common units and the subordinated units are separate classes of limited partner interests in us. The holders of units are entitled to participate in partnership distributions and exercise the rights or privileges available to limited partners under our partnership agreement. For a description of the relative rights and preferences of holders of common units and subordinated units in and to partnership distributions, please read this section and “Our Cash Distribution Policy and Restrictions on Distributions.” For a description of the rights and privileges of limited partners under our partnership agreement, including voting rights, please read “The Partnership Agreement.”

Transfer Agent and Registrar

Duties. BNY Mellon Shareowner Services will serve as registrar and transfer agent for the common units. We will pay all fees charged by the transfer agent for transfers of common units except the following that must be paid by unitholders:


	•	surety bond premiums to replace lost or stolen certificates, taxes and other governmental charges;

	•	special charges for services requested by a common unitholder; and

	•	other similar fees or charges.

There will be no charge to unitholders for disbursements of our cash distributions. We will indemnify the transfer agent, its agents and each of their stockholders, directors, officers and employees against all claims and losses that may arise out of acts performed or omitted for its activities in that capacity, except for any liability due to any gross negligence or intentional misconduct of the indemnified person or entity.

Resignation or Removal. The transfer agent may resign, by notice to us, or be removed by us. The resignation or removal of the transfer agent will become effective upon our appointment of a successor transfer agent and registrar and its acceptance of the appointment. If no successor has been appointed and has accepted the appointment within 30 days after notice of the resignation or removal, our general partner may act as the transfer agent and registrar until a successor is appointed.

Transfer of Common Units

The transfer of the common units to persons that purchase directly from the underwriters will be accomplished through the proper completion, execution and delivery of a transfer application by the investor. Any later transfers of a common unit will not be recorded by the transfer agent or recognized by us unless the transferee executes and delivers a properly completed transfer application. By executing and delivering a transfer application, the transferee of common units:


	•	becomes the record holder of the common units and is an assignee until admitted into our partnership as a substituted limited partner;

	•	automatically requests admission as a substituted limited partner in our partnership;

	•	executes and agrees to be bound by the terms and conditions of our partnership agreement;

	•	represents that the transferee has the capacity, power and authority to enter into our partnership agreement;

	•	grants powers of attorney to the officers of our general partner and any liquidator of us as specified in our partnership agreement;

	•	gives the consents, covenants, representations and approvals contained in our partnership agreement, such as the approval of all transactions and agreements we are entering into in connection with our formation and this offering; and

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	•	certifies:


	•	that the transferee is an individual or is an entity subject to United States federal income taxation on the income generated by us; or

	•	that, if the transferee is an entity not subject to United States federal income taxation on the income generated by us, as in the case, for example, of a mutual fund taxed as a regulated investment company or a partnership, all the entity’s owners are subject to United States federal income taxation on the income generated by us.

An assignee will become a substituted limited partner of our partnership for the transferred common units automatically upon the recording of the transfer on our books and records. Our general partner will cause any unrecorded transfers for which a properly completed and duly executed transfer application has been received to be recorded on our books and records no less frequently than quarterly.

A transferee’s broker, agent or nominee may, but is not obligated to, complete, execute and deliver a transfer application. We are entitled to treat the nominee holder of a common unit as the absolute owner. In that case, the beneficial holder’s rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.

Common units are securities and are transferable according to the laws governing transfer of securities. In addition to other rights acquired upon transfer, the transferor gives the transferee the right to request admission as a substituted limited partner in our partnership for the transferred common units. A purchaser or transferee of common units who does not execute and deliver a properly completed transfer application obtains only:


	•	the right to assign the common unit to a purchaser or other transferee; and

	•	the right to transfer the right to seek admission as a substituted limited partner in our partnership for the transferred common units.

Thus, a purchaser or transferee of common units who does not execute and deliver a properly completed transfer application:


	•	will not receive cash distributions;

	•	will not be allocated any of our income, gain, deduction, losses or credits for federal income tax or other tax purposes;

	•	may not receive some federal income tax information or reports furnished to record holders of common units; and

	•	will have no voting rights;

unless the common units are held in a nominee or “street name” account and the nominee or broker has executed and delivered a transfer application and certification as to itself and any beneficial holders.

The transferor of common units has a duty to provide the transferee with all information that may be necessary to transfer the common units. The transferor does not have a duty to ensure the execution of the transfer application by the transferee and has no liability or responsibility if the transferee neglects or chooses not to execute and deliver a properly completed transfer application to the transfer agent. Please read “The Partnership Agreement — Status as Limited Partner.”

Until a common unit has been transferred on our books, we and the transfer agent may treat the record holder of the unit as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations.

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THE PARTNERSHIP AGREEMENT

The following is a summary of the material provisions of our partnership agreement. The form of our partnership agreement is included in this prospectus as Appendix A. We will provide prospective investors with a copy of our partnership agreement upon request at no charge.

We summarize the following provisions of our partnership agreement elsewhere in this prospectus:


	•	with regard to distributions of available cash, please read “Provisions of Our Partnership Agreement Relating to Cash Distributions”;

	•	with regard to the fiduciary duties of our general partner, please read “Conflicts of Interest and Fiduciary Duties”;

	•	with regard to the transfer of common units, please read “Description of the Common Units — Transfer of Common Units”; and

	•	with regard to allocations of taxable income and taxable loss, please read “Material Tax Consequences.”

Organization and Duration

Our partnership was organized December 5, 2007 and will have a perpetual existence.

Purpose

Our purpose under the partnership agreement is limited to any business activity that is approved by our general partner and that lawfully may be conducted by a limited partnership organized under Delaware law; provided, that our general partner shall not cause us to engage, directly or indirectly, in any business activity that our general partner determines would cause us to be treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes.

Although our general partner has the ability to cause us and our subsidiaries to engage in activities other than the business of transporting and storing natural gas, our general partner has no current plans to do so and may decline to do so free of any fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us or the limited partners. Our general partner is authorized in general to perform all acts it determines to be necessary or appropriate to carry out our purposes and to conduct our business.

Power of Attorney

Each limited partner, and each person who acquires a unit from a unitholder, by accepting the common unit, automatically grants to our general partner and, if appointed, a liquidator, a power of attorney to, among other things, execute and file documents required for our qualification, continuance or dissolution. The power of attorney also grants our general partner the authority to amend, and to make consents and waivers under, our partnership agreement.

Cash Distributions

Our partnership agreement specifies the manner in which we will make cash distributions to holders of our common units and other partnership securities as well as to our general partner in respect of its general partner interest and its incentive distribution rights. For a description of these cash distribution provisions, please read “Provisions of Our Partnership Agreement Relating to Cash Distributions.”

Capital Contributions

Unitholders are not obligated to make additional capital contributions, except as described below under “— Limited Liability.”

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For a discussion of our general partner’s right to contribute capital to maintains its 2% general partner interest if we issue additional units, please read “— Issuance of Additional Securities.”

Voting Rights

The following is a summary of the unitholder vote required for the matters specified below. Matters requiring the approval of a “unit majority” require:


	•	during the subordination period, the approval of a majority of the common units, excluding those common units held by our general partner and its affiliates, and a majority of the subordinated units, voting as separate classes; and

	•	after the subordination period, the approval of a majority of the common units and Class B units, if any, voting as a single class.

In voting their common, Class B and subordinated units, our general partner and its affiliates will have no fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us or the limited partners.


Issuance of additional units		No approval right.

Amendment of the partnership agreement		Certain amendments may be made by the general partner without the approval of the unitholders. Other amendments generally require the approval of a unit majority. Please read “— Amendment of the Partnership Agreement.”

Merger of our partnership or the sale of all or substantially all of our assets		Unit majority in certain circumstances. Please read “— Merger, Consolidation, Conversion, Sale or Other Disposition of Assets.”

Dissolution of our partnership		Unit majority. Please read “— Termination and Dissolution.”

Continuation of our business upon dissolution		Unit majority. Please read “— Termination and Dissolution.”

Withdrawal of the general partner		Under most circumstances, the approval of a majority of the common units, excluding common units held by our general partner and its affiliates, is required for the withdrawal of our general partner prior to March 31, 2018 in a manner that would cause a dissolution of our partnership. Please read “— Withdrawal or Removal of the General Partner.”

Removal of the general partner		Not less than 66 2/3% of the outstanding units, voting as a single class, including units held by our general partner and its affiliates. Please read “— Withdrawal or Removal of the General Partner.”

Transfer of the general partner interest		Our general partner may transfer all, but not less than all, of its general partner interest in us without a vote of our unitholders to an affiliate or another person in connection with its merger or consolidation with or into, or sale of all or substantially all of its assets to, such person. The approval of a majority of the common units, excluding common units held by the general partner and its affiliates, is required in other circumstances for a transfer of the general partner interest to a third party prior to March 31, 2018. See ‘‘— Transfer of General Partner Units.”

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Transfer of incentive distribution rights		Our general partner may transfer any or all of the incentive distribution rights without a vote of our unitholders to an affiliate or another person as part of our general partner’s merger or consolidation with or into, or sale of all or substantially all of its assets or the sale of all of the ownership interests in such holder to, such person. The approval of a majority of the common units, excluding common units held by the general partner and its affiliates, is required in other circumstances for a transfer of the incentive distribution rights to a third party prior to March 31, 2018. Please read ‘‘— Transfer of Incentive Distribution Rights.”

Transfer of ownership interests in our general partner		No approval required at any time. Please read ‘‘— Transfer of Ownership Interests in the General Partner.”

Limited Liability

Assuming that a limited partner does not participate in the control of our business within the meaning of the Delaware Act and that he otherwise acts in conformity with the provisions of the partnership agreement, his liability under the Delaware Act will be limited, subject to possible exceptions, to the amount of capital he is obligated to contribute to us for his common units plus his share of any undistributed profits and assets. If it were determined, however, that the right, or exercise of the right, by the limited partners as a group:


	•	to remove or replace the general partner;

	•	to approve some amendments to the partnership agreement; or

	•	to take other action under the partnership agreement;

constituted “participation in the control” of our business for the purposes of the Delaware Act, then the limited partners could be held personally liable for our obligations under the laws of Delaware, to the same extent as the general partner. This liability would extend to persons who transact business with us who reasonably believe that the limited partner is a general partner. Neither the partnership agreement nor the Delaware Act specifically provides for legal recourse against the general partner if a limited partner were to lose limited liability through any fault of the general partner. While this does not mean that a limited partner could not seek legal recourse, we know of no precedent for this type of a claim in Delaware case law.

Under the Delaware Act, a limited partnership may not make a distribution to a partner if, after the distribution, all liabilities of the limited partnership, other than liabilities to partners on account of their partnership interests and liabilities for which the recourse of creditors is limited to specific property of the partnership, would exceed the fair value of the assets of the limited partnership. For the purpose of determining the fair value of the assets of a limited partnership, the Delaware Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited partnership only to the extent that the fair value of that property exceeds the nonrecourse liability. The Delaware Act provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of the Delaware Act shall be liable to the limited partnership for the amount of the distribution for three years. Under the Delaware Act, a substituted limited partner of a limited partnership is liable for the obligations of his assignor to make contributions to the partnership, except that such person is not obligated for liabilities unknown to him at the time he became a limited partner and that could not be ascertained from the partnership agreement.

Our subsidiaries conduct business in six states and we may have subsidiaries that conduct business in other states in the future. Maintenance of our limited liability as a limited partner of the operating partnership may require compliance with legal requirements in the jurisdictions in which the operating partnership conducts business, including qualifying our subsidiaries to do business there.

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Limitations on the liability of limited partners for the obligations of a limited partner have not been clearly established in many jurisdictions. If, by virtue of our partnership interest in our operating partnership or otherwise, it were determined that we were conducting business in any state without compliance with the applicable limited partnership or limited liability company statute, or that the right or exercise of the right by the limited partners as a group to remove or replace the general partner, to approve some amendments to the partnership agreement, or to take other action under the partnership agreement constituted “participation in the control” of our business for purposes of the statutes of any relevant jurisdiction, then the limited partners could be held personally liable for our obligations under the law of that jurisdiction to the same extent as the general partner under the circumstances. We will operate in a manner that the general partner considers reasonable and necessary or appropriate to preserve the limited liability of the limited partners.

Issuance of Additional Securities

Our partnership agreement authorizes us to issue an unlimited number of additional partnership securities for the consideration and on the terms and conditions determined by our general partner without the approval of the unitholders.

It is possible that we will fund acquisitions through the issuance of additional common units, subordinated units or other partnership securities. Holders of any additional common units we issue will be entitled to share equally with the then-existing holders of common units in our distributions of available cash. In addition, the issuance of additional common units or other partnership securities may dilute the value of the interests of the then-existing holders of common units in our net assets.

In accordance with Delaware law and the provisions of our partnership agreement, we may also issue additional partnership securities that, as determined by our general partner, may have special voting rights to which the common units are not entitled. In addition, our partnership agreement does not prohibit the issuance by our subsidiaries of equity securities, which may effectively rank senior to the common units.

Upon issuance of additional partnership securities (other than the issuance of common units upon exercise by the underwriters of their option to purchase additional common units, the issuance of Class B units in connection with a reset of the incentive distribution target levels or the issuance of partnership securities upon conversion of outstanding partnership securities), our general partner will be entitled, but not required, to make additional capital contributions to the extent necessary to maintain its 2% general partner interest in us. Our general partner’s 2% interest in us will be reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its 2% general partner interest. Moreover, our general partner will have the right, which it may from time to time assign in whole or in part to any of its affiliates, to purchase common units, subordinated units or other partnership securities whenever, and on the same terms that, we issue those securities to persons other than our general partner and its affiliates, to the extent necessary to maintain the percentage interest of the general partner and its affiliates, including such interest represented by common units and subordinated units, that existed immediately prior to each issuance. The holders of common units will not have preemptive rights to acquire additional common units or other partnership securities.

Amendment of the Partnership Agreement

General. Amendments to our partnership agreement may be proposed only by or with the consent of our general partner. However, our general partner will have no duty or obligation to propose any amendment and may decline to do so free of any fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us or the limited partners. In order to adopt a proposed amendment, other than the amendments discussed below, our general partner is required to seek written approval of the holders of the number of units required to approve the amendment or call a meeting of the limited partners to consider and vote upon the proposed amendment. Except as described below, an amendment must be approved by a unit majority.

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Prohibited Amendments. No amendment may be made that would:


	•	enlarge the obligations of any limited partner without its consent, unless approved by at least a majority of the type or class of limited partner interests so affected; or

	•	enlarge the obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable by us to our general partner or any of its affiliates without the consent of our general partner, which consent may be given or withheld at its option.

The provision of our partnership agreement preventing the amendments having the effects described in any of the clauses above can be amended upon the approval of the holders of at least 90% of the outstanding units voting together as a single class (including units owned by our general partner and its affiliates). Upon completion of the offering, our general partner and its affiliates will own approximately 60.0% of the outstanding common and subordinated units.

No Unitholder Approval. Our general partner may generally make amendments to our partnership agreement without the approval of any limited partner to reflect:


	•	a change in our name, the location of our principal place of our business, our registered agent or our registered office;

	•	the admission, substitution, withdrawal or removal of partners in accordance with our partnership agreement;

	•	a change that our general partner determines to be necessary or appropriate to qualify or continue our qualification as a limited partnership or a partnership in which the limited partners have limited liability under the laws of any state or to ensure that neither we nor the operating partnership nor any of its subsidiaries will be treated as an association taxable as a corporation or otherwise taxed as an entity for federal income tax purposes;

	•	an amendment that is necessary, in the opinion of our counsel, to prevent us or our general partner or its directors, officers, agents or trustees from in any manner being subjected to the provisions of the Investment Company Act of 1940, the Investment Advisors Act of 1940, or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974, or ERISA, whether or not substantially similar to plan asset regulations currently applied or proposed;

	•	an amendment that our general partner determines to be necessary or appropriate for the authorization of additional partnership securities or rights to acquire partnership securities, including any amendment that our general partner determines is necessary or appropriate in connection with:


	•	the adjustments of the minimum quarterly distribution, first target distribution, second target distribution and third target distribution in connection with the reset of our general partner’s incentive distribution rights as described under “Provisions of Our Partnership Agreement Relating to Cash Distributions — General Partner’s Right to Reset Incentive Distribution Levels”; or

	•	the implementation of the provisions relating to our general partner’s right to reset its incentive distribution rights in exchange for Class B units; and

	•	any modification of the incentive distribution rights made in connection with the issuance of additional partnership securities or rights to acquire partnership securities, provided that, any such modifications and related issuance of partnership securities have received approval by a majority of the members of the conflicts committee of our general partner;


	•	any amendment expressly permitted in our partnership agreement to be made by our general partner acting alone;

	•	an amendment effected, necessitated or contemplated by a merger agreement that has been approved under the terms of our partnership agreement;

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	•	any amendment that our general partner determines to be necessary or appropriate for the formation by us of, or our investment in, any corporation, partnership or other entity, as otherwise permitted by our partnership agreement;

	•	a change in our fiscal year or taxable year and related changes;

	•	conversions into, mergers with or conveyances to another limited liability entity that is newly formed and has no assets, liabilities or operations at the time of the conversion, merger or conveyance other than those it receives by way of the conversion, merger or conveyance; or

	•	any other amendments substantially similar to any of the matters described in the clauses above.

In addition, our general partner may make amendments to our partnership agreement without the approval of any limited partner if our general partner determines that those amendments:


	•	do not adversely affect in any material respect the limited partners considered as a whole or any particular class of limited partners as compared to other classes of limited partners;

	•	are necessary or appropriate to satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute;

	•	are necessary or appropriate to facilitate the trading of limited partner interests or to comply with any rule, regulation, guideline or requirement of any securities exchange on which the limited partner interests are or will be listed for trading;

	•	are necessary or appropriate for any action taken by our general partner relating to splits or combinations of units under the provisions of our partnership agreement; or

	•	are required to effect the intent expressed in this prospectus or the intent of the provisions of our partnership agreement or are otherwise contemplated by our partnership agreement.

Opinion of Counsel and Unitholder Approval. For amendments of the type not requiring unitholder approval, our general partner will not be required to obtain an opinion of counsel that an amendment will not result in a loss of limited liability to the limited partners or result in our being treated as an entity for federal income tax purposes in connection with any of the amendments. No other amendments to our partnership agreement will become effective without the approval of holders of at least 90% of the outstanding units voting as a single class unless we first obtain an opinion of counsel to the effect that the amendment will not affect the limited liability under applicable law of any of our limited partners.

In addition to the above restrictions, any amendment that would have a material adverse effect on the rights or preferences of any type or class of outstanding units in relation to other classes of units will require the approval of at least a majority of the type or class of units so affected. Any amendment that reduces the voting percentage required to take any action is required to be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than the voting requirement sought to be reduced.

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

A merger, consolidation or conversion of us requires the prior consent of our general partner. However, our general partner will have no duty or obligation to consent to any merger, consolidation or conversion and may decline to do so free of any fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interest of us or the limited partners.

In addition, the partnership agreement generally prohibits our general partner without the prior approval of the holders of a unit majority, from causing us to, among other things, sell, exchange or otherwise dispose of all or substantially all of our assets in a single transaction or a series of related transactions, including by way of merger, consolidation or other combination, or approving on our behalf the sale, exchange or other disposition of all or substantially all of the assets of our subsidiaries. Our general partner may, however,

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mortgage, pledge, hypothecate or grant a security interest in all or substantially all of our assets without that approval. Our general partner may also sell all or substantially all of our assets under a foreclosure or other realization upon those encumbrances without that approval. Finally, our general partner may consummate any merger without the prior approval of our unitholders if we are the surviving entity in the transaction, our general partner has received an opinion of counsel regarding limited liability and tax matters, the transaction would not result in a material amendment to the partnership agreement, each of our units will be an identical unit of our partnership following the transaction, and the partnership securities to be issued do not exceed 20% of our outstanding partnership securities immediately prior to the transaction.

If the conditions specified in the partnership agreement are satisfied, our general partner may convert us or any of our subsidiaries into a new limited liability entity or merge us or any of our subsidiaries into, or convey all of our assets to, a newly formed entity if the sole purpose of that conversion, merger or conveyance is to effect a mere change in our legal form into another limited liability entity, our general partner has received an opinion of counsel regarding limited liability and tax matters, and the governing instruments of the new entity provide the limited partners and the general partner with the same rights and obligations as contained in the partnership agreement. The unitholders are not entitled to dissenters’ rights of appraisal under the partnership agreement or applicable Delaware law in the event of a conversion, merger or consolidation, a sale of substantially all of our assets or any other similar transaction or event.

Termination and Dissolution

We will continue as a limited partnership until terminated under our partnership agreement. We will dissolve upon:


	•	the election of our general partner to dissolve us, if approved by the holders of units representing a unit majority;

	•	there being no limited partners, unless we are continued without dissolution in accordance with applicable Delaware law;

	•	the entry of a decree of judicial dissolution of our partnership; or

	•	the withdrawal or removal of our general partner or any other event that results in its ceasing to be our general partner other than by reason of a transfer of its general partner interest in accordance with our partnership agreement or withdrawal or removal following approval and admission of a successor.

Upon a dissolution under the last clause above, the holders of a unit majority may also elect, within specific time limitations, to continue our business on the same terms and conditions described in our partnership agreement by appointing as a successor general partner an entity approved by the holders of units representing a unit majority, subject to our receipt of an opinion of counsel to the effect that:


	•	the action would not result in the loss of limited liability of any limited partner; and

	•	neither our partnership, our operating partnership nor any of our other subsidiaries would be treated as an association taxable as a corporation or otherwise be taxable as an entity for federal income tax purposes upon the exercise of that right to continue.

Liquidation and Distribution of Proceeds

Upon our dissolution, unless we are continued as a new limited partnership, the liquidator authorized to wind up our affairs will, acting with all of the powers of our general partner that are necessary or appropriate to liquidate our assets and apply the proceeds of the liquidation as described in “Provisions of Our Partnership Agreement Relating to Cash Distributions — Distributions of Cash Upon Liquidation.” The liquidator may defer liquidation or distribution of our assets for a reasonable period of time or distribute assets to partners in kind if it determines that a sale would be impractical or would cause undue loss to our partners.

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Withdrawal or Removal of the General Partner

Except as described below, our general partner has agreed not to withdraw voluntarily as our general partner prior to March 31, 2018 without obtaining the approval of the holders of at least a majority of the outstanding common units, excluding common units held by the general partner and its affiliates, and furnishing an opinion of counsel regarding limited liability and tax matters. On or after March 31, 2018, our general partner may withdraw as general partner without first obtaining approval of any unitholder by giving 90 days’ written notice, and that withdrawal will not constitute a violation of our partnership agreement. Notwithstanding the information above, our general partner may withdraw without unitholder approval upon 90 days’ notice to the limited partners if at least 50% of the outstanding common units are held or controlled by one person and its affiliates other than the general partner and its affiliates. In addition, the partnership agreement permits our general partner in some instances to sell or otherwise transfer all of its general partner interest in us without the approval of the unitholders. Please read “— Transfer of General Partner Units” and “— Transfer of Incentive Distribution Rights.”

Upon withdrawal of our general partner under any circumstances, other than as a result of a transfer by our general partner of all or a part of its general partner interest in us, the holders of a unit majority, voting as separate classes, may select a successor to that withdrawing general partner. If a successor is not elected, or is elected but an opinion of counsel regarding limited liability and tax matters cannot be obtained, we will be dissolved, wound up and liquidated, unless within a specified period after that withdrawal, the holders of a unit majority agree in writing to continue our business and to appoint a successor general partner. Please read “— Termination and Dissolution.”

Our general partner may not be removed unless that removal is approved by the vote of the holders of not less than 662/3% of the outstanding units, voting together as a single class, including units held by our general partner and its affiliates, and we receive an opinion of counsel regarding limited liability and tax matters. Any removal of our general partner is also subject to the approval of a successor general partner by the vote of the holders of a majority of the outstanding common units and Class B units, if any, voting as a separate class, and subordinated units, voting as a separate class. The ownership of more than 331/3% of the outstanding units by our general partner and its affiliates would give them the practical ability to prevent our general partner’s removal. At the closing of this offering, our general partner and its affiliates will own approximately 60.0% of the outstanding common and subordinated units.

Our partnership agreement also provides that if our general partner is removed as our general partner under circumstances where cause does not exist and units held by the general partner and its affiliates are not voted in favor of that removal:


	•	the subordination period will end, and all outstanding subordinated units will immediately convert into common units on a one-for-one basis;

	•	any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and

	•	our general partner will have the right to convert its general partner interest and its incentive distribution rights into common units or to receive cash in exchange for those interests based on the fair market value of those interests at that time.

In the event of removal of a general partner under circumstances where cause exists or withdrawal of a general partner where that withdrawal violates our partnership agreement, a successor general partner will have the option to purchase the general partner interest and incentive distribution rights of the departing general partner for a cash payment equal to the fair market value of those interests. Under all other circumstances where a general partner withdraws or is removed by the limited partners, the departing general partner will have the option to require the successor general partner to purchase the general partner interest of the departing general partner and its incentive distribution rights for fair market value. In each case, this fair market value will be determined by agreement between the departing general partner and the successor general partner. If no agreement is reached, an independent investment banking firm or other independent expert selected by the departing general partner and the successor general partner will determine the fair market

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value. Or, if the departing general partner and the successor general partner cannot agree upon an expert, then an expert chosen by agreement of the experts selected by each of them will determine the fair market value.

If the option described above is not exercised by either the departing general partner or the successor general partner, the departing general partner’s general partner interest and its incentive distribution rights will automatically convert into common units equal to the fair market value of those interests as determined by an investment banking firm or other independent expert selected in the manner described in the preceding paragraph.

In addition, we will be required to reimburse the departing general partner for all amounts due the departing general partner, including, without limitation, all employee-related liabilities, including severance liabilities, incurred for the termination of any employees employed by the departing general partner or its affiliates for our benefit.

Transfer of General Partner Units

Except for transfer by our general partner of all, but not less than all, of its general partner units to:


	•	an affiliate of our general partner (other than an individual); or

	•	another entity as part of the merger or consolidation of our general partner with or into another entity or the transfer by our general partner of all or substantially all of its assets to another entity,

our general partner may not transfer all or any of its general partner units to another person prior to March 31, 2018 without the approval of the holders of at least a majority of the outstanding common units, excluding common units held by our general partner and its affiliates. As a condition of this transfer, the transferee must assume, among other things, the rights and duties of our general partner, agree to be bound by the provisions of our partnership agreement, and furnish an opinion of counsel regarding limited liability and tax matters.

Our general partner and its affiliates may at any time, transfer units to one or more persons, without unitholder approval, except that they may not transfer subordinated units to us.

Transfer of Ownership Interests in the General Partner

At any time, NiSource and its affiliates may sell or transfer all or part of their membership interest in NiSource GP, LLC, our general partner, to an affiliate or third party without the approval of our unitholders.

Transfer of Incentive Distribution Rights

Our general partner or its affiliates or a subsequent holder may transfer its incentive distribution rights to an affiliate of the holder (other than an individual) or another entity as part of the merger or consolidation of such holder with or into another entity, the sale of all of the ownership interest in the holder or the sale of all or substantially all of its assets to, that entity without the prior approval of the unitholders. Prior to March 31, 2018, other transfers of incentive distribution rights will require the affirmative vote of holders of a majority of the outstanding common units, excluding common units held by our general partner and its affiliates. On or after March 31, 2018, the incentive distribution rights will be freely transferable.

Change of Management Provisions

Our partnership agreement contains specific provisions that are intended to discourage a person or group from attempting to remove NiSource GP, LLC as our general partner or otherwise change our management. If any person or group other than our general partner and its affiliates acquires beneficial ownership of 20% or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply to any person or group that acquires the units from our general partner or its affiliates and any transferees of that person or group approved by our general partner or to any person or group who acquires the units with the prior approval of the board of directors of our general partner.

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Our partnership agreement also provides that if our general partner is removed as our general partner under circumstances where cause does not exist and units held by our general partner and its affiliates are not voted in favor of that removal:


	•	the subordination period will end and all outstanding subordinated units will immediately convert into common units on a one-for-one basis;

	•	any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and

	•	our general partner will have the right to convert its general partner units and its incentive distribution rights into common units or to receive cash in exchange for those interests based on the fair market value of those interests at that time.

Limited Call Right

If at any time our general partner and its affiliates own more than 80% of the then-issued and outstanding limited partner interests of any class, our general partner will have the right, which it may assign in whole or in part to any of its affiliates or to us, to acquire all, but not less than all, of the limited partner interests of the class held by unaffiliated persons as of a record date to be selected by our general partner, on at least 10 but not more than 60 days notice. The purchase price in the event of this purchase is the greater of:


	•	the highest cash price paid by either of our general partner or any of its affiliates for any limited partner interests of the class purchased within the 90 days preceding the date on which our general partner first mails notice of its election to purchase those limited partner interests; and

	•	the current market price as of the date three days before the date the notice is mailed.

As a result of our general partner’s right to purchase outstanding limited partner interests, a holder of limited partner interests may have his limited partner interests purchased at a price that may be lower than market prices at various times prior to such purchase or lower than a unitholder may anticipate the market price to be in the future. The tax consequences to a unitholder of the exercise of this call right are the same as a sale by that unitholder of his common units in the market. Please read “Material Tax Consequences — Disposition of Common Units.”

Non-Taxpaying Assignees; Redemption

To avoid any adverse effect on the maximum applicable rates chargeable to customers by our subsidiaries that are regulated interstate natural gas pipelines, or in order to reverse an adverse determination that has occurred regarding such maximum rate, transferees (including purchasers from the underwriters in this offering) are required to fill out a properly completed transfer application certifying, and our general partner, acting on our behalf, may at any time require each unitholder to re-certify:


	•	that the transferee or unitholder is an individual or an entity subject to United States federal income taxation on the income generated by us; or

	•	that, if the transferee unitholder is an entity not subject to United States federal income taxation on the income generated by us, as in the case, for example, of a mutual fund taxed as a regulated investment company or a partnership, all the entity’s owners are subject to United States federal income taxation on the income generated by us.

This certification can be changed in any manner our general partner determines is necessary or appropriate to implement its original purpose.

If a unitholder fails to furnish:


	•	a transfer application containing the required certification;

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	•	a re-certification containing the required certification within 30 days after request; or

	•	provides a false certification; then

we will have the right, which we may assign to any of our affiliates, to acquire all but not less than all of the units held by such unitholder. Further, the units will not be entitled to any allocations of income or loss, distributions or voting rights while held by such unitholder.

The purchase price in the event of such an acquisition for each unit held by such unitholder will be the lesser of:

(1) the price paid by such unitholder for the relevant unit; and

(2) the current market price as of the date three days before the date the notice is mailed.

The purchase price will be paid in cash or by delivery of a promissory note, as determined by our general partner. Any such promissory note will bear interest at the rate of 5% annually and be payable in three equal annual installments of principal and accrued interest, commencing one year after the redemption date.

Meetings; Voting

Except as described below regarding a person or group owning 20% or more of any class of units then outstanding, record holders of units on the record date will be entitled to notice of, and to vote at, meetings of our limited partners and to act upon matters for which approvals may be solicited.

Our general partner does not anticipate that any meeting of unitholders will be called in the foreseeable future. Any action that is required or permitted to be taken by the unitholders may be taken either at a meeting of the unitholders or without a meeting if consents in writing describing the action so taken are signed by holders of the number of units necessary to authorize or take that action at a meeting. Meetings of the unitholders may be called by our general partner or by unitholders owning at least 20% of the outstanding units of the class for which a meeting is proposed. Unitholders may vote either in person or by proxy at meetings. The holders of a majority of the outstanding units of the class or classes for which a meeting has been called represented in person or by proxy will constitute a quorum unless any action by the unitholders requires approval by holders of a greater percentage of the units, in which case the quorum will be the greater percentage.

Each record holder of a unit has a vote according to his percentage interest in us, although additional limited partner interests having special voting rights could be issued. Please read “— Issuance of Additional Securities.” However, if at any time any person or group acquires, in the aggregate, beneficial ownership of 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, that person or group will lose voting rights on all of its units and the units may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes, determining the presence of a quorum or for other similar purposes. Common units held in nominee or street name account will be voted by the broker or other nominee in accordance with the instruction of the beneficial owner unless the arrangement between the beneficial owner and his nominee provides otherwise. Except as our partnership agreement otherwise provides, subordinated units will vote together with common units and Class B units as a single class.

Any notice, demand, request, report or proxy material required or permitted to be given or made to record holders of common units under our partnership agreement will be delivered to the record holder by us or by the transfer agent.

Status as Limited Partner

By transfer of common units in accordance with our partnership agreement, each transferee of common units shall be admitted as a limited partner with respect to the common units transferred when such transfer and admission is reflected in our books and records. Except as described under “— Limited Liability,” the common units will be fully paid, and unitholders will not be required to make additional contributions.

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Non-Citizen Assignees; Redemption

If we are or become subject to federal, state or local laws or regulations that, in the reasonable determination of our general partner, create a substantial risk of cancellation or forfeiture of any property that we have an interest in because of the nationality, citizenship or other related status of any limited partner, we may redeem the units held by the limited partner at their current market price on the redemption date. In order to avoid any cancellation or forfeiture, our general partner may require each limited partner to furnish information about his nationality, citizenship or related status. If a limited partner fails to furnish information about his nationality, citizenship or other related status within 30 days after a request for the information or our general partner determines after receipt of the information that the limited partner is not an eligible citizen, the limited partner may be treated as a non-citizen assignee. A non-citizen assignee is entitled to an interest equivalent to that of a limited partner for the right to share in allocations and distributions from us, including liquidating distributions. A non-citizen assignee does not have the right to direct the voting of his units and may not receive distributions in-kind upon our liquidation.

Indemnification

Under our partnership agreement, in most circumstances, we will indemnify the following persons, to the fullest extent permitted by law, from and against all losses, claims, damages or similar events:


	•	our general partner;

	•	any departing general partner;

	•	any person who is or was an affiliate of a general partner or any departing general partner;

	•	any person who is or was a director, officer, member, partner, fiduciary or trustee of any entity set forth in the preceding three bullet points;

	•	any person who is or was serving as director, officer, member, partner, fiduciary or trustee of another person at the request of our general partner or any departing general partner; and

	•	any person designated by our general partner.

Any indemnification under these provisions will only be out of our assets. Unless it otherwise agrees, our general partner will not be personally liable for, or have any obligation to contribute or lend funds or assets to us to enable us to effectuate, indemnification. We may purchase insurance against liabilities asserted against and expenses incurred by persons for our activities, regardless of whether we would have the power to indemnify the person against liabilities under our partnership agreement.

Reimbursement of Expenses

Our partnership agreement requires us to reimburse our general partner for all direct and indirect expenses it incurs or payments it makes on our behalf and all other expenses allocable to us or otherwise incurred by our general partner in connection with operating our business. 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. The general partner is entitled to determine in good faith the expenses that are allocable to us.

Books and Reports

Our general partner is required to keep appropriate books of our business at our principal offices. The books will be maintained for both tax and financial reporting purposes on an accrual basis. For tax and fiscal reporting purposes, our fiscal year is the calendar year.

We will furnish or make available to record holders of common units, within 120 days after the close of each fiscal year, an annual report containing audited financial statements and a report on those financial statements by our independent public accountants. Except for our fourth quarter, we will also furnish or make available summary financial information within 90 days after the close of each quarter.

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We will furnish each record holder of a unit with information reasonably required for tax reporting purposes within 90 days after the close of each calendar year. This information is expected to be furnished in summary form so that some complex calculations normally required of partners can be avoided. Our ability to furnish this summary information to unitholders will depend on the cooperation of unitholders in supplying us with specific information. Every unitholder will receive information to assist him in determining his federal and state tax liability and filing his federal and state income tax returns, regardless of whether he supplies us with information.

Right to Inspect Our Books and Records

Our partnership agreement provides that a limited partner can, for a purpose reasonably related to his interest as a limited partner, upon reasonable written demand stating the purpose of such demand and at his own expense, have furnished to him:


	•	a current list of the name and last known address of each partner;

	•	a copy of our tax returns;

	•	information as to the amount of cash, and a description and statement of the agreed value of any other property or services, contributed or to be contributed by each partner and the date on which each partner became a partner;

	•	copies of our partnership agreement, our certificate of limited partnership, related amendments and powers of attorney under which they have been executed;

	•	information regarding the status of our business and financial condition; and

	•	any other information regarding our affairs as is just and reasonable.

Our general partner may, and intends to, keep confidential from the limited partners, trade secrets or other information the disclosure of which our general partner believes in good faith is not in our best interests or that we are required by law or by agreements with third parties to keep confidential.

Registration Rights

Under our partnership agreement, we have agreed to register for resale under the Securities Act and applicable state securities laws any common units, subordinated units or other partnership securities proposed to be sold by our general partner or any of its affiliates or their assignees if an exemption from the registration requirements is not otherwise available. These registration rights continue for two years following any withdrawal or removal of NiSource GP, LLC as general partner. We are obligated to pay all expenses incidental to the registration, excluding underwriting discounts and commissions. Please read “Units Eligible for Future Sale.”

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UNITS ELIGIBLE FOR FUTURE SALE

After the sale of the common units offered hereby and assuming that the underwriters do not exercise their option to purchase additional units, management of our general partner and NiSource and its affiliates will hold an aggregate of 8,584,349 common units and 10,222,715 subordinated units. The sale of these units could have an adverse impact on the price of the common units or on any trading market that may develop.

The common units sold in the offering will generally be freely transferable without restriction or further registration under the Securities Act, except that any common units owned by an “affiliate” of ours may not be resold publicly except in compliance with the registration requirements of the Securities Act or under an exemption under Rule 144 or otherwise. Rule 144 permits securities acquired by an affiliate of the issuer to be sold into the market in an amount that does not exceed, during any three-month period, the greater of:


	•	1% of the total number of the securities outstanding; or

	•	the average weekly reported trading volume of the common units for the four calendar weeks prior to the sale.

Sales under Rule 144 are also subject to specific manner of sale provisions, holding period requirements, notice requirements and the availability of current public information about us. A person who is not deemed to have been an affiliate of ours at any time during the three months preceding a sale, and who has beneficially owned his common units for at least two years, would be entitled to sell common units under Rule 144 without regard to the public information requirements, volume limitations, manner of sale provisions and notice requirements of Rule 144.

The partnership agreement does not restrict our ability to issue any partnership securities at any time. Any issuance of additional common units or other equity securities would result in a corresponding decrease in the proportionate ownership interest in us represented by, and could adversely affect the cash distributions to and market price of, common units then outstanding. Please read “The Partnership Agreement — Issuance of Additional Securities.”

Under our partnership agreement, our general partner and its affiliates have the right to cause us to register under the Securities Act and state securities laws the offer and sale of any common units, subordinated units or other partnership securities that they hold. Subject to the terms and conditions of our partnership agreement, these registration rights allow our general partner and its affiliates or their assignees holding any units or other partnership securities to require registration of any of these units or other partnership securities and to include them in a registration by us of other units, including units offered by us or by any unitholder. Our general partner will continue to have these registration rights for two years following its withdrawal or removal as our general partner. In connection with any registration of this kind, we will indemnify each unitholder participating in the registration and its officers, directors and controlling persons from and against any liabilities under the Securities Act or any state securities laws arising from the registration statement or prospectus. We will bear all costs and expenses incidental to any registration, excluding any underwriting discounts and a structuring fee. Except as described below, our general partner and its affiliates may sell their units or other partnership interests in private transactions at any time, subject to compliance with applicable laws.

NiSource, our partnership, our operating company, our general partner and the directors and executive officers of our general partner, have agreed not to sell any common units they beneficially own for a period of 180 days from the date of this prospectus. For a description of these lock-up provisions, please read “Underwriting.”

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MATERIAL TAX CONSEQUENCES

This section is a summary of the material tax considerations that may be relevant to prospective unitholders who are individual citizens or residents of the United States and, unless otherwise noted in the following discussion, is the opinion of Vinson & Elkins L.L.P., counsel to our general partner and us, insofar as it relates to legal conclusions with respect to matters of United States federal income tax law. This section is based upon current provisions of the Internal Revenue Code, existing and proposed regulations and current administrative rulings and court decisions, all of which are subject to change. Later changes in these authorities may cause the tax consequences to vary substantially from the consequences described below. Unless the context otherwise requires, references in this section to “us” or “we” are references to NiSource Energy Partners, L.P. and our operating company.

The following discussion does not comment on all federal income tax matters affecting us or our unitholders. Moreover, the discussion focuses on unitholders who are individual citizens or residents of the United States and has only limited application to corporations, estates, trusts, nonresident aliens or other unitholders subject to specialized tax treatment, such as tax-exempt institutions, foreign persons, individual retirement accounts (IRAs), real estate investment trusts (REITs) or mutual funds. Accordingly, we encourage each prospective unitholder to consult, and depend on, his own tax advisor in analyzing the federal, state, local and foreign tax consequences particular to him of the ownership or disposition of common units.

All statements as to matters of law and legal conclusions, but not as to factual matters, contained in this section, unless otherwise noted, are the opinion of Vinson & Elkins L.L.P. and are based on the accuracy of the representations made by us.

No ruling has been or will be requested from the IRS regarding any matter affecting us or prospective unitholders. Instead, we will rely on opinions of Vinson & Elkins L.L.P. Unlike a ruling, an opinion of counsel represents only that counsel’s best legal judgment and does not bind the IRS or the courts. Accordingly, the opinions and statements made herein may not be sustained by a court if contested by the IRS. Any contest of this sort with the IRS may materially and adversely impact the market for the common units and the prices at which common units trade. In addition, the costs of any contest with the IRS, principally legal, accounting and related fees, will result in a reduction in cash available for distribution to our unitholders and our general partner and thus will be borne indirectly by our unitholders and our general partner. Furthermore, the tax treatment of us, or of an investment in us, may be significantly modified by future legislative or administrative changes or court decisions. Any modifications may or may not be retroactively applied.

For the reasons described below, Vinson & Elkins L.L.P. has not rendered an opinion with respect to the following specific federal income tax issues: (1) the treatment of a unitholder whose common units are loaned to a short seller to cover a short sale of common units (please read “— Tax Consequences of Unit Ownership — Treatment of Short Sales”); (2) whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations (please read “— Disposition of Common Units — Allocations Between Transferors and Transferees”); and (3) whether our method for depreciating Section 743 adjustments is sustainable in certain cases (please read “— Tax Consequences of Unit Ownership — Section 754 Election”).

Partnership Status

A partnership is not a taxable entity and incurs no federal income tax liability. Instead, each partner of a partnership is required to take into account his share of items of income, gain, loss and deduction of the partnership in computing his federal income tax liability, regardless of whether cash distributions are made to him by the partnership. Distributions by a partnership to a partner are generally not taxable unless the amount of cash distributed is in excess of the partner’s adjusted basis in his partnership interest.

Section 7704 of the Internal Revenue Code provides that publicly traded partnerships will, as a general rule, be taxed as corporations. However, an exception, referred to as the “Qualifying Income Exception,” exists with respect to publicly traded partnerships of which 90% or more of the gross income for every taxable year consists of “qualifying income.” Qualifying income includes income and gains derived from the transportation,

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storage and processing of crude oil, natural gas and products thereof. Other types of qualifying income include interest (other than from a financial business), dividends, gains from the sale of real property and gains from the sale or other disposition of capital assets held for the production of income that otherwise constitutes qualifying income. We estimate that less than % of our current gross income is not qualifying income; however, this estimate could change from time to time. Based upon and subject to this estimate, the factual representations made by us and our general partner and a review of the applicable legal authorities, Vinson & Elkins L.L.P. is of the opinion that at least 90% of our current gross income constitutes qualifying income.

No ruling has been or will be sought from the IRS and the IRS has made no determination as to our status for federal income tax purposes or whether our operations generate “qualifying income” under Section 7704 of the Internal Revenue Code. Instead, we will rely on the opinion of Vinson & Elkins L.L.P. on such matters. It is the opinion of Vinson & Elkins L.L.P. that, based upon the Internal Revenue Code, its regulations, published revenue rulings and court decisions and the representations described below, we will be classified as a partnership and our operating company will be disregarded as an entity separate from us for federal income tax purposes.

In rendering its opinion, Vinson & Elkins L.L.P. has relied on factual representations made by us and our general partner. The representations made by us and our general partner upon which Vinson & Elkins L.L.P. has relied are:

(a) Neither we nor the operating company has elected or will elect to be treated as a corporation; and

(b) For each taxable year, more than 90% of our gross income has been and will be income that Vinson & Elkins L.L.P. has opined or will opine is “qualifying income” within the meaning of Section 7704(d) of the Internal Revenue Code.

If we fail to meet the Qualifying Income Exception, other than a failure that is determined by the IRS to be inadvertent and that is cured within a reasonable time after discovery (in which case the IRS may also require us to make adjustments with respect to our unitholders or pay other amounts), we will be treated as if we had transferred all of our assets, subject to liabilities, to a newly formed corporation, on the first day of the year in which we fail to meet the Qualifying Income Exception, in return for stock in that corporation, and then distributed that stock to the unitholders in liquidation of their interests in us. This deemed contribution and liquidation should be tax-free to unitholders and us so long as we, at that time, do not have liabilities in excess of the tax basis of our assets. Thereafter, we would be treated as a corporation for federal income tax purposes.

If we were treated as an association taxable as a corporation in any taxable year, either as a result of a failure to meet the Qualifying Income Exception or otherwise, our items of income, gain, loss and deduction would be reflected only on our tax return rather than being passed through to our unitholders, and our net income would be taxed to us at corporate rates. In addition, any distribution made to a unitholder would be treated as either taxable dividend income, to the extent of our current or accumulated earnings and profits, or, in the absence of earnings and profits, a nontaxable return of capital, to the extent of the unitholder’s tax basis in his common units, or taxable capital gain, after the unitholder’s tax basis in his common units is reduced to zero. Accordingly, taxation as a corporation would result in a material reduction in a unitholder’s cash flow and after-tax return and thus would likely result in a substantial reduction of the value of the units.

The discussion below is based on Vinson & Elkins L.L.P.’s opinion that we will be classified as a partnership for federal income tax purposes.

Limited Partner Status

Unitholders who have become limited partners of NiSource Energy Partners, L.P. will be treated as partners of NiSource Energy Partners, L.P. for federal income tax purposes. Also unitholders whose common units are held in street name or by a nominee and who have the right to direct the nominee in the exercise of all substantive rights attendant to the ownership of their common units will be treated as partners of NiSource Energy Partners, L.P. for federal income tax purposes.

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A beneficial owner of common units whose units have been transferred to a short seller to complete a short sale would appear to lose his status as a partner with respect to those units for federal income tax purposes. Please read “— Tax Consequences of Unit Ownership — Treatment of Short Sales.”

Income, gain, deductions or losses would not appear to be reportable by a unitholder who is not a partner for federal income tax purposes, and any cash distributions received by a unitholder who is not a partner for federal income tax purposes would therefore appear to be fully taxable as ordinary income. These holders are urged to consult their own tax advisors with respect to their tax consequences of holding common units in NiSource Energy Partners, L.P.

Tax Consequences of Unit Ownership

Flow-Through of Taxable Income. We will not pay any federal income tax. Instead, each unitholder will be required to report on his income tax return his share of our income, gains, losses and deductions without regard to whether we make cash distributions to him. Consequently, we may allocate income to a unitholder even if he has not received a cash distribution. Each unitholder will be required to include in income his allocable share of our income, gains, losses and deductions for our taxable year ending with or within his taxable year. Our taxable year ends on December 31.

Treatment of Distributions. Distributions by us to a unitholder generally will not be taxable to the unitholder for federal income tax purposes, except to the extent the amount of any such cash distribution exceeds his tax basis in his common units immediately before the distribution. Our cash distributions in excess of a unitholder’s tax basis generally will be considered to be gain from the sale or exchange of the common units, taxable in accordance with the rules described under “— Disposition of Common Units” below. Any reduction in a unitholder’s share of our liabilities for which no partner, including the general partner, bears the economic risk of loss, known as “nonrecourse liabilities,” will be treated as a distribution of cash to that unitholder. To the extent our distributions cause a unitholder’s “at-risk” amount to be less than zero at the end of any taxable year, he must recapture any losses deducted in previous years. Please read “— Limitations on Deductibility of Losses.”

A decrease in a unitholder’s percentage interest in us because of our issuance of additional common units will decrease his share of our nonrecourse liabilities, and thus will result in a corresponding deemed distribution of cash. A non-pro rata distribution of money or property may result in ordinary income to a unitholder, regardless of his tax basis in his common units, if the distribution reduces the unitholder’s share of our “unrealized receivables,” including depreciation recapture, and/or substantially appreciated “inventory items,” both as defined in the Internal Revenue Code, and collectively, “Section 751 Assets.” To that extent, he will be treated as having been distributed his proportionate share of the Section 751 Assets and then having exchanged those assets with us in return for the non-pro rata portion of the actual distribution made to him. This latter deemed exchange will generally result in the unitholder’s realization of ordinary income, which will equal the excess of (1) the non-pro rata portion of that distribution over (2) the unitholder’s tax basis (generally zero) for the share of Section 751 Assets deemed relinquished in the exchange.

Ratio of Taxable Income to Distributions. We estimate that a purchaser of common units in this offering who owns those common units from the date of closing of this offering through the record date for distributions for the period ending December 31, 2010, will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be % or less of the cash distributed with respect to that period. Thereafter, we anticipate that the ratio of allocable taxable income to cash distributions to the unitholders will increase. These estimates are based upon the assumption that gross income from operations will approximate the amount required to make the minimum quarterly distribution on all units and other assumptions with respect to capital expenditures, cash flow, net working capital and anticipated cash distributions. These estimates and assumptions are subject to, among other things, numerous business, economic, regulatory, competitive and political uncertainties beyond our control. Further, the estimates are based on current tax law and tax reporting positions that we will adopt and with which the IRS could disagree. Accordingly, we cannot assure you that these estimates will prove to be correct. The actual percentage of distributions that will constitute taxable income could be higher or lower than expected, and any differences

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could be material and could materially affect the value of the common units. For example, the ratio of allocable taxable income to cash distributions to a purchaser of common units in this offering will be greater, and perhaps substantially greater, than our estimate with respect to the period described above if:


	•	gross income from operations exceeds the amount required to make minimum quarterly distributions on all units, yet we only distribute the minimum quarterly distributions on all units; or

	•	we make a future offering of common units and use the proceeds of the offering in a manner that does not produce substantial additional deductions during the period described above, such as to repay indebtedness outstanding at the time of this offering or to acquire property that is not eligible for depreciation or amortization for federal income tax purposes or that is depreciable or amortizable at a rate significantly slower than the rate applicable to our assets at the time of this offering.

Basis of Common Units. A unitholder’s initial tax basis for his common units will be the amount he paid for the common units plus his share of our nonrecourse liabilities. That basis will be increased by his share of our income and by any increases in his share of our nonrecourse liabilities. That basis will be decreased, but not below zero, by distributions from us, by the unitholder’s share of our losses, by any decreases in his share of our nonrecourse liabilities and by his share of our expenditures that are not deductible in computing taxable income and are not required to be capitalized. A unitholder will have no share of our debt that is recourse to our general partner, but will have a share, generally based on his share of profits, of our nonrecourse liabilities. Please read “— Disposition of Common Units — Recognition of Gain or Loss.”

Limitations on Deductibility of Losses. The deduction by a unitholder of his share of our losses will be limited to the tax basis in his units and, in the case of an individual unitholder, estate, trust, or corporate unitholder (if more than 50% of the value of the corporate unitholder’s stock is owned directly or indirectly by or for five or fewer individuals) or some tax-exempt organizations, to the amount for which the unitholder is considered to be “at risk” with respect to our activities, if that is less than his tax basis. A common unitholder subject to these limitations must recapture losses deducted in previous years to the extent that distributions cause his at-risk amount to be less than zero at the end of any taxable year. Losses disallowed to a unitholder or recaptured as a result of these limitations will carry forward and will be allowable as a deduction to the extent that his tax basis or at-risk amount, whichever is the limiting factor, is subsequently increased. Upon the taxable disposition of a unit, any gain recognized by a unitholder can be offset by losses that were previously suspended by the at-risk limitation but may not be offset by losses suspended by the basis limitation. Any loss previously suspended by the at-risk limitation in excess of that gain would no longer be utilizable.

In general, a unitholder will be at risk to the extent of the tax basis of his units, excluding any portion of that basis attributable to his share of our nonrecourse liabilities, reduced by (i) any portion of that basis representing amounts otherwise protected against loss because of a guarantee, stop loss agreement or other similar arrangement and (ii) any amount of money he borrows to acquire or hold his units, if the lender of those borrowed funds owns an interest in us, is related to the unitholder or can look only to the units for repayment. A unitholder’s at-risk amount will increase or decrease as the tax basis of the unitholder’s units increases or decreases, other than tax basis increases or decreases attributable to increases or decreases in his share of our nonrecourse liabilities.

In addition to the basis and at-risk limitations on the deductibility of losses, the passive loss limitations generally provide that individuals, estates, trusts and some closely-held corporations and personal service corporations can deduct losses from passive activities, which are generally trade or business activities in which the taxpayer does not materially participate, only to the extent of the taxpayer’s income from those passive activities. The passive loss limitations are applied separately with respect to each publicly traded partnership. Consequently, any passive losses we generate will only be available to offset our passive income generated in the future and will not be available to offset income from other passive activities or investments, including our investments or investments in other publicly traded partnerships, or salary or active business income. Passive losses that are not deductible because they exceed a unitholder’s share of income we generate may be deducted in full when he disposes of his entire investment in us in a fully taxable transaction with an unrelated party. The passive loss limitations are applied after other applicable limitations on deductions, including the at-risk rules and the basis limitation.

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A unitholder’s share of our net income may be offset by any of our suspended passive losses, but it may not be offset by any other current or carryover losses from other passive activities, including those attributable to other publicly traded partnerships.

Limitations on Interest Deductions. The deductibility of a non-corporate taxpayer’s “investment interest expense” is generally limited to the amount of that taxpayer’s “net investment income.” Investment interest expense includes:


	•	interest on indebtedness properly allocable to property held for investment;

	•	our interest expense attributed to portfolio income; and

	•	the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent attributable to portfolio income.

The computation of a unitholder’s investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a unit. Net investment income includes gross income from property held for investment and amounts treated as portfolio income under the passive loss rules, less deductible expenses, other than interest, directly connected with the production of investment income, but generally does not include gains attributable to the disposition of property held for investment. The IRS has indicated that the net passive income earned by a publicly traded partnership will be treated as investment income to its unitholders. In addition, the unitholder’s share of our portfolio income will be treated as investment income.

Entity-Level Collections. If we are required or elect under applicable law to pay any federal, state, local or foreign income tax on behalf of any unitholder or our general partner or any former unitholder, we are authorized to pay those taxes from our funds. That payment, if made, will be treated as a distribution of cash to the unitholder on whose behalf the payment was made. If the payment is made on behalf of a person whose identity cannot be determined, we are authorized to treat the payment as a distribution to all current unitholders. We are authorized to amend our partnership agreement in the manner necessary to maintain uniformity of intrinsic tax characteristics of units and to adjust later distributions, so that after giving effect to these distributions, the priority and characterization of distributions otherwise applicable under our partnership agreement is maintained as nearly as is practicable. Payments by us as described above could give rise to an overpayment of tax on behalf of an individual unitholder in which event the unitholder would be required to file a claim in order to obtain a credit or refund.

Allocation of Income, Gain, Loss and Deduction. In general, if we have a net profit, our items of income, gain, loss and deduction will be allocated among our general partner and the unitholders in accordance with their percentage interests in us. At any time that distributions are made to the common units in excess of distributions to the subordinated units, or incentive distributions are made to our general partner, gross income will be allocated to the recipients to the extent of these distributions. If we have a net loss, that loss will be allocated first to our general partner and the unitholders in accordance with their percentage interests in us to the extent of their positive capital accounts and, second, to our general partner.

Specified items of our income, gain, loss and deduction will be allocated to account for the difference between the tax basis and fair market value of property contributed to us by our general partner and its affiliates, referred to in this discussion as “Contributed Property.” The effect of these allocations, referred to as Section 704(c) Allocations, to a unitholder purchasing common units from us in this offering will be essentially the same as if the tax basis of our assets were equal to their fair market value at the time of such offering. In the event we issue additional common units or engage in certain other transactions in the future “reverse Section 704(c) Allocations,” similar to the Section 704(c) Allocations described above, will be made to all holders of partnership interests, including purchasers of common units in this offering, to account for the difference between the “book” basis for purposes of maintaining capital accounts and the fair market value of all property held by us at the time of the future transaction. In addition, items of recapture income will be allocated to the extent possible to the unitholder who was allocated the deduction giving rise to the treatment of that gain as recapture income in order to minimize the recognition of ordinary income by some unitholders. Finally, although we do not expect that our operations will result in the creation of negative capital accounts, if

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negative capital accounts nevertheless result, items of our income and gain will be allocated in such amount and manner as is needed to eliminate the negative balance as quickly as possible.

An allocation of items of our income, gain, loss or deduction, other than an allocation required by the Internal Revenue Code to eliminate the difference between a partner’s “book” capital account, credited with the fair market value of Contributed Property, and “tax” capital account, credited with the tax basis of Contributed Property, referred to in this discussion as the “Book-Tax Disparity,” will generally be given effect for federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction only if the allocation has substantial economic effect. In any other case, a partner’s share of an item will be determined on the basis of his interest in us, which will be determined by taking into account all the facts and circumstances, including:


	•	his relative contributions to us;

	•	the interests of all the partners in profits and losses;

	•	the interest of all the partners in cash flow; and

	•	the rights of all the partners to distributions of capital upon liquidation.

Vinson & Elkins L.L.P. is of the opinion that, with the exception of the issues described in “— Section 754 Election” and “— Disposition of Common Units — Allocations Between Transferors and Transferees,” allocations under our partnership agreement will be given effect for federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction.

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


	•	any of our income, gain, loss or deduction with respect to those units would not be reportable by the unitholder;

	•	any cash distributions received by the unitholder as to those units would be fully taxable; and

	•	all of these distributions would appear to be ordinary income.

Vinson & Elkins L.L.P. has not rendered an opinion regarding the treatment of a unitholder where common units are loaned to a short seller to cover a short sale of common units; therefore, unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from loaning their units. The IRS has announced that it is actively studying issues relating to the tax treatment of short sales of partnership interests. Please also read “— Disposition of Common Units — Recognition of Gain or Loss.”

Alternative Minimum Tax. Each unitholder will be required to take into account his distributive share of any items of our income, gain, loss or deduction for purposes of the alternative minimum tax. The current minimum tax rate for noncorporate taxpayers is 26% on the first $175,000 of alternative minimum taxable income in excess of the exemption amount and 28% on any additional alternative minimum taxable income. Prospective unitholders are urged to consult with their tax advisors as to the impact of an investment in units on their liability for the alternative minimum tax.

Tax Rates. In general, the highest effective United States federal income tax rate for individuals is currently 35%, and the maximum United States federal income tax rate for net capital gains of an individual where the asset disposed of was held for more than twelve months at the time of disposition is currently 15%, and is scheduled to remain at 15% for years 2008 through 2010 and then increase to 20% beginning January 1, 2011.

Section 754 Election. We will make the election permitted by Section 754 of the Internal Revenue Code. That election is irrevocable without the consent of the IRS. The election will generally permit us to adjust a common unit purchaser’s tax basis in our assets (“inside basis”) under Section 743(b) of the Internal

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Revenue Code to reflect his purchase price. This election does not apply to a person who purchases common units directly from us. The Section 743(b) adjustment belongs to the purchaser and not to other unitholders. For purposes of this discussion, a unitholder’s inside basis in our assets will be considered to have two components: (1) his share of our tax basis in our assets (“common basis”) and (2) his Section 743(b) adjustment to that basis.

Where the remedial allocation method is adopted (which we will adopt as to all our properties), the Treasury Regulations under Section 743 of the Internal Revenue Code require a portion of the Section 743(b) adjustment that is attributable to recovery property under Section 168 of the Internal Revenue Code whose book basis is in excess of its tax basis to be depreciated over the remaining cost recovery period for the property’s unamortized book-tax disparity. Under Treasury Regulation Section 1.167(c)-1(a)(6), a Section 743(b) adjustment attributable to property subject to depreciation under Section 167 of the Internal Revenue Code, rather than cost recovery deductions under Section 168, is generally required to be depreciated using either the straight-line method or the 150% declining balance method. Under our partnership agreement, our general partner is authorized to take a position to preserve the uniformity of units even if that position is not consistent with these and any other Treasury Regulations. Please read “— Uniformity of Units.”

Although Vinson & Elkins L.L.P. is unable to opine as to the validity of this approach because there is no direct or indirect controlling authority on this issue, we intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized Book-Tax Disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the property’s unamortized book-tax disparity, or treat that portion as non-amortizable to the extent attributable to property which is not amortizable. This method is consistent with the methods employed by other publicly traded partnerships but is arguably inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets. To the extent this Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized Book-Tax Disparity, we will apply the rules described in the Treasury Regulations and legislative history. If we determine that this position cannot reasonably be taken, we may take a depreciation or amortization position under which all purchasers acquiring units in the same month would receive depreciation or amortization, whether attributable to common basis or a Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our assets. This kind of aggregate approach may result in lower annual depreciation or amortization deductions than would otherwise be allowable to some unitholders. Please read “— Uniformity of Units.” A unitholder’s tax basis for his common units is reduced by his share of our deductions (whether or not such deductions were claimed on an individual’s income tax return) so that any position we take that understates deductions will overstate the common unitholder’s basis in his common units, which may cause the unitholder to understate gain or overstate loss on any sale of such units. Please read “— Disposition of Common Units — Recognition of Gain or Loss.” The IRS may challenge our position with respect to depreciating or amortizing the Section 743(b) adjustment we take to preserve the uniformity of the units. If such a challenge were sustained, the gain from the sale of units might be increased without the benefit of additional deductions.

A Section 754 election is advantageous if the transferee’s tax basis in his units is higher than the units’ share of the aggregate tax basis of our assets immediately prior to the transfer. In that case, as a result of the election, the transferee would have, among other items, a greater amount of depreciation and depletion deductions and his share of any gain or loss on a sale of our assets would be less. Conversely, a Section 754 election is disadvantageous if the transferee’s tax basis in his units is lower than those units’ share of the aggregate tax basis of our assets immediately prior to the transfer. Thus, the fair market value of the units may be affected either favorably or unfavorably by the election. A basis adjustment is required regardless of whether a Section 754 election is made in the case of a transfer of an interest in us if we have a substantial built-in loss immediately after the transfer, or if we distribute property and have a substantial basis reduction. Generally a built-in loss or a basis reduction is substantial if it exceeds $250,000.

The calculations involved in the Section 754 election are complex and will be made on the basis of assumptions as to the value of our assets and other matters. For example, the allocation of the Section 743(b) adjustment among our assets must be made in accordance with the Internal Revenue Code. The IRS could

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seek to reallocate some or all of any Section 743(b) adjustment allocated by us to our tangible assets to goodwill instead. Goodwill, as an intangible asset, is generally nonamortizable or amortizable over a longer period of time or under a less accelerated method than our tangible assets. We cannot assure you that the determinations we make will not be successfully challenged by the IRS and that the deductions resulting from them will not be reduced or disallowed altogether. Should the IRS require a different basis adjustment to be made, and should, in our opinion, the expense of compliance exceed the benefit of the election, we may seek permission from the IRS to revoke our Section 754 election. If permission is granted, a subsequent purchaser of units may be allocated more income than he would have been allocated had the election not been revoked.

Tax Treatment of Operations

Accounting Method and Taxable Year. We use the year ending December 31 as our taxable year and the accrual method of accounting for federal income tax purposes. Each unitholder will be required to include in income his share of our income, gain, loss and deduction for our taxable year ending within or with his taxable year. In addition, a unitholder who has a taxable year ending on a date other than December 31 and who disposes of all of his units following the close of our taxable year but before the close of his taxable year must include his share of our income, gain, loss and deduction in income for his taxable year, with the result that he will be required to include in income for his taxable year his share of more than one year of our income, gain, loss and deduction. Please read “— Disposition of Common Units — Allocations Between Transferors and Transferees.”

Initial Tax Basis, Depreciation and Amortization. The tax basis of our assets will be used for purposes of computing depreciation and cost recovery deductions and, ultimately, gain or loss on the disposition of these assets. The federal income tax burden associated with the difference between the fair market value of our assets and their tax basis immediately prior to this offering will be borne by our general partner. Please read “— Tax Consequences of Unit Ownership — Allocation of Income, Gain, Loss and Deduction.”

To the extent allowable, we may elect to use the depreciation and cost recovery methods that will result in the largest deductions being taken in the early years after assets subject to these allowances are placed in service. Because our general partner may determine not to adopt the remedial method of allocation with respect to any difference between the tax basis and the fair market value of goodwill immediately prior to this or any future offering, we may not be entitled to any amortization deductions with respect to any goodwill properties conveyed to us on formation or held by us at the time of any future offering. Please read “— Uniformity of Units.” Property we subsequently acquire or construct may be depreciated using accelerated methods permitted by the Internal Revenue Code.

If we dispose of depreciable property by sale, foreclosure or otherwise, all or a portion of any gain, determined by reference to the amount of depreciation previously deducted and the nature of the property, may be subject to the recapture rules and taxed as ordinary income rather than capital gain. Similarly, a unitholder who has taken cost recovery or depreciation deductions with respect to property we own will likely be required to recapture some or all of those deductions as ordinary income upon a sale of his interest in us. Please read “— Tax Consequences of Unit Ownership — Allocation of Income, Gain, Loss and Deduction” and “— Disposition of Common Units — Recognition of Gain or Loss.”

The costs incurred in selling our units (called “syndication expenses”) must be capitalized and cannot be deducted currently, ratably or upon our termination. There are uncertainties regarding the classification of costs as organization expenses, which may be amortized by us, and as syndication expenses, which may not be amortized by us. The underwriting discounts and commissions we incur will be treated as syndication expenses.

Valuation and Tax Basis of Our Properties. The federal income tax consequences of the ownership and disposition of units will depend in part on our estimates of the relative fair market values, and the initial tax bases, of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we will make many of the relative fair market value estimates ourselves. These estimates and determinations of basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or basis are later found to be incorrect, the character and amount of items of

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income, gain, loss or deductions previously reported by unitholders might change, and unitholders might be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.

Disposition of Common Units

Recognition of Gain or Loss. Gain or loss will be recognized on a sale of units equal to the difference between the amount realized and the unitholder’s tax basis for the units sold. A unitholder’s amount realized will be measured by the sum of the cash or the fair market value of other property received by him plus his share of our nonrecourse liabilities. Because the amount realized includes a unitholder’s share of our nonrecourse liabilities, the gain recognized on the sale of units could result in a tax liability in excess of any cash received from the sale.

Prior distributions from us in excess of cumulative net taxable income for a common unit that decreased a unitholder’s tax basis in that common unit will, in effect, become taxable income if the common unit is sold at a price greater than the unitholder’s tax basis in that common unit, even if the price received is less than his original cost.

Except as noted below, gain or loss recognized by a unitholder, other than a “dealer” in units, on the sale or exchange of a unit held for more than one year will generally be taxable as capital gain or loss. Capital gain recognized by an individual on the sale of units held more than twelve months will generally be taxed at a maximum rate of 15%. However, a portion of this gain or loss, which will likely be substantial, will be separately computed and taxed as ordinary income or loss under Section 751 of the Internal Revenue Code to the extent attributable to assets giving rise to depreciation recapture or other “unrealized receivables” or to “inventory items” we own. The term “unrealized receivables” includes potential recapture items, including depreciation recapture. Ordinary income attributable to unrealized receivables, inventory items and depreciation recapture may exceed net taxable gain realized upon the sale of a unit and may be recognized even if there is a net taxable loss realized on the sale of a unit. Thus, a unitholder may recognize both ordinary income and a capital loss upon a sale of units. Net capital losses may offset capital gains and no more than $3,000 of ordinary income, in the case of individuals, and may only be used to offset capital gains in the case of corporations.

The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all those interests. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests sold using an “equitable apportionment” method, which generally means that the tax basis allocated to the interest sold equals an amount that bears the same relation to the partner’s tax basis in his entire interest in the partnership as the value of the interest sold bears to the value of the partner’s entire interest in the partnership. Treasury Regulations under Section 1223 of the Internal Revenue Code allow a selling unitholder who can identify common units transferred with an ascertainable holding period to elect to use the actual holding period of the common units transferred. Thus, according to the ruling, a common unitholder will be unable to select high or low basis common units to sell as would be the case with corporate stock, but, according to the regulations, may designate specific common units sold for purposes of determining the holding period of units transferred. A unitholder electing to use the actual holding period of common units transferred must consistently use that identification method for all subsequent sales or exchanges of common units. A unitholder considering the purchase of additional units or a sale of common units purchased in separate transactions is urged to consult his tax advisor as to the possible consequences of this ruling and application of the Treasury Regulations.

Specific provisions of the Internal Revenue Code affect the taxation of some financial products and securities, including partnership interests, by treating a taxpayer as having sold an “appreciated” partnership interest, one in which gain would be recognized if it were sold, assigned or terminated at its fair market value, if the taxpayer or related persons enter(s) into:


	•	a short sale;

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	•	an offsetting notional principal contract; or

	•	a futures or forward contract with respect to the partnership interest or substantially identical property.

Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the partnership interest, the taxpayer will be treated as having sold that position if the taxpayer or a related person then acquires the partnership interest or substantially identical property. The Secretary of the Treasury is also authorized to issue regulations that treat a taxpayer that enters into transactions or positions that have substantially the same effect as the preceding transactions as having constructively sold the financial position.

Allocations Between Transferors and Transferees. In general, our taxable income and losses will be determined annually, will be prorated on a monthly basis and will be subsequently apportioned among the unitholders in proportion to the number of units owned by each of them as of the opening of the applicable exchange on the first business day of the month, which we refer to in this prospectus as the “Allocation Date.” However, gain or loss realized on a sale or other disposition of our assets other than in the ordinary course of business will be allocated among the unitholders on the Allocation Date in the month in which that gain or loss is recognized. As a result, a unitholder transferring units may be allocated income, gain, loss and deduction realized after the date of transfer.

The use of this method may not be permitted under existing Treasury Regulations. Accordingly, Vinson & Elkins L.L.P. is unable to opine on the validity of this method of allocating income and deductions between transferor and transferee unitholders. If this method is not allowed under the Treasury Regulations, or only applies to transfers of less than all of the unitholder’s interest, our taxable income or losses might be reallocated among the unitholders. We are authorized to revise our method of allocation between transferor and transferee unitholders, as well as unitholders whose interests vary during a taxable year, to conform to a method permitted under future Treasury Regulations.

A unitholder who owns units at any time during a quarter and who disposes of them prior to the record date set for a cash distribution for that quarter will be allocated items of our income, gain, loss and deductions attributable to that quarter but will not be entitled to receive that cash distribution.

Notification Requirements. A unitholder who sells any of his units is generally required to notify us in writing of that sale within 30 days after the sale (or, if earlier, January 15 of the year following the sale). A purchaser of units who purchases units from another unitholder is also generally required to notify us in writing of that purchase within 30 days after the purchase. Upon receiving such notifications, we are required to notify the IRS of that transaction and to furnish specified information to the transferor and transferee. Failure to notify us of a purchase may, in some cases, lead to the imposition of penalties. However, these reporting requirements do not apply to a sale by an individual who is a citizen of the United States and who effects the sale or exchange through a broker who will satisfy such requirements.

Constructive Termination. We will be considered to have been terminated for 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. A constructive termination results in the closing of our taxable year for all unitholders. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. A constructive termination occurring on a date other than December 31 will result in us filing two tax returns (and unitholders receiving two Schedule K-1s) for one fiscal year and the cost of preparation of these returns will be borne by all unitholders. We would be required to make new tax elections after a termination, including a new election under Section 754 of the Internal Revenue Code, and a termination would result in a deferral of our deductions for depreciation. A termination could also result in penalties if we were unable to determine that the termination had occurred. Moreover, a termination might either accelerate the application of, or subject us to, any tax legislation enacted before the termination.

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Uniformity of Units

Because we cannot match transferors and transferees of units, we must maintain uniformity of the economic and tax characteristics of the units to a purchaser of these units. In the absence of uniformity, we may be unable to completely comply with a number of federal income tax requirements, both statutory and regulatory. A lack of uniformity can result from a literal application of Treasury Regulation Section 1.167(c)-1(a)(6). Any non-uniformity could have a negative impact on the value of the units. Please read “— Tax Consequences of Unit Ownership — Section 754 Election.”

We intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized Book-Tax Disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the property’s unamortized Book-Tax Disparity, or treat that portion as nonamortizable, to the extent attributable to property the common basis of which is not amortizable, consistent with the regulations under Section 743 of the Internal Revenue Code, even though that position may be inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets. Please read “— Tax Consequences of Unit Ownership — Section 754 Election.” To the extent that the Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized Book-Tax Disparity, we will apply the rules described in the Treasury Regulations and legislative history. If we determine that this position cannot reasonably be taken, we may adopt a depreciation and amortization position under which all purchasers acquiring units in the same month would receive depreciation and amortization deductions, whether attributable to a common basis or Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our property. If this position is adopted, it may result in lower annual depreciation and amortization deductions than would otherwise be allowable to some unitholders and risk the loss of depreciation and amortization deductions not taken in the year that these deductions are otherwise allowable. This position will not be adopted if we determine that the loss of depreciation and amortization deductions will have a material adverse effect on the unitholders. If we choose not to utilize this aggregate method, we may use any other reasonable depreciation and amortization method to preserve the uniformity of the intrinsic tax characteristics of any units that would not have a material adverse effect on the unitholders. The IRS may challenge any method of depreciating the Section 743(b) adjustment described in this paragraph. If this challenge were sustained, the uniformity of units might be affected, and the gain from the sale of units might be increased without the benefit of additional deductions. Please read “— Disposition of Common Units — Recognition of Gain or Loss.”

Tax-Exempt Organizations and Other Investors

Ownership of units by employee benefit plans, other tax-exempt organizations, non-resident aliens, foreign corporations and other non-U.S. persons raises issues unique to those investors and, as described below, may have substantially adverse tax consequences to them.

Employee benefit plans and most other organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, are subject to federal income tax on unrelated business taxable income. Virtually all of our income allocated to a unitholder that is a tax-exempt organization will be unrelated business taxable income and will be taxable to them.

Non-resident aliens and foreign corporations, trusts or estates that own units will be considered to be engaged in business in the United States because of the ownership of units. As a consequence, they will be required to file federal tax returns to report their share of our income, gain, loss or deduction and pay federal income tax at regular rates on their share of our net income or gain. Moreover, under rules applicable to publicly traded partnerships, we will withhold at the highest applicable effective tax rate from cash distributions made quarterly to non-U.S. unitholders. Each non-U.S. unitholder must obtain a taxpayer identification number from the IRS and submit that number to our transfer agent on a Form W-8BEN or applicable substitute form in order to obtain credit for these withholding taxes. A change in applicable law may require us to change these procedures.

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In addition, because a foreign corporation that owns units will be treated as engaged in a United States trade or business, that corporation may be subject to the United States branch profits tax at a rate of 30%, in addition to regular federal income tax, on its share of our income and gain, as adjusted for changes in the foreign corporation’s “U.S. net equity,” which is effectively connected with the conduct of a United States trade or business. That tax may be reduced or eliminated by an income tax treaty between the United States and the country in which the foreign corporate unitholder is a “qualified resident.” In addition, this type of unitholder is subject to special information reporting requirements under Section 6038C of the Internal Revenue Code.

Under a ruling of the IRS, a non-U.S. unitholder who sells or otherwise disposes of a unit will be subject to federal income tax on gain realized on the sale or disposition of that unit to the extent that this gain is effectively connected with a United States trade or business of the non-U.S. unitholder. Because a non-U.S. unitholder is considered to be engaged in business in the United States by virtue of the ownership of units, under this ruling a non-U.S. unitholder who sells or otherwise disposes of a unit generally will be subject to federal income tax on gain realized on the sale or disposition of units. Apart from the ruling, a non-U.S. unitholder will not be taxed or subject to withholding upon the sale or disposition of a unit if he has owned less than 5% in value of the units during the five-year period ending on the date of the disposition and if the units are regularly traded on an established securities market at the time of the sale or disposition.

Administrative Matters

Information Returns and Audit Procedures. We intend to furnish to each unitholder, within 90 days after the close of each calendar year, specific tax information, including a Schedule K-1, which describes his share of our income, gain, loss and deduction for our preceding taxable year. In preparing this information, which will not be reviewed by counsel, we will take various accounting and reporting positions, some of which have been mentioned earlier, to determine each unitholder’s share of income, gain, loss and deduction. We cannot assure you that those positions will yield a result that conforms to the requirements of the Internal Revenue Code, Treasury Regulations or administrative interpretations of the IRS. Neither we nor Vinson & Elkins L.L.P. can assure prospective unitholders that the IRS will not successfully contend in court that those positions are impermissible. Any challenge by the IRS could negatively affect the value of the units.

The IRS may audit our federal income tax information returns. Adjustments resulting from an IRS audit may require each unitholder to adjust a prior year’s tax liability, and possibly may result in an audit of his return. Any audit of a unitholder’s return could result in adjustments not related to our returns as well as those related to our returns.

Partnerships generally are treated as separate entities for purposes of federal tax audits, judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax treatment of partnership items of income, gain, loss and deduction are determined in a partnership proceeding rather than in separate proceedings with the partners. The Internal Revenue Code requires that one partner be designated as the “Tax Matters Partner” for these purposes. Our partnership agreement names our general partner as our Tax Matters Partner.

The Tax Matters Partner will make some elections on our behalf and on behalf of unitholders. In addition, the Tax Matters Partner can extend the statute of limitations for assessment of tax deficiencies against unitholders for items in our returns. The Tax Matters Partner may bind a unitholder with less than a 1% profits interest in us to a settlement with the IRS unless that unitholder elects, by filing a statement with the IRS, not to give that authority to the Tax Matters Partner. The Tax Matters Partner may seek judicial review, by which all the unitholders are bound, of a final partnership administrative adjustment and, if the Tax Matters Partner fails to seek judicial review, judicial review may be sought by any unitholder having at least a 1% interest in profits or by any group of unitholders having in the aggregate at least a 5% interest in profits. However, only one action for judicial review will go forward, and each unitholder with an interest in the outcome may participate.

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A unitholder must file a statement with the IRS identifying the treatment of any item on his federal income tax return that is not consistent with the treatment of the item on our return. Intentional or negligent disregard of this consistency requirement may subject a unitholder to substantial penalties.

Nominee Reporting. Persons who hold an interest in us as a nominee for another person are required to furnish to us:


	•	the name, address and taxpayer identification number of the beneficial owner and the nominee;

	•	whether the beneficial owner is:


	•	a person that is not a United States person;

	•	a foreign government, an international organization or any wholly owned agency or instrumentality of either of the foregoing; or

	•	a tax-exempt entity;


	•	the amount and description of units held, acquired or transferred for the beneficial owner; and

	•	specific information including the dates of acquisitions and transfers, means of acquisitions and transfers, and acquisition cost for purchases, as well as the amount of net proceeds from sales.

Brokers and financial institutions are required to furnish additional information, including whether they are United States persons and specific information on units they acquire, hold or transfer for their own account. A penalty of $50 per failure, up to a maximum of $100,000 per calendar year, is imposed by the Internal Revenue Code for failure to report that information to us. The nominee is required to supply the beneficial owner of the units with the information furnished to us.

Accuracy-Related Penalties. An additional tax equal to 20% of the amount of any portion of an underpayment of tax that is attributable to one or more specified causes, including negligence or disregard of rules or regulations, substantial understatements of income tax and substantial valuation misstatements, is imposed by the Internal Revenue Code. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for that portion and that the taxpayer acted in good faith regarding that portion.

For individuals, a substantial understatement of income tax in any taxable year exists if the amount of the understatement exceeds the greater of 10% of the tax required to be shown on the return for the taxable year or $5,000. The amount of any understatement subject to penalty generally is reduced if any portion is attributable to a position adopted on the return:


	•	for which there is, or was, “substantial authority”; or

	•	as to which there is a reasonable basis and the pertinent facts of that position are disclosed on the return.

If any item of income, gain, loss or deduction included in the distributive shares of unitholders might result in that kind of an “understatement” of income for which no “substantial authority” exists, we must disclose the pertinent facts on our return. In addition, we will make a reasonable effort to furnish sufficient information for unitholders to make adequate disclosure on their returns and to take other actions as may be appropriate to permit unitholders to avoid liability for this penalty. More stringent rules apply to “tax shelters,” which we do not believe includes us.

A substantial valuation misstatement exists if the value of any property, or the adjusted basis of any property, claimed on a tax return is 150% or more of the amount determined to be the correct amount of the valuation or adjusted basis. No penalty is imposed unless the portion of the underpayment attributable to a substantial valuation misstatement exceeds $5,000 ($10,000 for most corporations). If the valuation claimed on a return is 200% or more than the correct valuation, the penalty imposed increases to 40%.

Reportable Transactions. If we were to engage in a “reportable transaction,” we (and possibly you and others) would be required to make a detailed disclosure of the transaction to the IRS. A transaction may be a

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reportable transaction based upon any of several factors, including the fact that it is a type of tax avoidance transaction publicly identified by the IRS as a “listed transaction” or that it produces certain kinds of losses for partnerships, individuals, S corporations, and trusts in excess of $2 million in any single year, or $4 million in any combination of tax years. Our participation in a reportable transaction could increase the likelihood that our federal income tax information return (and possibly your tax return) would be audited by the IRS. Please read “— Information Returns and Audit Procedures.”

Moreover, if we were to participate in a reportable transaction with a significant purpose to avoid or evade tax, or in any listed transaction, you may be subject to the following provisions of the American Jobs Creation Act of 2004:


	•	accuracy-related penalties with a broader scope, significantly narrower exceptions, and potentially greater amounts than described above at “— Accuracy-Related Penalties”;

	•	for those persons otherwise entitled to deduct interest on federal tax deficiencies, nondeductibility of interest on any resulting tax liability; and

	•	in the case of a listed transaction, an extended statute of limitations.

We do not expect to engage in any “reportable transactions.”

State, Local, Foreign and Other Tax Considerations

In addition to federal income taxes, you likely will be subject to other taxes, such as state, local and foreign income taxes, unincorporated business taxes, and estate, inheritance or intangible taxes that may be imposed by the various jurisdictions in which we do business or own property or in which you are a resident. Although an analysis of those various taxes is not presented here, each prospective unitholder should consider their potential impact on his investment in us. We will initially own property or do business in Kentucky, Louisiana, Mississippi, Tennessee, Texas and Wyoming. Each of these states, other than Texas and Wyoming, currently imposes a personal income tax on individuals. Most of these states also impose an income tax on corporations and other entities. We may also own property or do business in other jurisdictions in the future. Although you may not be required to file a return and pay taxes in some jurisdictions because your income from that jurisdiction falls below the filing and payment requirement, you will be required to file income tax returns and to pay income taxes in many of these jurisdictions in which we do business or own property and may be subject to penalties for failure to comply with those requirements. In some jurisdictions, tax losses may not produce a tax benefit in the year incurred and may not be available to offset income in subsequent taxable years. Some of the jurisdictions may require us, or we may elect, to withhold a percentage of income from amounts to be distributed to a unitholder who is not a resident of the jurisdiction. Withholding, the amount of which may be greater or less than a particular unitholder’s income tax liability to the jurisdiction, generally does not relieve a nonresident unitholder from the obligation to file an income tax return. Amounts withheld will be treated as if distributed to unitholders for purposes of determining the amounts distributed by us. Please read “— Tax Consequences of Unit Ownership — Entity-Level Collections.” Based on current law and our estimate of our future operations, our general partner anticipates that any amounts required to be withheld will not be material.

It is the responsibility of each unitholder to investigate the legal and tax consequences, under the laws of pertinent jurisdictions, of his investment in us. Accordingly, each prospective unitholder is urged to consult, and depend upon, his tax counsel or other advisor with regard to those matters. Further, it is the responsibility of each unitholder to file all state, local and foreign, as well as United States federal tax returns, that may be required of him. Vinson & Elkins L.L.P. has not rendered an opinion on the state, local or foreign tax consequences of an investment in us.

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SELLING UNITHOLDER

If the underwriters exercise all or any portion of their option to purchase additional common units, we will issue up to 1,875,000 additional common units, and we will redeem an equal number of units from Columbia Energy Holdings Corporation, a subsidiary of NiSource, which will be deemed to be a selling unitholder and an underwriter in this offering. The redemption price per common unit will be equal to the price per common unit (net of underwriting discounts and a structuring fee) sold to the underwriters upon exercise of their option.

The following table sets forth information concerning the ownership of common units by our general partner. The numbers in the table are presented assuming:


	•	the underwriters’ option to purchase additional units is not exercised; and

	•	the underwriters exercise their option to purchase additional units in full.

Common Units Owned Immediately

After Exercise of Underwriters’

After This Offering

Option and Related Unit Redemption

Assuming

Underwriters’

Option is not

Option is

Name of Selling Unitholder

Exercised

Percent(1)

Exercised in Full

Percent(1)

Columbia Energy Holdings Corporation

8,584,349

26.9

%

6,709,349

21.0

%


(1)		Percentage of total units outstanding, including common units, subordinated units and general partner units.

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INVESTMENT IN NISOURCE ENERGY PARTNERS, L.P. BY EMPLOYEE BENEFIT PLANS

An investment in us by an employee benefit plan is subject to additional considerations because the investments of these plans are subject to the fiduciary responsibility and prohibited transaction provisions of ERISA and restrictions imposed by Section 4975 of the Internal Revenue Code. For these purposes the term “employee benefit plan” includes, but is not limited to, qualified pension, profit-sharing and stock bonus plans, Keogh plans, simplified employee pension plans and tax deferred annuities or IRAs established or maintained by an employer or employee organization. Among other things, consideration should be given to:


	•	whether the investment is prudent under Section 404(a)(1)(B) of ERISA;

	•	whether in making the investment, that plan will satisfy the diversification requirements of Section 404(a)(1)(C) of ERISA; and

	•	whether the investment will result in recognition of unrelated business taxable income by the plan and, if so, the potential after-tax investment return. Please read “Material Tax Consequences — Tax-Exempt Organizations and Other Investors”.

The person with investment discretion with respect to the assets of an employee benefit plan, often called a fiduciary, should determine whether an investment in us is authorized by the appropriate governing instrument and is a proper investment for the plan.

Section 406 of ERISA and Section 4975 of the Internal Revenue Code prohibit employee benefit plans, and also IRAs that are not considered part of an employee benefit plan, from engaging in specified transactions involving “plan assets” with parties that are “parties in interest” under ERISA or “disqualified persons” under the Internal Revenue Code with respect to the plan.

In addition to considering whether the purchase of common units is a prohibited transaction, a fiduciary of an employee benefit plan should consider whether the plan will, by investing in us, be deemed to own an undivided interest in our assets, with the result that our operations would be subject to the regulatory restrictions of ERISA, including its prohibited transaction rules, as well as the prohibited transaction rules of the Internal Revenue Code.

The Department of Labor regulations provide guidance with respect to whether the assets of an entity in which employee benefit plans acquire equity interests would be deemed “plan assets” under some circumstances. Under these regulations, an entity’s assets would not be considered to be “plan assets” if, among other things:

(a) the equity interests acquired by employee benefit plans are publicly offered securities — i.e., the equity interests are widely held by 100 or more investors independent of the issuer and each other, freely transferable and registered under some provisions of the federal securities laws;

(b) the entity is an “operating company,” — i.e., it is primarily engaged in the production or sale of a product or service other than the investment of capital either directly or through a majority-owned subsidiary or subsidiaries; or

(c) there is no significant investment by benefit plan investors, which is defined to mean that less than 25% of the value of each class of equity interest is held by the employee benefit plans referred to above, IRAs and other employee benefit plans not subject to ERISA, including governmental plans.

Our assets should not be considered “plan assets” under these regulations because it is expected that the investment will satisfy the requirements in (a) above.

Plan fiduciaries contemplating a purchase of common units should consult with their own counsel regarding the consequences under ERISA and the Internal Revenue Code in light of the serious penalties imposed on persons who engage in prohibited transactions or other violations.

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UNDERWRITING

Lehman Brothers Inc. and Citigroup Global Markets Inc. are acting as representatives of the underwriters and joint book-running managers for this offering. Under the terms of an underwriting agreement, a form of which will be filed as an exhibit to the registration statement relating to this prospectus, each of the underwriters named below has severally agreed to purchase from us the respective number of common units opposite its name below.


	Number of
Underwriters	Common Units

Lehman Brothers Inc.
Citigroup Global Markets Inc.

Total		12,500,000

The underwriting agreement provides that the underwriters’ obligation to purchase the common units depends on the satisfaction of the conditions contained in the underwriting agreement including:


	•	the obligation to purchase all of the common units offered hereby (other than those common units covered by their option to purchase additional common units as described below) if any of the common units are purchased;

	•	the representations and warranties made by us to the underwriters are true;

	•	there has been no material change in the business or the financial markets; and

	•	we deliver customary closing documents to the underwriters.

Commissions and Expenses

The following table summarizes the underwriting discounts and commissions we will pay to the underwriters in connection with this offering. These amounts are shown assuming both no exercise and full exercise of the underwriters’ option to purchase additional common units. The underwriting fee is the difference between the initial price to the public and the amount the underwriters pay to us for the common units.


	No Exercise	Full Exercise

Paid by us per unit	$	$
Total	$	$

The representatives of the underwriters have advised us that the underwriters propose to offer the common units directly to the public at the public offering price on the cover of this prospectus and to selected dealers, which may include the underwriters, at such offering price less a selling concession not in excess of $ per common unit. After the offering, the representatives may change the offering price and other selling terms.

We will pay Lehman Brothers Inc. an aggregate structuring fee equal to $0.375% of the gross proceeds of this offering for evaluation, analysis and structuring of our partnership.

The expenses of the offering that are payable by us are estimated to be approximately $3.0 million (exclusive of underwriting discounts, commissions and the structuring fee).

Option to Purchase Additional Common Units

We have granted the underwriters an option exercisable for 30 days after the date of this prospectus to purchase, from time to time, in whole or in part, up to an aggregate of 1,875,000 additional common units at the public offering price less underwriting discounts, commissions and a structuring fee. This option may be exercised if the underwriters sell more than 12,500,000 common units in connection with this offering. To the extent that this option is exercised, each underwriter will be obligated, subject to certain conditions, to

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purchase its pro rata portion of these additional common units based on the underwriter’s percentage underwriting commitment in the offering as indicated in the table at the beginning of this Underwriting section.

Lock-Up Agreements

We, our subsidiaries, our general partner and its affiliates, including the directors and executive officers of the general partner, have agreed, without the prior written consent of the representatives, not to, (1) directly or indirectly, offer, pledge, announce the intention to sell, sell, contract to sell, sell an option or contract to purchase, purchase any option or contract to sell, grant any option, right or warrant to purchase, or otherwise transfer or dispose of any common units or any securities that may be converted into or exchanged for any common units; (2) enter into any swap or other agreement that transfers, in whole or in part, any of the economic consequences of ownership of the common units; (3) file or cause to be filed a registration statement, including any amendments thereto, with respect to the registration of any common units or securities convertible, exercisable or exchangeable into common units or any other of our securities; or (4) publicly disclose the intention to do any of the foregoing for a period of 180 days from the date of this prospectus.

The 180-day restricted period described in the preceding paragraph will be extended if:


	•	during the last 17 days of the 180-day restricted period we issue an earnings release or announce material news or a material event; or

	•	prior to the expiration of the 180-day restricted period, we announce that we will release earnings results during the 16-day period beginning on the last day of the 180-day period,

in which case the restrictions described in the preceding paragraph will continue to apply until the expiration of the 18-day period beginning on the issuance of the earnings release or the announcement of the material news or the occurrence of the material event.

The representatives, in their sole discretion, may release the common units subject to these restrictions in whole or part at anytime with or without notice. When determining whether or not to release common units from these restrictions, the primary factors that the representatives will consider include the requesting unitholder’s reasons for requesting the release, the number of common units for which the release is being requested and the prevailing economic and equity market conditions at the time of the request.

As described below under “— Directed Unit Program,” any participants in the Directed Unit Program shall be subject to a 180-day lock up with respect to any units sold to them pursuant to that program. This lock up will have similar restrictions and an identical extension provision as the lock-up agreement described above. Any units sold in the Directed Unit Program to our directors or officers shall be subject to the lock-up agreement described above.

Offering Price Determination

Prior to this offering, there has been no public market for our common units. The initial public offering price will be negotiated between the representatives and us. In determining the initial public offering price of our common units, the representatives considered:


	•	the history and prospects for the industry in which we compete;

	•	our financial information and our assets;

	•	the ability of our management and our business potential and earning prospects;

	•	the prevailing securities markets at the time of this offering; and

	•	the recent market prices of, and the demand for, publicly traded common units of generally comparable master limited partnerships.

164

Indemnification

We and our general partner have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act and liabilities incurred in connection with the directed unit program referred to below, and to contribute to payments that the underwriters may be required to make for these liabilities.

Directed Unit Program

At our request, the underwriters have reserved up to % of the common units for sale at the initial public offering price to persons who are our directors, officers or employees and certain other persons. The number of common units available for sale to the general public will be reduced by the number of directed common units purchased by participants in the program. Any directed common units not so purchased will be offered by the underwriters to the general public on the same basis as all other common units offered. The directed unit program materials will include a lock-up agreement requiring each purchaser in the directed unit program to agree that for a period of 180 days from the date of the final prospectus (as such period may be extended as described above), such purchaser will not, without prior written consent from the representatives, dispose of or hedge any shares of common units purchased in the directed unit program. The purchasers in the directed unit program will be subject to substantially the same form of lock-up agreement as our officers, directors and unitholders described above.

Stabilization, Short Positions and Penalty Bids

The representatives may engage in stabilizing transactions, short sales and purchases to cover positions created by short sales, and penalty bids or purchases for the purpose of pegging, fixing or maintaining the price of the common units, in accordance with Regulation M under the Securities Exchange Act of 1934.


	•	Stabilizing transactions permit bids to purchase the underlying security so long as the stabilizing bids do not exceed a specified maximum.

	•	A short position involves a sale by the underwriters of the common units in excess of the number of common units the underwriters are obligated to purchase in the offering, which creates the syndicate short position. This short position may be either a covered short position or a naked short position. In a covered short position, the number of common units involved in the sales made by the underwriters in excess of the number of common units they are obligated to purchase is not greater than the number of common units that they may purchase by exercising their option to purchase additional common units. In a naked short position, the number of common units involved is greater than the number of common units in their option to purchase additional common units. The underwriters may close out any short position by either exercising their option to purchase additional common units and/or purchasing common units in the open market. In determining the source of common units to close out the short position, the underwriters will consider, among other things, the price of common units available for purchase in the open market as compared to the price at which they may purchase common units through their option to purchase additional common units. A naked short position is more likely to be created if the underwriters are concerned that there could be downward pressure on the price of the common units in the open market after pricing that could adversely affect investors who purchase in the offering.

	•	Syndicate covering transactions involve purchases of the common units in the open market after the distribution has been completed in order to cover syndicate short positions.

	•	Penalty bids permit the representatives to reclaim a selling concession from a syndicate member when the common units originally sold by the syndicate member are purchased in a stabilizing or syndicate covering transaction to cover syndicate short positions.

These stabilizing transactions, syndicate covering transactions and penalty bids may have the effect of raising or maintaining the market price of our common units or preventing or retarding a decline in the market price of the common units. As a result, the price of the common units may be higher than the price that might

165

otherwise exist in the open market. These transactions may be effected on The New York Stock Exchange or otherwise and, if commenced, may be discontinued at any time.

Neither we nor any of the underwriters make any representation or prediction as to the direction or magnitude of any effect that the transactions described above may have on the price of the common units. In addition, neither we nor any of the underwriters make any representation that the representatives will engage in these stabilizing transactions or that any transaction, once commenced, will not be discontinued without notice.

Electronic Distribution

A prospectus in electronic format may be made available on the Internet sites or through other online services maintained by one or more of the underwriters and/or selling group members participating in this offering, or by their affiliates. In those cases, prospective investors may view offering terms online and, depending upon the particular underwriter or selling group member, prospective investors may be allowed to place orders online. The underwriters may agree with us to allocate a specific number of common units for sale to online brokerage account holders. Any such allocation for online distributions will be made by the representatives on the same basis as other allocations.

Other than the prospectus in electronic format, the information on any underwriter’s or selling group member’s web site and any information contained in any other web site maintained by an underwriter or selling group member is not part of the prospectus or the registration statement of which this prospectus forms a part, has not been approved and/or endorsed by us or any underwriter or selling group member in its capacity as underwriter or selling group member and should not be relied upon by investors.

New York Stock Exchange

We intend to apply to list the common units on the New York Stock Exchange under the symbol “NIA.”

Discretionary Sales

The underwriters have informed us that they do not intend to confirm sales to discretionary accounts that exceed 5% of the total number of common units offered by them.

Stamp Taxes

If you purchase common units offered in this prospectus, you may be required to pay stamp taxes and other charges under the laws and practices of the country of purchase, in addition to the offering price listed on the cover page of this prospectus.

Relationships

The underwriters may, from time to time, engage in other transactions with or perform services for us in the ordinary course of their business. In addition, some of the underwriters and their affiliates have performed, and may in the future perform, various financial advisory, investment banking and other banking services in the ordinary course of business with us, NiSource and its affiliates for which they received or will receive customary compensation. An affiliate of Citigroup Global Markets Inc. serves as a lender under a $1.5 billion credit facility with a NiSource affiliate.

FINRA Rules

Because the Financial Industry Regulatory Authority, or FINRA (formerly, the NASD), views the common units offered hereby as interests in a direct participation program, the offering is being made in compliance with Rule 2810 of the NASD Conduct Rules, which are a part of the FINRA rules. Investor suitability with respect to the common units should be judged similarly to the suitability with respect to other securities that are listed for trading on a national securities exchange.

166

VALIDITY OF THE COMMON UNITS

The validity of the common units will be passed upon for us by Vinson & Elkins L.L.P., Houston, Texas and for the underwriters by Baker Botts L.L.P., Houston, Texas.

EXPERTS

The financial statements of Columbia Gulf as of December 31, 2006 and 2005, and for each of the three years in the period ended December 31, 2006 included in this Prospectus and the related financial statement schedule included elsewhere in the Registration Statement have been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report appearing herein (which report expresses an unqualified opinion on the financial statements and financial statement schedule and includes an explanatory paragraph referring to the adoption of Financial Accounting Standards Board (“FASB”) Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations, “and FASB Statement No. 158 “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans”), and have been so included in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

The balance sheet of NiSource Energy Partners, L.P. as of December 5, 2007 and the balance sheet of NiSource GP, LLC as of December 5, 2007 included in this prospectus have been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their reports appearing herein, and are included in reliance upon the reports of such firm given upon their authority as experts in accounting and auditing.

WHERE YOU CAN FIND MORE INFORMATION

We have filed with the Securities and Exchange Commission, or the SEC, a registration statement on Form S-l regarding the common units. This prospectus does not contain all of the information found in the registration statement. For further information regarding us and the common units offered by this prospectus, you may desire to review the full registration statement, including its exhibits and schedules, filed under the Securities Act. The registration statement of which this prospectus forms a part, including its exhibits and schedules, may be inspected and copied at the public reference room maintained by the SEC at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. Copies of the materials may also be obtained from the SEC at prescribed rates by writing to the public reference room maintained by the SEC at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. You may obtain information on the operation of the public reference room by calling the SEC at 1-800-SEC-0330. The SEC maintains a web site on the Internet at http://www.sec.gov. Our registration statement, of which this prospectus constitutes a part, can be downloaded from the SEC’s web site.

We intend to furnish our unitholders annual reports containing our audited financial statements and furnish or make available quarterly reports containing our unaudited interim financial information for the first three fiscal quarters of each of our fiscal years.

FORWARD-LOOKING STATEMENTS

Some of the information in this prospectus may contain forward-looking statements. These statements can be identified by the use of forward-looking terminology including “may,” “believe,” “expect,” “anticipate,” “estimate,” “continue,” or other similar words. These statements discuss future expectations, contain projections of results of operations or of financial condition, or state other “forward-looking” information. These forward-looking statements involve risks and uncertainties. When considering these forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this prospectus. The risk factors and other factors noted throughout this prospectus could cause our actual results to differ materially from those contained in any forward-looking statement.

167

INDEX TO FINANCIAL STATEMENTS


NISOURCE ENERGY PARTNERS, L.P. UNAUDITED PRO FORMA FINANCIAL STATEMENTS:
Introduction			F-2
Unaudited Pro Forma Statement of Income for the year ended December 31, 2006			F-3
Unaudited Pro Forma Statement of Income for the nine months ended September 30, 2007			F-4
Unaudited Pro Forma Balance Sheet as of September 30, 2007			F-5
Notes to the Unaudited Pro Forma Financial Statements			F-7
COLUMBIA GULF TRANSMISSION COMPANY FINANCIAL STATEMENTS:
Report of Independent Registered Public Accounting Firm			F-10
Statements of Income for the years ended December 31, 2006, 2005 and 2004			F-11
Balance Sheets as of December 31, 2006 and 2005			F-12
Statements of Cash Flows for the years ended December 31, 2006, 2005 and 2004			F-14
Statements of Common Shareholder’s Equity for the years ended December 31, 2006, 2005 and 2004			F-15
Notes to Financial Statements			F-16
Statements of Income for the nine months ended September 30, 2007 and 2006 (unaudited)			F-32
Condensed Balance Sheet as of September 30, 2007 (unaudited)			F-33
Statements of Cash Flows for the nine months ended September 30, 2007 and 2006 (unaudited)			F-35
Statements of Common Shareholder Equity for the nine months ended September 30, 2007 and 2006 (unaudited)			F-36
Notes to the Unaudited Financial Statements			F-37
NISOURCE ENERGY PARTNERS, L.P. FINANCIAL STATEMENTS:
Report of Independent Registered Public Accounting Firm			F-43
Balance Sheet as of December 5, 2007			F-44
Notes to the Balance Sheet			F-45
NISOURCE GP, LLC FINANCIAL STATEMENTS:
Report of Independent Registered Public Accounting Firm			F-46
Balance Sheet as of December 5, 2007			F-47
Notes to the Balance Sheet			F-48

F-1

UNAUDITED PRO FORMA FINANCIAL STATEMENTS

Introduction

The unaudited pro forma financial statements of NiSource Energy Partners, L.P. (the Partnership), as of September 30, 2007, for the year ended December 31, 2006 and for the nine months ended September 30, 2007 are based upon historical audited and unaudited financial statements of Columbia Gulf Transmission Company (Columbia Gulf). Columbia Gulf was a wholly owned subsidiary of NiSource Inc. (NiSource) for the periods presented in these financial statements.

The contribution by NiSource to the Partnership of Columbia Gulf will be recorded at cost as it is considered to be a reorganization of entities under common control. The pro forma adjustments have been prepared as if the transactions to be effected at the closing of this offering had taken place on September 30, 2007, in the case of the of the pro forma balance sheet and as of January 1, 2006, in the case of the pro forma statements of income for the year ended December 31, 2006 and the nine months ended September 30, 2007. The unaudited pro forma financial statements have been prepared on the assumption the Partnership will be treated as a partnership for federal income tax purposes. Historical income taxes for all current and deferred taxes have been eliminated except for Tennessee state taxes which will continue to be borne by the partnership following this offering. The unaudited pro forma financial statements were derived by adjusting the historical financial statements of Columbia Gulf and should be read in conjunction with the accompanying notes. The adjustments are based upon currently available information and certain assumptions and estimates. Actual effects of these transactions will differ from the pro forma adjustments. The Partnership’s management believes that the assumptions and estimates used in these pro forma financial statements provide a reasonable basis for presenting the significant effects of the transactions as contemplated and that the pro forma adjustments are factually supportable and give appropriate effect to the expected events upon the formation of the Partnership and related transactions. The pro forma adjustments have been prepared as if the disposition of certain offshore assets currently owned by Columbia Gulf had taken place on September 30, 2007, in the case of the pro forma balance sheet, and as of January 1, 2006, in the case of the pro forma income statements.

At the closing of this offering the following transactions will occur:


	•	NiSource or its subsidiaries will contribute Columbia Gulf to the partnership;

	•	we will issue to subsidiaries of NiSource 8,584,349 common units and 10,222,715 subordinated units, representing an aggregate 58.9% limited partner interest in us;

	•	we will issue to NiSource GP, LLC, a subsidiary of NiSource, a 2% general partner interest in us and all of our incentive distribution rights, which will entitle our general partner to increasing percentages of the cash we distribute in excess of $0.345 per unit per quarter (115% of the minimum quarterly distribution);

	•	we will issue 12,500,000 common units to the public in this offering, representing a 39.1% limited partner interest in us, and will use the proceeds as described in “Use of Proceeds”;

	•	we expect to borrow approximately $37.0 million in term debt and $163.0 million in revolving debt under our $250.0 million credit facility and distribute the aggregate net proceeds of such borrowings (approximately $198.0 million net of debt issuance costs) to subsidiaries of NiSource; and

	•	we will enter into an omnibus agreement with NiSource, our general partner and certain of their affiliates pursuant to which NiSource will indemnify us for certain environmental and tax liabilities, title and right-of-way defects and potential government-mandated pipeline capital expenditures.

The unaudited pro forma financial statements are not necessarily indicative of the results that actually would have occurred if the Partnership had assumed the operations of the Columbia Gulf on the dates indicated or which would be obtained in the future.

F-2

NISOURCE ENERGY PARTNERS, L.P.

UNAUDITED PRO FORMA STATEMENT OF INCOME
YEAR ENDED DECEMBER 31, 2006


	Predecessor			Pro Forma			Partnership
	Historical			Adjustments			Pro Forma
	(In millions, except unit amounts)

Operating Revenues
Transportation revenues	$	108.4		$	(4.6	)(a)	$	103.8
Transportation revenues — affiliated		13.4			—			13.4
Other revenues		1.4			(1.4	)(a)		—
Other revenues — affiliated		0.1			—			0.1

Total Operating Revenues		123.3			(6.0	)		117.3

Operating Expenses
Operation and maintenance		43.5			(6.1	)(a)		37.4
Operation and maintenance — affiliated		17.7			—			17.7
Depreciation and amortization		22.0			(2.9	)(a)		19.1
Other taxes		8.1			—			8.1

Total Operating Expenses		91.3			(9.0	)		82.3

Operating Income		32.0			3.0			35.0

Other Income (Deductions)
Interest expense — affiliated		(4.0	)		0.3	(b)		(3.7	)
Other interest expense		—			(12.1	)(c)		(12.5	)
					(0.4	)(d)

Allowance for borrowed funds used during construction		1.3			(0.3	)(a)		1.0
Interest income		0.1			1.0	(e)		1.1
Interest income — affiliated		0.4			—			0.4
Other, net		0.7			—			0.7

Total Other Income (Deductions)		(1.5	)		(11.5	)		(13.0	)

Income Before Income Taxes		30.5			(8.5	)		22.0
Income Taxes		12.2			(12.1	)(f)		0.1

Net Income	$	18.3		$	3.6		$	21.9

General partner’s interest in net income							$	0.4

Limited partners’ interest in net income							$	21.5

Net income per limited partners’ unit
Common units							$	1.02

Subordinated units							$	—

Weighted average number of limited partners’ units outstanding
Common units								21,084,349

Subordinated units								10,222,715

See accompanying notes to unaudited pro forma financial statements

F-3

NISOURCE ENERGY PARTNERS, L.P.

UNAUDITED PRO FORMA STATEMENT OF INCOME
NINE MONTHS ENDED SEPTEMBER 30, 2007


	Predecessor			Pro Forma			Partnership
	Historical			Adjustments			Pro Forma
	(In millions, except unit amounts)

Operating Revenues
Transportation revenues	$	89.1		$	(4.0	)(a)	$	85.1
Transportation revenues — affiliated		9.3			—			9.3
Other revenues		1.2			(1.1	)(a)		0.1

Total Operating Revenues		99.6			(5.1	)		94.5

Operating Expenses
Operation and maintenance		31.3			(6.0	)(a)		25.3
Operation and maintenance — affiliated		13.1			—			13.1
Depreciation and amortization		16.4			(1.6	)(a)		14.8
Other taxes		6.2			—			6.2

Total Operating Expenses		67.0			(7.6	)		59.4

Operating Income		32.6			2.5			35.1

Other Income (Deductions)
Interest expense — affiliated		(3.3	)		0.5	(b)		(2.8	)
Other interest expense		(0.1	)		(9.1	)(c)		(9.5	)
					(0.3	)(d)
Allowance for borrowed funds used during construction		1.6			—			1.6
Interest income		—			0.8	(e)		0.8

Total Other Income (Deductions)		(1.8	)		(8.1	)		(9.9	)

Income Before Income Taxes		30.8			(5.6	)		25.2
Income Taxes		10.7			(10.6	)(f)		0.1

Net Income	$	20.1		$	5.0		$	25.1

General partner’s interest in net income							$	0.5

Limited partners’ interest in net income							$	24.6

Net income per limited partners’ unit
Common units							$	0.90

Subordinated units							$	0.55

Weighted average number of limited partners’ units outstanding
Common units								21,084,349

Subordinated units								10,222,715

See accompanying notes to unaudited pro forma financial statements

F-4

NISOURCE ENERGY PARTNERS, L.P.

UNAUDITED PRO FORMA BALANCE SHEET
SEPTEMBER 30, 2007


	Predecessor			Pro Forma			Partnership
	Historical			Adjustments			Pro Forma
	(In millions)

ASSETS
Property Plant and Equipment
Total property plant and equipment	$	1,136.9		$	—		$	1,136.9
Accumulated provision for depreciation and amortization		(815.4	)		—			(815.4	)

Net Property Plant and Equipment		321.5			—			321.5

Other Assets
Assets held for sale		5.3			(5.3	)(a)		—
Current Assets
Cash and cash equivalents		—			250.0	(g)		89.7
					(18.9	)(h)
					(54.9	)(i)
					163.0	(j)
					(2.0	)(k)
					(220.8	)(l)
					(37.0	)(m)
					37.0	(n)
					(26.7	)(o)
Marketable securities		—			37.0	(m)		37.0
Accounts receivable		60.7			(60.7	)(p)		—
Accounts receivable — affiliated		1.7			(1.7	)(p)		—
Materials and supplies, at average cost		8.8			—			8.8
Exchange gas receivable		37.1			—			37.1
Regulatory assets		2.3			—			2.3
Prepaid insurance		6.8			—			6.8
Prepayments and other		2.5			(1.1	)(f)		1.4

Total Current Assets		119.9			63.2			183.1

Other Assets
Regulatory assets		13.4			—			13.4
Goodwill		321.3			—			321.3
Deferred charges and other		1.9			—			1.9

Total Other Assets		336.6			—			336.6

Total Assets		783.3			57.9			841.2

See accompanying notes to unaudited pro forma financial statements

F-5

NISOURCE ENERGY PARTNERS, L.P.

UNAUDITED PRO FORMA BALANCE SHEET — (Continued)
SEPTEMBER 30, 2007


	Predecessor		Pro Forma			Partnership
	Historical		Adjustments			Pro Forma
	(In millions)

PARTNERS’CAPITAL/PARENT NET EQUITY
Parents net equity	$	508.3	$	39.9	(f)	$	0.0
				(54.9	)(i)
				(220.8	)(l)
				(5.3	)(a)
				(62.4	)(p)
				(204.8	)(q)
Common unitholders — public		—		250.0	(g)		231.1
				(18.9	)(h)
Common unitholders — sponsor		—		90.4	(q)		90.4
Covertible subordinated unitholders — sponsor		—		107.7	(q)		107.7
General partner interest		—		6.7	(q)		6.7

Total partners’ capital/parent net equity		508.3		(72.4	)		435.9

Long-term debt, excluding amounts due within one year		67.9		163.0	(j)		265.9
				37.0	(n)
				(2.0	)(k)

Total Capitalization		576.2		125.6			701.8

Current Liabilities
Short-term borrowings — affiliated		26.7		(26.7	)(o)		—
Accounts payable		8.9		—			8.9
Accounts payable — affiliated		28.9		—			28.9
Customer deposits		1.8		—			1.8
Taxes accrued		6.2		(0.8	)(f)		5.4
Exchange gas payable		15.3		—			15.3
Regulatory liabilities		0.5		—			0.5
Accrued liability for postretirement and postemployment benefits		0.1		—			0.1
Other accruals		5.1		—			5.1

Total Current Liabilities		93.5		(27.5	)		66.0

Other Liabilities and Deferred Credits
Deferred income taxes		40.6		(40.2	)(f)		0.4
Deferred investment tax credits		0.2		—			0.2
Accrued liability for postretirement and postemployment benefits		10.8		—			10.8
Regulatory liabilities and other removal costs		49.8		—			49.8
Asset retirement obligations		3.5		—			3.5
Other noncurrent liabilities		8.7		—			8.7

Total Other Liabilities and Deferred Credits		113.6		(40.2	)		73.4

Commitments and Contingencies		—		—			—

Total Partners’ Capital/Parent Net Equity and Liabilities	$	783.3	$	57.9		$	841.2

F-6

NISOURCE ENERGY PARTNERS, L.P.

NOTES TO THE UNAUDITED PRO FORMA FINANCIAL STATEMENTS


1.	Basis of Presentation, The Offering and Other Transactions

The unaudited pro forma financial statements of NiSource Energy Partners, L.P. (the Partnership) are derived from the historical audited financial statements for the year ended December 31, 2006 and unaudited financial statements for the nine-month period ended September 30, 2007, of Columbia Gulf Transmission Company (Columbia Gulf), appearing elsewhere in this prospectus and the assumptions outlined in Note 2 below. The pro forma adjustments have been prepared as if certain transactions to be effected at the closing of this offering had taken place on September 30, 2007, in the case of the pro forma balance sheet, and as of January 1, 2006, in the case of the pro forma statements of operations for the year ended December 31, 2006, and for the nine months ended September 30, 2007. The adjustments are based on currently available information and certain estimates and assumptions and therefore the actual effects of these transactions will differ from the pro forma adjustments. These transactions include:


	•	Columbia Gulf’s distribution of accounts receivable of $62.4 million to subsidiaries of NiSource;

	•	Our receipt of $235.0 million in net proceeds after deducting underwriting discounts, but before paying expenses associated with the offering and related formation transactions and structuring fees payable to Lehman Brothers Inc. from the issuance and sale of 12,500,000 common units to the public at an assumed price of $20.00 per common unit;

	•	Our borrowing approximately $37.0 million in term debt and $163.0 million in revolving debt under our new $250.0 million credit facility;

	•	Our use of proceeds and borrowings to pay transaction expenses and underwriting commissions, retire assumed indebtedness, reimburse subsidiaries of NiSource for certain capital expenditures, make distributions to subsidiaries of NiSource, and fund identified capital expenditures and working capital; and

	•	The disposition of certain offshore assets currently owned by Columbia Gulf. On October 30, 2007 Columbia Gulf and Tennessee Gas Pipeline Company (Tennessee) entered into a binding purchase and sale agreement whereby Tennessee will buy certain assets in the offshore Gulf of Mexico.

Upon completion of this offering, the Partnership anticipates incurring incremental general and administrative expense of approximately $3.2 million per year as a result of being a publicly traded limited partnership, including costs associated with annual and quarterly reports to unitholders, and other costs. The unaudited pro forma financial statements do not reflect these incremental expenses because they are not currently factually supportable as the expected scope of the required services has not yet been defined.


2.	Pro Forma Adjustments and Assumptions

(a) Reflects the disposition of certain Columbia Gulf assets relating to offshore operations that will not be transferred to the Partnership as part of the offering.

(b) Reflects short-term debt interest elimination on money pool borrowings that are going to be repaid as described below in (o).

(c) Reflects the interest expense related to the borrowings described below in (j) at an interest rate of 6.25% and the borrowings described below in (n) at a net interest rate after consideration of interest earned on qualified investment grade securities assigned as collateral to secure new term loan borrowings, of 0.25%.

(d) Reflects the amortization of the deferred issuance costs related to the borrowings described below in (j) and (n) over the 5-year term of the associated debt.

(e) Reflects interest income on available cash.

F-7

NISOURCE ENERGY PARTNERS, L.P.

NOTES TO THE UNAUDITED PRO FORMA FINANCIAL STATEMENTS — (Continued)

(f) Reflects the elimination of historical federal income taxes for all current and deferred taxes apart from Tennessee state income taxes which will continue to be borne by the Partnership following this offering.

(g) Reflects the gross proceeds to the Partnership of $250.0 million from the issuance and sale of 12,500,000 common units at an assumed initial public offering price of $20.00 per unit.

(h) Reflects the payment of an underwriting commission of $15.0 million and other offering fees and expenses of $3.9 million, which will be allocated to the public common units (one time costs).

(i) Reflects the distribution of $54.9 million to reimburse subsidiaries of NiSource for certain capital expenditures incurred prior to the offering.

(j) Reflects $163.0 million of borrowings under the revolving portion of the new credit facility.

(k) Reflects the estimated deferred debt issuance costs of $2.0 million associated with the new credit facility.

(l) Reflects the distribution of $220.8 million to NiSource of a portion of the net proceeds from the offering and related borrowings under the new credit facility.

(m) Reflects the purchase of $37.0 million investment grade securities that will be assigned as collateral to secure new term loan borrowings under the credit facility as described below in (n).

(n) Reflects $37.0 million of term borrowings under the new credit facility.

(o) Reflects the retirement of short-term money pool borrowings owed to a subsidiary of NiSource. The balance of this indebtedness fluctuates daily. As of September 30, 2007, the balance of the indebtedness was $26.7 million.

(p) Reflects the distribution of $62.4 million to subsidiaries of NiSource of accounts receivable for Columbia Gulf.

(q) Reflects the conversion of the adjusted parent net equity of Columbia Gulf from the parent net equity to common and subordinated limited partner capital and the general partner’s interest.

Conversion:

$90.4 million for 8,584,349 common units issued to a subsidiary of NiSource

$107.7 million for 10,222,715 subordinated units

$6.7 million for 638,920 general partner units

Common units accrue cumulative cash distributions for any period in which the available cash is not adequate to achieve the minimum distribution of $0.30 per quarter.

The subordinated units may convert to common units should certain performance milestones be reached. The subordination period also will end upon the removal of our general partner other than for cause if the units held by our general partner and its affiliates are not voted in favor of such removal. When the subordination period ends, all remaining subordinated units will convert into common units on a one-for-one basis, and the common units will no longer be entitled to arrearages.

The above assumes that the underwriters’ over-allotment option is not exercised. If the underwriters exercise their option to purchase additional common units in full, we would receive approximately $35.1 million of net proceeds from the sale of these common units and would (1) use such net proceeds from the sale of these additional units to purchase an equivalent amount of qualifying securities and (2) borrow an additional amount under the term loan facility equal to such net proceeds.

F-8

NISOURCE ENERGY PARTNERS, L.P.

NOTES TO THE UNAUDITED PRO FORMA FINANCIAL STATEMENTS — (Continued)


3.	Pro Forma Net Income per Unit

Pro forma net income per unit is determined by dividing the pro forma net income that would have been allocated, in accordance with the provisions of the limited partnership agreement, to the common and subordinated unitholders by the number of common and subordinated units to be outstanding at the closing of the offering. For purposes of this calculation, we assumed that (1) pro forma distributions were equal to pro forma earnings, (2) the number of units outstanding was 21,084,349 common units and 10,222,715 subordinated units (excludes exercise of the underwriters’ over-allotment option), and (3) all units were assumed to have been outstanding since the beginning of the periods presented. Basic and diluted pro forma net income per unit are equivalent as there are no dilutive units at the date of the closing of the initial public offering. During each quarter of the year ended December 31, 2006, the minimum quarterly distribution would not have been made to all common unitholders. Instead only $1.02 would be been distributed to the common unitholders and the subordinated unitholders would have received zero. During the nine months ended September 30, 2007, the minimum quarterly distribution would have been made to all common unitholders for a total of $0.90 per common unit and each subordinated unitholders would have received $0.55 per unit.

SEC Staff Accounting Bulletin 1:B:3 requires that certain distributions to owners prior to or coincident with an initial public offering be considered as distributions in contemplation of that offering. Upon completion of this offering, NiSource Energy Partners, L.P. intends to distribute approximately $275.7 million in cash to affiliates of NiSource Inc. This distribution will be paid with (i) $163.0 million of revolving borrowings and $37.0 million in term borrowings, net of $2.0 million in issuance costs; and (ii) $77.7 million from the proceeds of the issuance and sale of common units. Assuming additional common units were issued to give effect to this distribution, pro forma net income per limited partners’ unit would have been $0.48 and $0.54 for common and subordinated units for the year ended December 31, 2006 and nine months ended September 30, 2007, respectively.

F-9

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of NiSource Inc.:

We have audited the accompanying balance sheets of Columbia Gulf Transmission Company (“the Company”) as of December 31, 2006 and 2005, and the related statements of income, common shareholder’s equity, and cash flows for each of the three years in the period ended December 31, 2006. Our audits also included the financial statement schedule listed in Item 16. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2006 and 2005, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2006, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects, the information set forth therein.

As explained in Note 2 to the financial statements, effective December 31, 2005, the Company adopted Financial Accounting Standards Board (“FASB”) Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations.” As explained in Note 2 to the financial statements, effective December 31, 2006, the Company adopted FASB Statement No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans.”

/s/ DELOITTE & TOUCHE LLP

Columbus, Ohio

December 14, 2007

F-10

COLUMBIA GULF TRANSMISSION COMPANY

STATEMENTS OF INCOME


Year Ended December 31,	2006			2005			2004
	(In millions)

Operating Revenues
Transportation revenues	$	108.4		$	97.7		$	105.1
Transportation revenues — affiliated		13.4			16.6			19.5
Other revenues		1.4			1.7			2.3
Other revenues — affiliated		0.1			0.1			0.1

Total Operating Revenues		123.3			116.1			127.0

Operating Expenses
Operation and maintenance		43.5			30.9			38.4
Operation and maintenance — affiliated		17.7			20.4			17.3
Depreciation and amortization		22.0			22.2			23.2
Other taxes		8.1			8.5			7.8

Total Operating Expenses		91.3			82.0			86.7

Operating Income		32.0			34.1			40.3

Other Income (Deductions)
Interest expense — affiliated		(4.0	)		(5.1	)		(5.3	)
Other interest expense		—			—			(0.1	)
Allowance for borrowed funds used during construction		1.3			0.1			—
Interest income		0.1			—			0.1
Interest income — affiliated		0.4			0.6			0.3
Other, net		0.7			0.5			—

Total Other Income (Deductions)		(1.5	)		(3.9	)		(5.0	)

Income Before Income Taxes		30.5			30.2			35.3
Income Taxes		12.2			11.7			13.1

Net Income	$	18.3		$	18.5		$	22.2

Common dividends declared	$	15.0		$	30.6		$	—

See notes to financial statements

F-11

COLUMBIA GULF TRANSMISSION COMPANY

BALANCE SHEETS


As of December 31,	2006			2005
	(In millions)

ASSETS
Property Plant and Equipment
Total property plant and equipment	$	1,393.4		$	1,373.4
Accumulated provision for depreciation and amortization		(1,082.8	)		(1,067.9	)

Net Property Plant and Equipment		310.6			305.5

Current Assets
Accounts receivable (less reserve of $1.6 and $1.2, respectively)		70.8			14.4
Accounts receivable — affiliated		15.2			21.2
Materials and supplies, at average cost		8.1			7.6
Exchange gas receivable		11.3			31.1
Regulatory assets		1.6			1.8
Prepayments and other		6.8			3.4

Total Current Assets		113.8			79.5

Other Assets
Regulatory assets		15.7			9.3
Goodwill		321.3			321.3
Deferred charges and other		1.7			0.4

Total Other Assets		338.7			331.0

Total Assets	$	763.1		$	716.0

See notes to financial statements

F-12

COLUMBIA GULF TRANSMISSION COMPANY

BALANCE SHEETS — (Continued)


As of December 31,	2006		2005
	(In millions, except shares outstanding)

CAPITALIZATION AND LIABILITIES
Capitalization Common Shareholder’s Equity Common stock — $10 par value — 3,000 shares authorized, 1,933 shares issued and outstanding	$	—	$	—
Additional paid-in capital		418.5		418.3
Retained earnings		69.7		66.4

Total Common Shareholder’s Equity		488.2		484.7
Long-term debt-affiliated, excluding amounts due within one year		67.9		67.9

Total Capitalization		556.1		552.6

Current Liabilities
Short-term borrowings-affiliated		13.7		—
Accounts payable		30.1		8.1
Accounts payable-affiliated		9.5		2.3
Customer deposits		1.1		1.1
Taxes accrued		4.1		6.8
Exchange gas payable		25.5		39.8
Regulatory liabilities		0.3		0.1
Accrued liability for postretirement and postemployment benefits		0.1		0.8
Other accruals		13.0		11.1

Total Current Liabilities		97.4		70.1

Other Liabilities and Deferred Credits
Deferred income taxes		40.5		37.4
Deferred investment tax credits		0.2		0.2
Deferred credits		0.1		—
Accrued liability for postretirement and postemployment benefits		12.8		7.2
Regulatory liabilities and other removal costs		46.9		43.2
Asset retirement obligations		3.4		3.2
Other noncurrent liabilities		5.7		2.1

Total Other Liabilities and Deferred Credits		109.6		93.3

Commitments and Contingencies		—		—

Total Capitalization and Liabilities	$	763.1	$	716.0

See notes to financial statements

F-13

COLUMBIA GULF TRANSMISSION COMPANY

STATEMENTS OF CASH FLOWS


Year Ended December 31,	2006			2005			2004
	(In millions)

Operating Activities
Net income	$	18.3		$	18.5		$	22.2
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization		22.0			22.2			23.2
Deferred income taxes and investment tax credits		2.8			1.0			2.8
Stock compensation expense		0.1			0.1			—
Changes in assets and liabilities:
Accounts receivable		(31.7	)		2.3			2.7
Inventories		(0.5	)		(0.6	)		0.1
Accounts payable		27.2			3.2			0.4
Customer deposits		—			(0.1	)		1.2
Taxes accrued		(2.4	)		3.6			0.9
Exchange gas receivable/payable		0.5			0.3			0.3
Other accruals		3.4			2.6			(7.6	)
Prepayments and other current assets		(3.1	)		(0.4	)		0.1
Regulatory assets/liabilities		0.3			(1.7	)		—
Postretirement and postemployment benefits		0.3			0.9			0.6
Deferred credits		0.1			—			—
Deferred charges and other noncurrent assets		(0.9	)		0.2			0.4
Other noncurrent liabilities		3.7			(1.1	)		(2.0	)

Net Cash Flows from Operating Activities		40.1			51.0			45.3

Investing Activities
Capital expenditures		(25.1	)		(31.5	)		(7.0	)
Cost to replace capital items, net of insurance recoveries (see Note 14)		(25.0	)		(5.1	)		—
Changes in short-term lendings — affiliated		11.3			16.3			(27.6	)

Net Cash Flows used for Investing Activities		(38.8	)		(20.3	)		(34.6	)

Financing Activities
Issuance of long-term debt		—			67.9			—
Retirement of long-term debt		—			(67.9	)		—
Changes in short-term borrowings — affiliated		13.7			—			(10.7	)
Capital contributed		—			(0.1	)		—
Dividends paid — common stock		(15.0	)		(30.6	)		—

Net Cash Flows used for Financing Activities		(1.3	)		(30.7	)		(10.7	)

Increase (decrease) in cash and cash equivalents		—			—			—
Cash and cash equivalents at beginning of year		—			—			—

Cash and cash equivalents at end of period	$	—		$	—		$	—

Supplemental Disclosures of Cash Flow Information
Cash paid for interest	$	4.0		$	5.2		$	5.4
Interest capitalized		1.3			0.1			0.0
Cash paid for income taxes		11.7			7.4			9.8

See notes to financial statements

F-14

COLUMBIA GULF TRANSMISSION COMPANY

STATEMENTS OF COMMON SHAREHOLDER’S EQUITY


	Common Stock				Additional
	Shares				Paid-In			Retained
	Outstanding		Value		Capital			Earnings			Total
	(In millions, except for shares outstanding)

Balance January 1, 2004		1,933	$	—	$	416.6		$	56.3		$	472.9

Net Income									22.2			22.2
Capital contributed						1.2						1.2
Tax benefit allocation						0.5						0.5

Balance December 31, 2004		1,933	$	—	$	418.3		$	78.5		$	496.8

Net Income									18.5			18.5
Cash dividends:
Common stock									(30.6	)		(30.6	)
Capital contributed						(0.1	)					(0.1	)
Tax benefit allocation						0.1						0.1

Balance December 31, 2005		1,933	$	—	$	418.3		$	66.4		$	484.7

Net Income									18.3			18.3
Cash dividends:
Common stock									(15.0	)		(15.0	)
Tax benefit allocation						0.2			—			0.2

Balance December 31, 2006		1,933	$	—	$	418.5		$	69.7		$	488.2

See notes to financial statements

F-15

COLUMBIA GULF TRANSMISSION COMPANY

NOTES TO FINANCIAL STATEMENTS
Years Ended December 31, 2006, 2005 and 2004


1.	Nature of Operations and Summary of Significant Accounting Policies

A. Company Structure. Columbia Gulf Transmission Company (Columbia Gulf) is a wholly owned subsidiary of NiSource Inc. (NiSource). Columbia Gulf is engaged in the transportation of natural gas through interstate pipeline systems located in Kentucky, Louisiana, Mississippi, Tennessee, Texas, Wyoming and the offshore Gulf of Mexico. Columbia Gulf considers its operations as one reportable segment. NiSource’s Chief Executive Officer is considered the chief operating decision maker.

NiSource Corporate Services Company (NiSource Corporate Services), a wholly-owned subsidiary of NiSource, administers short-term financing and short-term investment opportunities for NiSource’s participating subsidiaries through a money pool. Columbia Gulf was a participant in the NiSource money pool for all of the periods presented in the financial statements. The individual cash accounts maintained by Columbia Gulf are swept into a NiSource corporate account on a daily basis, creating an affiliated receivable or decreasing an affiliated payable, as appropriate, between NiSource and Columbia Gulf. Therefore, Columbia Gulf’s financials do not reflect any cash balances.

Columbia Gulf’s financing requirements have been managed historically with cash generated by operations and debt issuances, as needed. On November 28, 2005, Columbia Gulf refinanced its long-term debt of $67.9 million with NiSource Finance Corporation (NiSource Finance), a wholly owned subsidiary of NiSource.

Columbia Gulf’s costs of doing business are reflected in the financial statements for the periods presented. These costs include direct charges and allocations from NiSource subsidiaries for:


	•	Corporate services, such as human resources, finance and accounting, legal and senior executives;

	•	Business services, including payroll, accounts payable and information technology; and

	•	Pension and other post-retirement benefit costs.

Transactions between Columbia Gulf and other NiSource subsidiaries have been identified in the financial statements as affiliated transactions. Please refer to Note 13.

The financial statements of Columbia Gulf have been prepared in accordance with accounting principles generally accepted in the Unites States of America. In the opinion of management, the assumptions underlying the financial statements are reasonable.

Comprehensive income is equal to net income as there are no other comprehensive income items for Columbia Gulf for the years ended December 31, 2006, 2005 and 2004.

B. Use of Estimates. The preparation of financial statements in conformity with generally accepted accounting principles in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures in financial statements. Actual results could differ from those estimates.

C. Basis of Accounting for Rate-Regulated Operations. Columbia Gulf follows the accounting and reporting requirements of Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation” (SFAS No. 71). SFAS No. 71 provides that rate-regulated companies account for and report assets and liabilities consistent with the economic effect of the way in which regulators establish rates, if the rates established are designed to recover the costs of providing the regulated service and it is probable that such rates can be charged and collected. Certain expenses and credits subject to utility regulation or rate determination normally reflected in income are deferred on the Balance Sheet and are recognized in income as the related amounts are included in service rates and recovered from or refunded to customers.

F-16

COLUMBIA GULF TRANSMISSION COMPANY

NOTES TO FINANCIAL STATEMENTS — (Continued)
Years Ended December 31, 2006, 2005 and 2004

Columbia Gulf has designed its rates to recover the costs of providing the regulated service and determined it is probable that such rates can be charged and collected. In the event that regulation significantly changes the opportunity for Columbia Gulf to recover its costs in the future, it may no longer meet the criteria for the application of SFAS No. 71. In such event, a write-down of all or a portion of Columbia Gulf’s existing regulatory assets and liabilities could result. If transition cost recovery was approved by the Federal Energy Regulatory Commission (FERC) that would meet the requirements under generally accepted accounting principles for continued accounting as regulatory assets and liabilities during such recovery period, the regulatory assets and liabilities would be reported at the recoverable amounts. If unable to continue to apply the provisions of SFAS No. 71, Columbia Gulf would be required to apply the provisions of SFAS No. 101, “Regulated Enterprises — Accounting for the Discontinuation of Application of Financial Accounting Standards Board Statement No. 71.” In management’s opinion, Columbia Gulf will be subject to SFAS No. 71 for the foreseeable future.

Regulatory assets and liabilities were comprised of the following items:


At December 31,	2006		2005
	(In millions)

Assets
Other postretirement costs	$	8.5	$	8.2
FERC annual charge assessment		1.0		1.1
Retirement income plan costs		1.0		1.4
AFUDC		0.3		0.3
Unrecognized pension benefit and OPEB cost (SFAS 158)		6.4		—
Other		0.1		0.1

Total Assets	$	17.3	$	11.1

Liabilities
SFAS 109 — excess deferred taxes		0.3		0.4
Asset retirement obligations (see Note 4)		3.4		3.2
Cost of Removal (see Note 4)		46.6		42.9
Other		0.3		—

Total Liabilities	$	50.6	$	46.5

With the adoption of SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans” (SFAS No. 158), Columbia Gulf determined that the future recovery of pension and other postretirement plans costs is probable in accordance with the requirements of SFAS No. 71. Columbia Gulf recorded amounts that would otherwise have been recorded to accumulated other comprehensive income to a regulatory asset account. Refer to Note 2, “Recent Accounting Pronouncements,” in the Notes to Financial Statements for additional information.

Regulatory assets of $12.7 million are not presently included in rate base and consequently are not earning a return on investment. Although recovery of these amounts is not guaranteed, Columbia Gulf believes that these costs meet the requirements for deferral as regulatory assets as defined by the FERC. If Columbia Gulf determined that the amounts included as regulatory assets were not recoverable, a charge to income would immediately be required to the extent of the unrecoverable amounts.

D. Property, Plant and Equipment and Related Depreciation and Maintenance. Property, plant and equipment is stated at cost and includes jointly owned assets accounted for by proportionate consolidation. Such costs include materials, payroll and related costs such as taxes, pensions and other employee benefits,

F-17

COLUMBIA GULF TRANSMISSION COMPANY

NOTES TO FINANCIAL STATEMENTS — (Continued)
Years Ended December 31, 2006, 2005 and 2004

general and administrative costs and include allowance for funds used during construction (AFUDC). Columbia Gulf’s property, plant and equipment is comprised as follows:


At December 31,	2006			2005
	(In millions)

Onshore —
Pipelines	$	697.8		$	692.5
Facilities, structures and other		347.4			332.3
Offshore —
Pipelines		213.2			224.2
Facilities, structures and other		44.1			44.1
Construction work in progress		18.8			8.2
Other		72.1			72.1

Total property plant and equipment		1,393.4			1,373.4
Accumulated provision for depreciation and amortization		(1,082.8	)		(1,067.9	)

Net property plant and equipment	$	310.6		$	305.5

AFUDC is capitalized on all classes of property except organization, land, autos, office equipment, tools and other general property purchases. The allowance is applied to construction costs for that period of time between the date of the first expenditure and the date on which such project is completed and placed in service. The pre-tax rate for AFUDC was 5.28% in 2006, 2.3% in 2005 and 2.05% in 2004. Short-term borrowings were used to fund construction efforts for the years presented; therefore, these AFUDC rates only consisted of an interest component. The rates in 2006 increased due to higher short-term interest rates. Columbia Gulf recorded AFUDC amounts of $1.3 million, $0.1 million and zero in 2006, 2005 and 2004, respectively.

Columbia Gulf follows the practice of charging maintenance and repairs, including the cost of removal of minor items of property, to expense as incurred. When property that represents a retired unit is replaced or removed, the cost of such property is credited to utility plant, and such cost, together with the cost of removal net of salvage, is charged to the accumulated provision for depreciation.

Columbia Gulf records depreciation on a composite straight-line basis. The table below lists the applicable annual depreciation rates.


	2006		2005		2004

Offshore		1.0%		1.0%		1.0%
Onshore		1.7%		1.7%		1.7%
Other		2.0% - 11.4%		2.0% - 11.4%		2.0% - 11.4%

E. Amortization of Software Costs. External and internal costs associated with computer software developed for internal use are capitalized. Capitalization of such costs commences upon the completion of the preliminary stage of each project in accordance with Statement of Position 98-1, “Accounting for the Costs of Computer Software Developed or Obtained for Internal Use.” Once the installed software is ready for its intended use, such capitalized costs are amortized on a straight-line basis generally over a period of five years. Columbia Gulf amortized $0.7 million in 2006, $1.1 million in 2005 and $2.0 million in 2004 related to software costs.

F. Goodwill. Goodwill represents the excess of purchase price over fair value of net assets acquired. Columbia Gulf evaluates goodwill for potential impairment under the guidance of SFAS No. 142, “Goodwill

F-18

COLUMBIA GULF TRANSMISSION COMPANY

NOTES TO FINANCIAL STATEMENTS — (Continued)
Years Ended December 31, 2006, 2005 and 2004

and Other Intangible Assets (SFAS No. 142).” Under this provision, goodwill is subject to an annual test for impairment. Columbia Gulf has designated June 30 as the date it performs the annual review for goodwill impairment. Additional impairment tests are performed between the annual reviews if events or changes in circumstances make it more likely than not that the fair value is below its carrying amount.

Impairment testing of goodwill consists of a two-step process. The first step involves a comparison of the implied fair value of a reporting unit with its carrying amount. If the carrying amount of the reporting unit exceeds its fair value, the second step of the process involves a comparison of the fair value and carrying value of the goodwill of that reporting unit. If the carrying value of the goodwill of a reporting unit exceeds the implied fair value of that goodwill, an impairment loss is recognized in an amount equal to the excess.

Columbia Gulf uses a discounted cash flow analysis to determine fair value. Key assumptions in the determination of fair value include the use of an appropriate discount rate and estimated future cash flows. Columbia Gulf did not record any impairment of its goodwill in 2006, 2005 and 2004. Goodwill for Columbia Gulf’s sole operating segment, Columbia Gulf, was $321.3 million at December 31, 2006 and 2005.

G. Revenue Recognition. Revenues are recognized as services are provided and customers are billed on a monthly basis. Revenues from long-term contracts are recognized in accordance with the accrual basis of accounting and are recognized over the term of the contract as services are provided. Estimates may be used for determining the services provided. Differences between actual and estimated revenues are immaterial.

H. Significant Customers. The customer accounting for 10% or more of Columbia Gulf revenues during the years ended December 31, 2006, 2005 and 2004 were as follows:

% of Revenues Years Ended December 31,

Customer

2006

2005

2004

Columbia Gas of Ohio, Inc.

7%

10%

12%

I. Estimated Rate Refunds. Columbia Gulf collects revenues subject to refund pending final determination in rate proceedings. In connection with such revenues, estimated rate refund liabilities are recorded which reflect management’s current judgment of the ultimate outcomes of the proceedings. No provisions are made when, in the opinion of management, the facts and circumstances preclude a reasonable estimate of the outcome.

J. Inventory Policy. Columbia Gulf’s policy is to maintain materials/supplies and compressor spare parts for use in the utility business for construction, operation, and maintenance purposes. The inventory is accounted for by using the weighted-average method of inventory valuation. The inventory records are maintained on a perpetual basis.

K. Accounting for Exchange and Balancing Arrangements of Natural Gas. Columbia Gulf has entered into balancing and exchange arrangements of natural gas as part of its operations. Columbia Gulf records a receivable or payable for its respective cumulative gas imbalances and for any gas borrowed or lent under an exchange agreement. Columbia Gulf values these balances using twelve-month average spot rates. These receivables and payables are recorded as “Exchange gas receivable” or “Exchange gas payable” on the Balance Sheets, as appropriate.

L. Income Taxes and Investment Tax Credits. For income tax purposes, Columbia Gulf is included in the consolidated federal and various state returns filed by NiSource. Under Columbia Gulf’s tax-sharing agreement with NiSource, Columbia Gulf remits tax payments to NiSource, or receives tax benefits from NiSource based on its separate company taxable income.

F-19

COLUMBIA GULF TRANSMISSION COMPANY

NOTES TO FINANCIAL STATEMENTS — (Continued)
Years Ended December 31, 2006, 2005 and 2004

Income taxes have been provided by Columbia Gulf on the basis of its separate company income. Deferred income taxes have been provided for temporary differences between GAAP and tax carrying amounts of assets and liabilities.

To the extent certain deferred income taxes of Columbia Gulf are recoverable or payable through future rates, regulatory assets and liabilities have been established. Regulatory assets for income taxes are primarily attributable to property related items and the cumulative net amount of other income tax timing differences for which deferred taxes had not been provided in the past, when regulators did not recognize such taxes as costs in the rate-making process. Regulatory liabilities for income taxes are primarily attributable to Columbia Gulf’s obligation to refund to ratepayers deferred income taxes provided at rates higher than the current federal income tax rate. Such amounts are credited to ratepayers using the reverse South Georgia method. In addition, unamortized deferred investment tax credits are amortized over the regulatory life of the assets in rates.

Please refer to Note 6, “Income Taxes,” in the Notes to Financial Statements for additional information.

M. Environmental Expenditures. Columbia Gulf accrues for costs associated with environmental remediation obligations when the incurrence of such costs is probable and the amounts can be reasonably estimated, regardless of when the expenditures are actually made. The undiscounted estimated future expenditures are based on currently enacted laws and regulations, existing technology and site-specific costs where assumptions may be made about the nature and extent of site contamination, the extent of cleanup efforts, costs of alternative cleanup methods and other variables. The liability is adjusted as further information is discovered or circumstances change. Columbia Gulf’s reserves for estimated environmental expenditure are recorded on the Balance Sheet in “Other noncurrent liabilities.” Columbia Gulf applies FERC guidelines for establishing regulatory assets on the balance sheet to the extent that future recovery of environmental remediation costs is probable through the regulatory process.

Please refer to Note 12 D. “Environmental Matters” in the Notes to Financial Statements for additional information.


2.	Recent Accounting Pronouncements

Recently Adopted Accounting Pronouncements

SFAS No. 158 — Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans (SFAS No. 158) In September 2006, the FASB issued SFAS No. 158 to improve existing reporting for defined benefit postretirement plans by requiring employers to recognize in the statement of financial position the overfunded or underfunded status of a defined benefit postretirement plan, among other changes. In the fourth quarter of 2006, Columbia Gulf adopted the provisions of SFAS No. 158 requiring employers to recognize in the statement of financial position the overfunded or underfunded status of a defined benefit postretirement plan, measured as the difference between the fair value of the plan assets and the benefit obligation. Based on the measurement of the various defined benefit pension and other postretirement plans’ assets and benefit obligations at September 30, 2006, the pretax impact of adopting SFAS No. 158 increased deferred charges and other assets by $0.3 million, increased regulatory assets by $6.4 million and increased accrued liabilities for postretirement and postemployment benefits by $6.7 million. With the adoption of SFAS No. 158 Columbia Gulf determined that the future recovery of pension and other postretirement plans costs is probable in accordance with the requirements of SFAS No. 71. Columbia Gulf recorded regulatory assets and liabilities that would otherwise have been recorded to accumulated other comprehensive income.

Columbia Gulf adopted the SFAS No. 158 measurement date provisions in the first quarter of 2007 requiring employers to measure plan assets and benefit obligations as of the fiscal year-end. Upon adopting the measurement date provisions of SFAS No. 158 in the first quarter of 2007, Columbia Gulf decreased its

F-20

COLUMBIA GULF TRANSMISSION COMPANY

NOTES TO FINANCIAL STATEMENTS — (Continued)
Years Ended December 31, 2006, 2005 and 2004

accrued liabilities for postretirement and postemployment benefits by $1.6 million and increased its deferred charges and other assets by $0.5 million. In addition, 2007 expense for pension and postretirement benefits reflected the updated measurement date valuations.

SAB No. 108 — Considering the Effects of Prior Year Misstatements When Quantifying Misstatements in Current Year Financial Statements (SAB No. 108). In September 2006, the SEC issued SAB No. 108 to provide guidance on how prior year misstatements should be considered when quantifying misstatements in current year financial statements. SAB No. 108 became effective for periods ending after November 15, 2006. There were no impacts to Columbia Gulf’s Financial Statements as a result of the adoption of SAB No. 108.

SFAS No. 154 — Accounting Changes and Error Corrections (SFAS No. 154). In May 2005, the FASB issued SFAS No. 154 to provide guidance on the accounting for and reporting of accounting changes and error corrections, which is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. SFAS No. 154 establishes, unless impracticable, retrospective application as the required method for reporting a change in accounting principle in the absence of explicit transition requirements specific to the newly adopted accounting principle, and for the reporting of an error correction. Effective January 1, 2006, Columbia Gulf adopted SFAS No. 154. There was no impact to Columbia Gulf’s financial statements as a result of the adoption of SFAS No. 154.

FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (FIN 47). In March 2005, the FASB issued FIN 47 to clarify the accounting for conditional asset retirement obligations and to provide additional guidance for when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation, as used in SFAS No. 143, “Accounting for Asset Retirement Obligations” (SFAS No. 143). This interpretation is effective for fiscal years ending after December 15, 2005. Columbia Gulf adopted the provisions of FIN 47 in the fourth quarter 2005. Refer to Note 4, “Asset Retirement Obligations,” in the Notes to Financial Statements for additional information.

Recently Issued Accounting Pronouncements

SFAS No. 157 — Fair Value Measurements (SFAS No. 157). In September 2006, the FASB issued SFAS No. 157 to define fair value, establish a framework for measuring fair value and to expand disclosures about fair value measurements. Columbia Gulf is currently reviewing the provisions of SFAS No. 157 to determine the impact it may have on its financial statements and Notes to Financial Statements. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007 and should be applied prospectively, with limited exceptions.

SFAS No. 159 — The Fair Value Option for Financial Assets and Financial Liabilities — Including an amendment of FASB Statement No. 115. In February 2007, the FASB issued SFAS No. 159 which permits entities to choose to measure certain financial instruments at fair value that are not currently required to be measured at fair value. Upon adoption, a cumulative adjustment will be made to beginning retained earnings for the initial fair value option remeasurement. Subsequent unrealized gains and losses for fair value option items will be reported in earnings. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007 and should not be applied retrospectively, except as permitted for certain conditions for early adoption. Columbia Gulf is currently reviewing the provisions of SFAS No. 159 to determine whether to elect fair value measurement for any of its financial assets or liabilities when it adopts this standard in 2008.

FIN 48 — Accounting for Uncertainty in Income Taxes (FIN 48). In June 2006, the FASB issued FIN 48 to reduce the diversity in practice associated with certain aspects of the recognition and measurement requirements related to accounting for income taxes. Specifically, this interpretation requires that a tax position meet a “more-likely-than-not recognition threshold” for the benefit of an uncertain tax position to be recognized in the financial statements and requires that benefit to be measured at the largest amount of benefit

F-21

COLUMBIA GULF TRANSMISSION COMPANY

NOTES TO FINANCIAL STATEMENTS — (Continued)
Years Ended December 31, 2006, 2005 and 2004

that is greater than 50% likely of being realized upon ultimate settlement. When determining whether a tax position meets the more-likely-than-not recognition threshold, it is to be based on whether it is probable of being sustained on audit by the appropriate taxing authorities, based solely on the technical merits of the position. Additionally, FIN 48 provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. FIN 48 is effective for fiscal years beginning after December 15, 2006.

On January 1, 2007, Columbia Gulf adopted the provisions of FIN 48. There was no impact to the opening balance of retained earnings as a result of the implementation of FIN 48.


3.	Restructuring Activities

During the second quarter of 2005, NiSource Corporate Services reached a definitive agreement with International Business Machines Corp. (IBM) under which IBM will provide a broad range of business transformation and outsourcing services to NiSource. The service and outsourcing agreement is for ten years with a transition period that ended on December 31, 2006.

In June 2005, NiSource Corporate Services recorded a restructuring charge of $16.4 million for estimated severance payments expected to be made in connection with the IBM agreement. Of the $16.4 million restructuring charge recorded for the period, $0.3 million was recorded by Columbia Gulf. In the third quarter 2005 NiSource Corporate Services recorded a restructuring charge of $18.0 million for non-cash pension and post retirement benefits in connection with the IBM agreement. Of the $18.0 million restructuring charge recorded for the period, $0.6 million was recorded by Columbia Gulf.

During 2002, NiSource implemented a restructuring initiative which resulted in employee terminations throughout the organization mainly affecting executive and other management-level employees. At December 31, 2006 and 2005, Columbia Gulf’s balance sheet reflects restructuring liabilities of $0.1 million and $2.0 million for salaries, benefits and facilities costs associated with this reorganization initiative, respectively. Columbia Gulf’s restructuring liability was increased by $0.1 million in 2006 and decreased by $0.2 million in 2005 due to adjustments in estimated costs. Additionally, payments of $2.0 million, $2.0 million and $2.7 million were made in 2006, 2005 and 2004, respectively.


4.	Asset Retirement Obligations

Columbia Gulf accounts for retirement obligations on its assets in accordance with SFAS No. 143. In the fourth quarter 2005, Columbia Gulf adopted the provisions of FIN 47, which broadened the scope of SFAS No. 143 to include contingent asset retirement obligations and it also provided additional guidance for the measurement of the asset retirement liabilities. This accounting standard and the related interpretation requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When the liability is initially recorded, the entity capitalizes the cost, thereby increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted, and the capitalized cost is depreciated over the useful life of the related asset. Columbia Gulf defers the difference between the amount recognized for depreciation and accretion and the amount collected in rates as required pursuant to SFAS No. 71 for those amounts it has collected in rates or expects to collect in future rates.

Columbia Gulf adopted the provisions of SFAS No. 143 on January 1, 2003. Certain costs of removal that have been, and continue to be, included in depreciation rates and collected in service rates did not meet the definition of an asset retirement obligation pursuant to SFAS No. 143. The amounts of the other costs of removal reflected on Columbia Gulf’s balance sheet are classified as regulatory liabilities of $46.6 million at December 31, 2006 and $42.9 million at December 31, 2005, based on rates for estimated removal costs

F-22

COLUMBIA GULF TRANSMISSION COMPANY

NOTES TO FINANCIAL STATEMENTS — (Continued)
Years Ended December 31, 2006, 2005 and 2004

embedded in composite depreciation rates. These costs of removal are classified as regulatory liabilities and other removal costs on the Balance Sheets.

Columbia Gulf has recognized asset retirement obligations associated with various obligations including costs to remove and dispose of jointly owned offshore platforms, certain costs to retire pipeline, and removal of certain pipelines known to contain PCB contamination as well as some other nominal asset retirement obligations. The asset retirement obligation totaled $3.4 million and $3.2 million at December 31, 2006 and December 31, 2005, respectively. For the years ended December 31, 2006, December 31, 2005, and December 31, 2004, Columbia Gulf recognized accretion expense of $0.2 million, $0.1 million and $0.1 million, respectively.


5.	Regulatory Matters

General. Our interstate natural gas transportation system operations are regulated by the FERC under the NGA, the Natural Gas Policy Act of 1978 (NGPA) and the Energy Policy Act of 2005. Our system operates under a tariff approved by the FERC that establishes rates, cost recovery mechanisms, terms and conditions of service for our customers. Generally, the FERC’s authority extends to:


	•	transportation of natural gas;

	•	rates and charges for natural gas transportation;

	•	certification and construction of new facilities;

	•	initiation, extension or abandonment of services;

	•	maintenance of accounts and records;

	•	commercial relationships and communications between pipelines and certain affiliates;

	•	terms and conditions of service and service contracts with customers;

	•	depreciation and amortization policies; and

	•	acquisition, extension and abandonment of facilities.

Columbia Gulf’s interstate pipeline holds a certificate of public convenience and necessity issued by the FERC pursuant to Section 7 of the NGA permitting the construction, ownership, and operation of its interstate natural gas pipeline facilities and the provision of related activities and services. This certificate authorization requires our interstate pipeline facilities to provide on a non-discriminatory basis open-access services to all customers who qualify under its FERC gas tariff. Under Section 8 of the NGA, the FERC has the power to prescribe the accounting treatment of items for regulatory purposes. Thus, the books and records of our interstate pipeline may be periodically audited by the FERC.

Significant FERC Developments. On June 30, 2005, the FERC issued the “Order on Accounting for Pipeline Assessment Costs.” This guidance was issued by the FERC to address consistent application across the industry for accounting of the United States Department of Transportation’s (DOT) Integrity Management Rule. The effective date of the guidance was January 1, 2006 after which all assessment costs have been recorded as operating expenses. The rule specifically provides that amounts capitalized in periods prior to January 1, 2006 will be permitted to remain as recorded.

On July 20, 2006, the FERC issued a declaratory order in response to a petition filed by Tennessee Gas Pipeline. The petition related to a Tennessee Gas Pipeline request to establish an interconnection with Columbia Gulf operated portion of the Blue Water Pipeline system. The interconnection was placed in service on October 1, 2006. On December 29, 2006, Columbia Gulf filed in the D.C. Circuit Court of Appeals a

F-23

COLUMBIA GULF TRANSMISSION COMPANY

NOTES TO FINANCIAL STATEMENTS — (Continued)
Years Ended December 31, 2006, 2005 and 2004

Petition for Review of the FERC’s July 20, 2006 order and a subsequent order denying Columbia Gulf’s Request for Rehearing. In the declaratory order, the FERC also referred the matter to the Office of Enforcement to determine if any action should be taken against Columbia Gulf for failing to comply with prior orders that directed Columbia Gulf to allow Tennessee Gas Pipeline to make an interconnection. To resolve this matter, Columbia Gulf entered into a Stipulation and Consent Agreement dated May 21, 2007 as a voluntary agreement between Columbia Gulf and the Office of Enforcement of the FERC. Under the terms of the agreement, Columbia Gulf agreed to pay a penalty of $2 million to the United States Treasury. Columbia Gulf’s acceptance of the terms of the Stipulation and Consent Agreement is not an acknowledgement that any of its actions related to this dispute constitute a violation of law or of the FERC’s statutes, regulations, orders or policies. Columbia Gulf has asserted, and continues to believe, that it did not deliberately violate any FERC order. The December 29, 2006 D.C. Circuit Court of Appeals Petition for Review was withdrawn pursuant to the terms of the agreement with the FERC.

Columbia Gulf and Columbia Gas Transmission Corporation are also cooperating with the FERC on an informal non-public investigation of certain operating practices regarding tariff services offered by those companies. At this time, the companies cannot predict what the result of that investigation will be, but the FERC has indicated that it may seek to impose fines and possibly seek other remedies as well.


6.	Income Taxes

The components of income tax expense were as follows:


Year Ended December 31,	2006			2005		2004
	(In millions)

Income Taxes
Current
Federal	$	8.8		$	9.1	$	9.2
State		0.6			1.6		1.1

Total Current		9.4			10.7		10.3

Deferred
Federal		3.5			0.8		2.6
State		(0.7	)		0.2		0.2

Total Deferred		2.8			1.0		2.8

Total Income Taxes	$	12.2		$	11.7	$	13.1

F-24

COLUMBIA GULF TRANSMISSION COMPANY

NOTES TO FINANCIAL STATEMENTS — (Continued)
Years Ended December 31, 2006, 2005 and 2004

Total income taxes were different from the amount that would be computed by applying the statutory federal income tax rate to book income before income tax. The major reasons for this difference were as follows:


Year Ended December 31,	2006					2005				2004
	(In millions)

Book income before income taxes	$	30.5				$	30.2			$	35.3
Tax expense at statutory federal income tax rate		10.7		35.1	%		10.6	35.1	%		12.4		35.1	%
Increases (reductions) in taxes resulting from:
State income taxes, net of federal income tax benefit		—		—			1.1	3.6			0.8		2.3
Estimated non-deductible expenses		1.7		5.6			—	—			—		—
Other, net		(0.2	)	(0.7	)		—	—			(0.1	)	(0.3	)

Total Income Taxes	$	12.2		40.0	%	$	11.7	38.7	%	$	13.1		37.1	%

The effective income tax rates were 40.0%, 38.7%, and 37.1% in 2006, 2005 and 2004, respectively. The overall effective tax rate increase in 2006 versus 2005 and 2004 was due to the accrual of non-deductible expenses offset by lower state income taxes.

Deferred income taxes resulted from temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities. The principal components of Columbia Gulf’s net deferred tax liability were as follows:


At December 31,	2006			2005
	(In millions)

Deferred tax liabilities
Accelerated depreciation and other property differences	$	57.1		$	53.5
Other regulatory assets		6.6			4.2

Total Deferred Tax Liabilities		63.7			57.7

Deferred tax assets
Regulatory liabilities and cost of removal		(17.9	)		(16.6	)
Pensions and other postretirement/postemployment benefits		(3.9	)		(3.0	)
Other, net		(2.5	)		(1.5	)

Total Deferred Tax Assets		(24.3	)		(21.1	)

Deferred income taxes related to current assets and liabilities		1.1			0.8

Non-Current Deferred Tax Liability	$	40.5		$	37.4


7.	Pension and Other Postretirement Benefits

NiSource provides defined contribution plans and noncontributory defined benefit retirement plans that cover employees of Columbia Gulf. Benefits under the defined benefit retirement plans reflect the employees’ compensation, years of service and age at retirement. Additionally, NiSource provides health care and life insurance benefits for certain retired employees of Columbia Gulf. The majority of employees may become eligible for these benefits if they reach retirement age while working for Columbia Gulf. The expected cost of such benefits is accrued during the employees’ years of service. Columbia Gulf’s current rates include postretirement benefit costs on an accrual basis, including amortization of the regulatory assets that arose prior to inclusion of these costs in rates. Cash contributions are remitted to grantor trusts. As of December 31, 2006, NiSource used September 30 as its measurement date for its pension and postretirement benefit plans.

F-25

COLUMBIA GULF TRANSMISSION COMPANY

NOTES TO FINANCIAL STATEMENTS — (Continued)
Years Ended December 31, 2006, 2005 and 2004

Columbia Gulf’s employees are included in NiSource’s plans mentioned above. Costs are allocated to Columbia Gulf. Related assets, etc. are commingled and are not allocated to individual sponsors. Columbia Gulf’s employees account for 3.3% of the employees participating in the Plans in 2006 compared to 3.1% in 2005.

NiSource Retirement Plans. The fair value of NiSource’s retirement plans’ assets was $2,051.5 million as of September 30, 2006 and $2,028.1 million as of September 30, 2005. The projected benefit obligation was $2,285.7 million as of September 30, 2006 and $2,350.8 million as of September 30, 2005. The accumulated benefit obligation was $2,167.0 million at September 30, 2006 and $2,202.2 million at September 30, 2005. Gross pension expense for Columbia Gulf, as allocated by NiSource, was $0.5 million for 2006, $0.2 million for 2005 and $0.3 million for 2004. These allocations were based on expenses, net of assets returns, as actuarially determined for employees associated with Columbia Gulf. Columbia Gulf made no cash contribution to the pension plan for 2006 and 2005.

NiSource Other Postretirement Plans. The fair value of NiSource’s other postretirement plans’ assets was $243.9 million as of September 30, 2006 and $222.3 million as of September 30, 2005. The projected benefit obligation was $770.4 million as of September 30, 2006 and $760.6 million as of September 30, 2005. Postretirement benefits expense, as allocated by NiSource, for Columbia Gulf was $1.0 million in 2006, $0.9 million in 2005 and $0.9 million in 2004. These allocations were based on expenses, net of assets returns, as actuarially determined for employees associated with Columbia Gulf.

Columbia Gulf has deferred as a regulatory asset the transition obligation and the difference between other postretirement benefit costs (OPEB) and cash payments for the period January 1, 1991 to October 31, 1994. Beginning November 1994, Columbia Gulf’s rates provide for full recovery of current OPEB costs and the amortization of previously deferred OPEB costs. This regulatory asset totaled $2.4 million at December 31, 2006 and $2.9 million at December 31, 2005.


8.	Common Stock

As of December 31, 2006, Columbia Gulf had 3,000 authorized shares of common stock and 1,933 shares have been issued and outstanding to its parent, Columbia Energy Group Inc., a wholly owned subsidiary of NiSource, with a $10 par value.


9.	Long-Term Debt

Columbia Gulf’s long-term financing requirements are satisfied through borrowings from NiSource Finance. On November 28, 2005, Columbia Gulf redeemed $67.9 million of long-term debt having an average interest rate of 7.81% and refinanced the same amount having an average interest rate of 5.52%. Long-term debt at December 31, 2006 and 2005 includes $67.9 million, payable to NiSource Finance, respectively.

Details of the long-term debt balance as of December 31, 2006 and 2005 were as follows:

Date

Maturity

Issued

Outstanding

Series of Obligation

of Issue

Date

Rate

Amount

(In millions)

Installment Promissory Notes

11/28/2005

11/28/2012

5.28

%

$

23.8

Installment Promissory Notes

11/28/2005

11/28/2015

5.41

%

17.3

Installment Promissory Notes

11/28/2005

11/28/2016

5.45

%

6.8

Installment Promissory Notes

11/28/2005

11/28/2025

5.92

%

20.0

Total Installment Promissory Notes

$

67.9

F-26

COLUMBIA GULF TRANSMISSION COMPANY

NOTES TO FINANCIAL STATEMENTS — (Continued)
Years Ended December 31, 2006, 2005 and 2004

An Installment Promissory Note to Columbia in the amount of $9.6 million matured on November 28, 2005 and is included in the refinanced amount of $67.9 million.


10.	Short-Term Borrowings

Columbia Gulf satisfies its liquidity requirements primarily through internally generated funds and through intercompany borrowings from the NiSource Money Pool. As of December 31, 2006, Columbia Gulf had $13.7 million of short-term NiSource Money Pool borrowings outstanding at an interest rate of 5.73%. As of December 31, 2005, Columbia Gulf had no short-term NiSource Money Pool borrowings.


11.	Fair Value of Financial Instruments

Long-term Debt. The fair values of these securities are estimated based on the quoted market prices for the same or similar issues or on the rates offered for securities of the same remaining maturities. Certain premium costs associated with the early settlement of long-term debt are not taken into consideration in determining fair value.

The carrying amount and estimated fair values of fixed rate long-term debt were as follows:

Carrying

Estimated

Carrying

Estimated

Amount

Fair Value

Amount

Fair Value

At December 31,

2006

2005

(In millions)

Long-term debt

$

67.9

$

65.5

$

67.9

$

67.4

Other. The fair value of accounts receivable and accounts payable are not materially different from their carrying amounts due to their short term nature.


12.	Other Commitments and Contingencies

A. Capital Expenditures and Other Investing Activities. Columbia Gulf’s capital expenditure program was $25.1 million in 2006 and $31.5 million in 2005 and is projected to be approximately $39.6 million in 2007. These expenditures are primarily for modernizing and upgrading facilities and complying with the requirements of the DOT recently issued Integrity Management Rule. The DOT Integrity Management Rule requires that high consequence areas on transmission lines be assessed and remediated, if required, within a 10-year period beginning December 2002. Compliance will entail extensive assessment, including pipeline modifications to allow for testing devices, and facility replacement depending on test results. New business initiatives totaled approximately $2.9 million in 2006 and are projected to be $19.3 million in 2007.

B. Other Legal Proceedings. In the normal course of its business, Columbia Gulf has been named as defendant in various legal proceedings. In the opinion of management, the ultimate disposition of these currently asserted claims will not have a material adverse impact on Columbia Gulf’s financial position.

C. Regulatory Matters. Currently, various regulatory matters impact Columbia Gulf. Refer to Note 5, “Regulatory Matters”, in the Notes to Financial Statements for additional information.


	D.	Environmental Matters.

General. The operations of Columbia Gulf are subject to extensive and evolving federal, state and local environmental laws and regulations intended to protect the public health and the environment. Such environmental laws and regulations affect operations as they relate to impacts on air, water and land.

Proposals for voluntary initiatives and mandatory controls are being discussed both in the United States and worldwide to reduce so-called “greenhouse gases” such as carbon dioxide, a by-product of burning fossil fuels, and methane, a component of natural gas. Columbia Gulf engages in efforts to voluntarily report and

F-27

COLUMBIA GULF TRANSMISSION COMPANY

NOTES TO FINANCIAL STATEMENTS — (Continued)
Years Ended December 31, 2006, 2005 and 2004

reduce its greenhouse gas emissions. Columbia Gulf is currently a participant in the United States Environmental Protection Agency (EPA)’s Climate Leaders program and will continue to monitor and participate in developments related to efforts to register and potentially regulate greenhouse gas emissions.

Columbia Gulf is a potentially responsible party at several waste disposal sites under Comprehensive Environmental Response Compensation and Liability Act (CERCLA and similar state laws. The potential liability is believed to be de minimis. However, the final allocation of clean-up costs has yet to be determined. As site investigations and clean-ups proceed and as additional information becomes available reserves will be adjusted.

Implementation of the fine particulate matter and ozone national ambient air quality standards may require imposition of additional controls on engines and turbines. On April 15, 2004, the EPA finalized the eight-hour ozone nonattainment area designations. After designation, the Clean Air Act provides for a process for promulgation of rules specifying compliance level, compliance deadline, and necessary controls to be implemented within designated areas over the next few years. Resulting state rules could require additional reductions in nitrogen oxide (NOx) emissions from natural gas compressor stations. Also, on September 21, 2006, the EPA issued revisions to the National Ambient Air Quality Standards (NAAQS) for particulate matter. The final rule increased the stringency of the current fine particulate (PM2.5) standard, added a new standard for inhalable coarse particulate (particulate matter between 10 and 2.5 microns in diameter), and revoked the annual PM10 standards while retaining the 24-hour PM10 standards. The 24-hour primary and secondary standards for fine particulate were tightened from the previous level of 65 micrograms per cubic meter ( μg/m3) to 35 μg/m3 while the primary and secondary annual standards were kept at 15 μg/m3. The annual PM10 standards of 50 μg/m3 were revoked and the daily standards of 150 μ/m3 were retained. State recommendations for designation of areas not meeting the new fine particle standards are due December 2007 with EPA designations by December 2009, effective in April 2010. SIPs detailing how states will reduce emissions to meet the NAAQS will be due three years later with attainment due by April 2015 with a possible five year extension to April 2020. These actions could require further reductions in NOx emissions from various emission sources in and near nonattainment areas. Columbia Gulf will continue to closely monitor developments in this area and cannot accurately estimate the timing or cost of emission controls at this time.

On August 6, 2006, Columbia Gulf received final approval of the NOx SIP Call Compliance Plan from the state of Kentucky. This Plan will reduce NOx emissions by 950 tons per ozone season starting May 1, 2007. Currently Columbia Gulf anticipates installation capital costs of approximately $7.4 million in NOx controls to achieve these reductions of which $6.0 million was capitalized during the year ended December 31, 2006.

In December 2006, the EPA released the final National Emissions Standard for Hazardous Air Pollutants for Oil and Natural Gas Production Facilities. Columbia Gulf is currently evaluating impacts to operations, but based on an initial review it does not appear to result in significant cost or operational impacts.

Environmental Reserves. It is management’s continued intent to address environmental issues in cooperation with regulatory authorities in such a manner as to achieve mutually acceptable compliance plans. However, there can be no assurance that fines and penalties will not be incurred.

As of December 31, 2006 and December 31, 2005 a reserve of $0.2 million has been recorded to cover probable corrective actions at sites where Columbia Gulf has environmental remediation liability. Columbia Gulf accrues for costs associated with environmental remediation obligations when the incurrence of such costs is probable and the amounts can be reasonably estimated, regardless of when the expenditures are actually made. The undiscounted estimated future expenditures are based on many factors including currently enacted laws and regulations, existing technology and estimated site-specific costs whereby assumptions may be made about the nature and extent of site contamination, the extent of cleanup efforts, costs of alternative

F-28

COLUMBIA GULF TRANSMISSION COMPANY

NOTES TO FINANCIAL STATEMENTS — (Continued)
Years Ended December 31, 2006, 2005 and 2004

cleanup methods and other variables. Columbia Gulf’s estimated environmental remediation liability will be refined as events in the remediation process occur. Actual remediation costs may differ materially from Columbia Gulf’s estimates due to the dependence on the factors listed above.


	E.	Operating Leases.

Columbia Gulf leases assets in several areas of its operations. Payments made in connection with operating leases were $1.5 million in 2006, $0.8 million in 2005 and $2.3 million in 2004, and are primarily charged to operation and maintenance expense as incurred.

Future minimum rental payments required under operating leases that have initial or remaining non-cancelable lease terms in excess of one year are:


	(In millions)

2007	$	0.4
2008		0.2
2009		0.1
2010		0.1
2011		0.1
After		3.7

Total future minimum payments	$	4.6


	F.	Firm Service Obligations.

Since implementation of FERC Order No. 636 in the early 1990’s, the services of Columbia Gulf have consisted of open access transportation services. These services are provided primarily to local distribution companies (LDC). On October 31, 2004, firm contracts expired for Columbia Gulf, representing approximately 50% of Columbia Gulf’s net annual revenues. Based upon new commitments, Columbia Gulf realized a reduction of approximately $8.5 million in annual revenues under the replacement contracts for 2005, which represents approximately 7% of Columbia Gulf’s total revenues. The terms of the replacement contracts entered into by Columbia Gulf range from one year to 15 years, with an average term of approximately seven years. These reductions are partially offset by increased revenues of approximately $1.0 million in 2005 and $5.5 million in 2006 as the result of remarking efforts and new firm contracts.

13. Affiliated Company Transactions

Columbia Gulf receives executive, financial, and administrative and general services from an affiliate, NiSource Corporate Services. The costs of these services are charged to Columbia Gulf based on payroll costs and expenses incurred by NiSource Corporate Services employees for the benefit of Columbia Gulf. These costs which totaled $11.0 million, $14.3 million and $10.3 million for years 2006, 2005 and 2004, respectively, consist primarily of employee compensation and benefits and are recorded within, “Operation and maintenance — affiliated” on the Statements of Income. Columbia Gulf also incurred expenses from an affiliate, Columbia Gas Transmission Corporation (Columbia Transmission), for various routine administrative activities totaling $5.3 million, $5.4 million and $6.3 million during the years 2006, 2005 and 2004, respectively.

Certain of Columbia Gulf’s employees were participants in the NiSource long-term incentive plan whereby NiSource share based awards were granted. These awards are accounted for by Columbia Gulf in accordance with SFAS No. 123R, “Share-Based Payments.” The costs of these awards are identified by employee and are an expense of the NiSource subsidiary for which the employee works. Columbia Gulf recorded share based compensation expense of approximately $0.1 million, $0.1 million and zero in 2006,

F-29

COLUMBIA GULF TRANSMISSION COMPANY

NOTES TO FINANCIAL STATEMENTS — (Continued)
Years Ended December 31, 2006, 2005 and 2004

2005 and 2004, respectively, which are included as a part of Columbia Gulf’s employee related expenses discussed above.

Columbia Gulf recorded gas transportation revenues from affiliates of $13.4 million, $16.6 million and $19.5 million for years 2006, 2005 and 2004, respectively.

The December 31, 2006 and 2005 accounts receivable balance includes $15.2 million and $21.2 million respectively, due from associated companies. Also, included in this balance are amounts due from the NiSource Money Pool of zero and $11.4 million, respectively.

As of December 31, 2006, and 2005, Columbia Gulf had a long-term debt affiliated balance of $67.9 million due to NiSource Finance Corp. (NiSource Finance) borrowings.

As of December 31, 2006, Columbia Gulf had short-term NiSource Money Pool borrowings of $13.7 million at an interest rate of 5.73%. As of December 31, 2005, Columbia Gulf had no short-term NiSource Money Pool borrowings.

The December 31, 2006 and 2005 accounts payable balance includes $9.5 million and $2.3 million, respectively, due to associated companies.

The December 31, 2006 and 2005 Taxes Accrued balance includes $0.5 million and $2.6 million, respectively, of accrued federal and state income taxes that are payable to NiSource in accordance with its tax-sharing agreement.

14. Capital Costs for Damages

In September, 2004, hurricane Ivan damaged certain Columbia Gulf jointly owned property and in the third quarter of 2005, Columbia Gulf incurred additional damages to its jointly owned pipeline assets and wholly owned facilities as a result of hurricanes Katrina and Rita. Total costs recorded to repair damages on jointly owned and wholly owned facilities in 2006, 2005, and 2004 were $42.3 million, $4.5 million, and $0 million respectively. Columbia Gulf is covered by insurance for these damages subject to a $1.0 million deductible per incident. Amounts billed for reimbursement through insurance are recorded within “Accounts Receivable,” on the Balance Sheet. For the years ended December 31, 2006, 2005, and 2004, the Company had received $4.0 million, zero, and zero in insurance recoveries related to these damages and incurred a deductible of $1.8 million, $1.2 million, and zero as a deductible under its insurance policies. Costs to repair damages are recognized when costs are incurred or as information becomes available to estimate the damages incurred. As of December 31, 2006 and 2005, the Company had a receivable of $39.8 million and $3.3 million related to the hurricanes, and since a portion of its facilities are jointly owned and operated by the other owner, the Company also recorded a payable of $21.3 million and $0 million to its partner for work they performed on the jointly owned facilities. Capital expenditures net of insurance recoveries for these damages were $8.6 million, $3.0 million and zero in 2006, 2005 and 2004 respectively, and recorded as, “Capital costs to repair damages, net of insurance recoveries,” within investing activities on the Statement of Cash Flows.

On May 26, 2005, a turbine failure occurred at the Delhi compressor station located along Columbia Gulf’s mainline system in northeast Louisiana. Total costs recorded to repair damages to the facility in 2006, and 2005 were $24.7 million and $3.1 million respectively. Costs to repair damages are recognized when costs are incurred or as information becomes available to estimate the damages incurred. Columbia Gulf is covered by insurance for these damages and the claim was settled in 2007 for $25.0 million which included $5.9 million for business interruption revenue. The claim was subject to a $1.0 million deductible, which was incurred in 2005. The settlement resulted in $10.4 million not being recovered through insurance. The receivable for claims not recovered was reduced with an offsetting adjustment to property, plant and equipment as the claims were for capital charges incurred. For the years ended December 31, 2006 and 2005, the

F-30

COLUMBIA GULF TRANSMISSION COMPANY

NOTES TO FINANCIAL STATEMENTS — (Continued)
Years Ended December 31, 2006, 2005 and 2004

Company had received $10.2 million and $0 million in insurance recoveries related to these damages, of which $1.9 million was business interruption receipts in 2006. Columbia Gulf received the remaining $13.8 million in 2007, of which $4.0 million was business interruption receipts. Amounts billed for reimbursement through insurance are recorded within “Accounts Receivable,” on the Balance Sheet. As of December 31, 2006 and 2005, the Company had a receivable of $19.9 million and $2.1 million related to the damages incurred at the Delhi compressor station. Capital expenditures net of insurance recoveries for these damages were $16.4 million and $2.1 million in 2006 and 2005, respectively, and recorded as, “Capital costs to repair damages, net of insurance recoveries,” within investing activities on the Statement of Cash Flows.

15. Subsequent Event

On October 30, 2007, Columbia Gulf and Tennessee Gas Pipeline Company executed a definitive purchase and sale agreement for the sale of a portion of Columbia Gulf’s offshore assets. Closing of the transaction is dependent upon the receipt of required regulatory approvals which Columbia Gulf anticipates receiving in the first half of 2008. Tennessee Gas Pipeline Company currently co-owns and utilizes the offshore assets being sold. These assets, valued at $5.3 million, were reported as assets held for sale within the balance sheet as of September 30, 2007 in accordance with SFAS No. 144.

F-31

COLUMBIA GULF TRANSMISSION COMPANY

STATEMENTS OF INCOME


Nine Months Ended September 30,	2007			2006
	(Unaudited)
	(In millions)

Operating Revenues
Transportation revenues	$	89.1		$	79.5
Transportation revenues — affiliated		9.3			10.2
Other revenues		1.2			1.1

Total Operating Revenues		99.6			90.8

Operating Expenses
Operation and maintenance		31.3			27.9
Operation and maintenance — affiliated		13.1			13.3
Depreciation and amortization		16.4			16.5
Other taxes		6.2			6.0

Total Operating Expenses		67.0			63.7

Operating Income		32.6			27.1

Other Income (Deductions)
Interest expense — affiliated		(3.3	)		(2.8	)
Other interest expense		(0.1	)		—
Allowance for borrowed funds used during construction		1.6			0.6
Interest income		—			0.1
Interest income — affiliated		—			0.4
Other, net		—			0.7

Total Other Income (Deductions)		(1.8	)		(1.0	)

Income Before Income Taxes		30.8			26.1
Income Taxes		10.7			9.2

Net Income	$	20.1		$	16.9

Common dividends declared	$	—		$	15.0

See notes to financial statements

F-32

COLUMBIA GULF TRANSMISSION COMPANY

CONDENSED BALANCE SHEET


As of September 30,	2007
	(Unaudited)
	(In millions)

ASSETS
Property Plant and Equipment
Total property plant and equipment	$	1,136.9
Accumulated provision for depreciation and amortization		(815.4	)

Net Property Plant and Equipment		321.5

Other Assets
Assets held for sale		5.3

Current Assets
Accounts receivable (less reserve of $1.6)		60.7
Accounts receivable — affiliated		1.7
Materials and supplies, at average cost		8.8
Exchange gas receivable		37.1
Regulatory assets		2.3
Pre-paid insurance		6.8
Prepayments and other		2.5

Total Current Assets		119.9

Other Assets
Regulatory assets		13.4
Goodwill		321.3
Deferred charges and other		1.9

Total Other Assets		336.6

Total Assets	$	783.3

See notes to financial statements

F-33

COLUMBIA GULF TRANSMISSION COMPANY

CONDENSED BALANCE SHEET — (Continued)


As of September 30,	2007
	(Unaudited)
	(In millions, except
	shares outstanding)

CAPITALIZATION AND LIABILITIES
Capitalization
Common Shareholder’s Equity
Common stock — $10 par value — 3,000 shares authorized, 1,933 shares issued and outstanding	$	—
Additional paid-in capital		418.5
Retained earnings		89.8

Total Common Shareholder’s Equity		508.3
Long-term debt-affiliated, excluding amounts due within one year		67.9

Total Capitalization		576.2

Current Liabilities
Short-term borrowings — affiliated		26.7
Accounts payable		8.9
Accounts payable — affiliated		28.9
Customer deposits		1.8
Taxes accrued		6.2
Exchange gas payable		15.3
Regulatory liabilities		0.5
Accrued liability for postretirement and postemployment benefits		0.1
Other accruals		5.1

Total Current Liabilities		93.5

Other Liabilities and Deferred Credits
Deferred income taxes		40.6
Deferred investment tax credits		0.2
Accrued liability for postretirement and postemployment benefits		10.8
Regulatory liabilities and other removal costs		49.8
Asset retirement obligations		3.5
Other noncurrent liabilities		8.7

Total Other Liabilities and Deferred Credits		113.6

Commitments and Contingencies		—

Total Capitalization and Liabilities	$	783.3

See notes to financial statements

F-34

COLUMBIA GULF TRANSMISSION COMPANY

STATEMENTS OF CASH FLOWS


Nine Months Ended September 30,	2007			2006
	(Unaudited)
	(In millions)

Operating Activities
Net income	$	20.1		$	16.9
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization		16.4			16.5
Deferred income taxes and investment tax credits		0.7			—
Stock compensation expense		0.1			0.1
Changes in assets and liabilities:
Accounts receivable		13.3			0.4
Inventories		(0.6	)		(0.5	)
Accounts payable		(24.7	)		(2.7	)
Customer deposits		0.7			—
Taxes accrued		2.0			0.8
Other accruals		(8.2	)		(2.5	)
Prepayments and other current assets		(2.5	)		(6.6	)
Regulatory assets/liabilities		(0.5	)		0.3
Postretirement and postemployment benefits		(0.2	)		0.3
Deferred credits		(0.1	)		0.1
Deferred charges and other noncurrent assets		0.4			(0.8	)
Other noncurrent liabilities		3.1			4.4

Net Cash Flows from Operating Activities		20.0			26.7

Investing Activities
Capital expenditures		(22.1	)		(14.3	)
Cost to replace capital items, net of insurance recoveries (see Note 11)		(10.9	)		(19.9	)
Changes in short-term lendings — affiliated		—			11.3

Net Cash Flows used for Investing Activities		(33.0	)		(22.9	)

Financing Activities
Changes in short-term borrowings — affiliated		13.0			11.2
Dividends paid — common stock		—			(15.0	)

Net Cash Flows provided from (used for) Financing Activities		13.0			(3.8	)

Increase (decrease) in cash and cash equivalents		—			—
Cash and cash equivalents at beginning of year		—			—

Cash and cash equivalents at end of period	$	—		$	—

Supplemental Disclosures of Cash Flow Information
Cash paid for interest	$	3.4		$	2.8
Interest capitalized		1.6			0.6
Cash paid for income taxes		9.4			10.0

See notes to financial statements

F-35

COLUMBIA GULF TRANSMISSION COMPANY

STATEMENTS OF COMMON SHAREHOLDER’S EQUITY


	Common Stock				Additional
	Shares				Paid-in		Retained
	Outstanding		Value		Capital		Earnings			Total
	(Unaudited)
	(In millions, except for shares outstanding)

Balance January 1, 2007		1,933	$	—	$	418.5	$	69.7		$	488.2

Net Income								20.1			20.1

Balance September 30, 2007		1,933	$	—	$	418.5	$	89.8		$	508.3

											Total

	(In millions, except for shares outstanding)
Balance January 1, 2006		1,933	$	—	$	418.3	$	66.4		$	484.7

Net Income								16.9			16.9
Cash dividends:
Common stock								(15.0	)		(15.0	)

Balance September 30, 2006		1,933	$	—	$	418.3	$	68.3		$	486.6

See notes to financial statements

F-36

COLUMBIA GULF TRANSMISSION COMPANY

NOTES TO THE UNAUDITED FINANCIAL STATEMENTS

For the Nine Months Ended September 30, 2007 and 2006


1.	Nature of Operations and Summary of Significant Accounting Policies

A. Company Structure. Columbia Gulf Transmission Company (Columbia Gulf) is a subsidiary in NiSource Inc. (NiSource).

NiSource Corporate Services Company (NiSource Corporate Services), a wholly-owned subsidiary of NiSource, administers short-term financing and short-term investment opportunities for NiSource’s participating subsidiaries through a money pool. Columbia Gulf was a participant in the NiSource money pool for all of the periods presented in the financial statements. The individual cash accounts maintained by Columbia Gulf are swept into a NiSource corporate account on a daily basis, creating an Affiliated Receivable or decreasing an affiliated payable, as appropriate, between NiSource and Columbia Gulf. Therefore, Columbia Gulf’s financials do not reflect any cash balances.

Columbia Gulf’s financing requirements have been managed historically with cash generated by operations and debt issuances, as needed. On November 28, 2005, Columbia Gulf refinanced its long-term debt of $67.9 million with NiSource Finance Corporation (NiSource Finance), a wholly owned subsidiary of NiSource.

Columbia Gulf’s costs of doing business are reflected in the financial statements for the periods presented. These costs include direct charges and allocations from NiSource subsidiaries for:


	•	Corporate services, such as human resources, finance and accounting, legal and senior executives,

	•	Business services, including payroll, accounts payable and information technology, and

	•	Pension and other post-retirement benefit costs.

Transactions between Columbia Gulf and other NiSource subsidiaries have been identified in the financial statements as affiliated transactions. Please refer to Note 10.

The accompanying unaudited financial statements of Columbia Gulf reflect all normal recurring adjustments that are necessary, in the opinion of management, to present fairly the results of operations in accordance with generally accepted accounting principles in the United States of America.

The accompanying financial statements should be read in conjunction with Columbia Gulf’s financial statements and notes for the fiscal years ended December 31, 2006, 2005 and 2004. Income for interim periods may not be indicative of results for the calendar year due to weather variations and other factors. Comprehensive income is equal to net income as there are no other comprehensive income items for Columbia Gulf for the nine months ended September 30, 2007 and 2006.


2.	Recent Accounting Pronouncements

Recently Adopted Accounting Pronouncements

SFAS No. 158 — Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans (SFAS No. 158.) In September 2006, the FASB issued SFAS No. 158 to improve existing reporting for defined benefit postretirement plans by requiring employers to recognize in the statement of financial position the overfunded or underfunded status of a defined benefit postretirement plan, among other changes. In the fourth quarter of 2006, Columbia Gulf adopted the provisions of SFAS No. 158 requiring employers to recognize in the statement of financial position the overfunded or underfunded status of a defined benefit postretirement plan, measured as the difference between the fair value of the plan assets and the benefit obligation.

On January 1, 2007, Columbia Gulf adopted the SFAS No. 158 measurement date provisions requiring employers to measure plans assets and benefit obligations as of the fiscal year-end. The pretax impact of

F-37

COLUMBIA GULF TRANSMISSION COMPANY

NOTES TO THE UNAUDITED FINANCIAL STATEMENTS — (Continued)

For the Nine Months Ended September 30, 2007 and 2006

adopting SFAS No. 158 measurement date provisions increased deferred charges and other assets by $0.5 million, decreased regulatory assets by $2.1 million and decreased accrued liabilities for postretirement and postemployment benefits by $1.6 million. In addition, 2007 expense for pension and postretirement benefits reflected the updated measurement date valuations.

With the adoption of SFAS No. 158, Columbia Gulf determined that the future recovery of pension and other postretirement plans costs is probable in accordance with the requirements of SFAS No. 71. Columbia Gulf recorded regulatory assets and liabilities that would otherwise have been recorded to accumulated other comprehensive income.

Refer to Note 8, “Pension and Other Postretirement Benefits,” in the Notes to the Unaudited Financial Statements for additional information.

FIN 48 — Accounting for Uncertainty in Income Taxes (FIN 48). In June 2006, the FASB issued FIN 48 to reduce the diversity in practice associated with certain aspects of the recognition and measurement requirements related to accounting for income taxes. Specifically, this interpretation requires that a tax position meet a “more-likely-than-not recognition threshold” for the benefit of an uncertain tax position to be recognized in the financial statements and requires that benefit to be measured at the largest amount of benefit that is greater than 50% likely of being realized upon ultimate settlement. When determining whether a tax position meets the more-likely-than-not recognition threshold, it is to be based on whether it is probable of being sustained on audit by the appropriate taxing authorities, based solely on the technical merits of the position. Additionally, FIN 48 provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. FIN 48 is effective for fiscal years beginning after December 15, 2006.

On January 1, 2007, Columbia Gulf adopted the provisions of FIN 48. There was no impact to the opening balance of retained earnings as a result of the implementation of FIN 48.

Recently Issued Accounting Pronouncements

SFAS No. 157 — Fair Value Measurements (SFAS No. 157). In September 2006, the FASB issued SFAS No. 157 to define fair value, establish a framework for measuring fair value and to expand disclosures about fair value measurements. Columbia Gulf is currently reviewing the provisions of SFAS No. 157 to determine the impact it may have on its financial statements and Notes to Financial Statements. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007 and should be applied prospectively, with limited exceptions.

SFAS No. 159 — The Fair Value Option for Financial Assets and Financial Liabilities — Including an amendment of FASB Statement No. 115 (SFAS No. 159). In February 2007, the FASB issued SFAS No. 159 which permits entities to choose to measure certain financial instruments at fair value that are not currently required to be measured at fair value. Upon adoption, a cumulative adjustment will be made to beginning retained earnings for the initial fair value option remeasurement. Subsequent unrealized gains and losses for fair value option items will be reported in earnings. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007 and should not be applied retrospectively, except as permitted for certain conditions for early adoption. Columbia Gulf is currently reviewing the provisions of SFAS No. 159 to determine whether to elect fair value measurement for any of its financial assets or liabilities when it adopts this standard in 2008.


3.	Restructuring Activities

During the second quarter of 2005, NiSource Corporate Services reached a definitive agreement with International Business Machines Corp. (IBM) under which IBM will provide a broad range of business

F-38

COLUMBIA GULF TRANSMISSION COMPANY

NOTES TO THE UNAUDITED FINANCIAL STATEMENTS — (Continued)

For the Nine Months Ended September 30, 2007 and 2006

transformation and outsourcing services to NiSource. The service and outsourcing agreement is for ten years with a transition period that ended on December 31, 2006.

At September 30, 2007, Columbia Gulf’s Balance Sheet reflects $0.3 million in restructuring liabilities for salaries, benefits and facilities costs associated with all reorganization initiatives compared to $0.1 million at December 31, 2006. For the nine months ended September 30, 2007, the restructuring liability was increased by $0.5 million to adjust for certain costs and $0.4 million in payments were made. For the nine months ended September 30, 2006, the restructuring liability was increased by $0.1 million to adjust for certain costs and $1.5 million in payments were made.


4.	Assets Held for Sale

On October 30, 2007, Columbia Gulf and Tennessee Gas Pipeline Company executed a definitive purchase and sale agreement for the sale of a portion of Columbia Gulf’s offshore assets. Closing of the transaction is dependent upon the receipt of required regulatory approvals which Columbia Gulf anticipates receiving in the first half of 2008. Tennessee Gas Pipeline Company currently co-owns and utilizes the offshore assets being sold. These assets, valued at $5.3 million, were reported as assets held for sale within the balance sheet as of September 30, 2007 in accordance with SFAS No. 144.


5.	Asset Retirement Obligations

Columbia Gulf accounts for its asset retirement obligations in accordance with SFAS No. 143, “Accounting for Asset Retirement Obligations” (SFAS No. 143) and FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (FIN 47). Certain costs of removal that have been, and continue to be, included in depreciation rates and collected in the service rates of Columbia Gulf are classified as regulatory liabilities and other removal costs on the Balance Sheets.

For the nine months ended September 30, 2007 and September 30, 2006, Columbia Gulf recognized accretion expense of $0.2 million and $0.1 million, respectively.


6.	Regulatory Matters

Significant Federal Energy Regulatory Commission (FERC) Developments. On June 30, 2005, the FERC issued the “Order on Accounting for Pipeline Assessment Costs.” This guidance was issued by the FERC to address consistent application across the industry for accounting of the DOT’s Integrity Management Rule. The effective date of the guidance was January 1, 2006 after which all assessment costs have been recorded as operating expenses. The rule specifically provides that amounts capitalized in periods prior to January 1, 2006 will be permitted to remain as recorded.

On July 20, 2006, the FERC issued a declaratory order in response to a petition filed by Tennessee Gas Pipeline. The petition related to a Tennessee Gas Pipeline request to establish an interconnection with Columbia Gulf operated portion of the Blue Water Pipeline system. The interconnection was placed in service on October 1, 2006. On December 29, 2006, Columbia Gulf filed in the D.C. Circuit Court of Appeals a Petition for Review of the FERC’s July 20, 2006 order and a subsequent order denying Columbia Gulf’s Request for Rehearing. In the declaratory order, the FERC also referred the matter to the Office of Enforcement to determine if any action should be taken against Columbia Gulf for failing to comply with prior orders that directed Columbia Gulf to allow Tennessee Gas Pipeline to make an interconnection. To resolve this matter, Columbia Gulf entered into a Stipulation and Consent Agreement dated May 21, 2007 as a voluntary agreement between Columbia Gulf and the Office of Enforcement of the FERC. Under the terms of the agreement, Columbia Gulf agreed to pay a penalty of $2 million to the United States Treasury. Columbia Gulf’s acceptance of the terms of the Stipulation and Consent Agreement is not an acknowledgement that any

F-39

COLUMBIA GULF TRANSMISSION COMPANY

NOTES TO THE UNAUDITED FINANCIAL STATEMENTS — (Continued)

For the Nine Months Ended September 30, 2007 and 2006

of its actions related to this dispute constitute a violation of law or of the FERC’s statutes, regulations, orders or policies. Columbia Gulf has asserted, and continues to believe, that it did not deliberately violate any FERC order. The December 29, 2006 D.C. Circuit Court of Appeals Petition for Review was withdrawn pursuant to the terms of the agreement with the FERC.

Columbia Gulf and Columbia Gas Transmission Corporation are also cooperating with the FERC on an informal non-public investigation of certain operating practices regarding tariff services offered by those companies. At this time, the companies cannot predict what the result of that investigation will be, but the FERC has indicated that it may seek to impose fines and possibly seek other remedies as well.


7.	Income Taxes

Columbia Gulf joins in the filing of consolidated federal and state income tax returns with its parent company, NiSource and certain of NiSource’s other affiliated companies. Columbia Gulf is party to a tax allocation agreement under which the consolidated tax is allocated among the members of the group in proportion to each member’s relative contribution to the group’s consolidated tax liability. Because NiSource is part of the IRS’s Large and Mid-Size Business program, each year’s federal income tax return is typically audited by the IRS. Tax years through 2004 have been audited and are settled. The audit of tax years 2005 and 2006 is expected to commence in the fourth quarter of 2007.

Income taxes have been provided by Columbia Gulf on the basis of its separate company income. Deferred income taxes have been provided for temporary differences between GAAP and tax carrying amounts of assets and liabilities.

The statute of limitations in each of the state jurisdictions in which Columbia Gulf operates remain open until the years are settled for federal income tax purposes, at which time amended state income tax returns reflecting all federal income tax adjustments are filed. There are no state income tax audits currently in progress.

Columbia Gulf’s interim effective tax rates reflect the estimated annual effective tax rate for 2007 and 2006, respectively, adjusted for tax expense associated with certain discrete items. The effective tax rates for the nine months ended September 30, 2007 and September 30, 2006 were 34.7% and 35.2%, respectively. The effective tax rates differ from the federal tax rate of 35% primarily due to the effects of tax credits, state income taxes, utility rate-making, and other permanent book-to-tax differences. In the nine months ended September 30, 2007, Columbia Gulf recorded tax benefits on the reversal of accrued non-deductible expenses. For the nine months ended September 30, 2006, certain state income tax benefits were recorded which reduced the effective tax rate. Without such adjustments, the effective tax rate for both periods would have been approximately 38%.

Columbia Gulf is subject to income taxation in the United States and various state jurisdictions, primarily Kentucky, Louisiana, Mississippi and Tennessee.

There was no impact on Columbia Gulf for adopting the provisions of FIN 48 on January 1, 2007. Columbia Gulf does not have any unrecognized tax benefits.


8.	Pension and Other Postretirement Benefits

NiSource provides defined contribution plans and noncontributory defined benefit retirement plans that cover Columbia Gulf’s employees. Benefits under the defined benefit retirement plans reflect the employees’ compensation, years of service and age at retirement. Additionally, NiSource provides health care and life insurance benefits for certain retired employees of Columbia Gulf. The majority of employees may become eligible for these benefits if they reach retirement age while working for Columbia Gulf.

F-40

COLUMBIA GULF TRANSMISSION COMPANY

NOTES TO THE UNAUDITED FINANCIAL STATEMENTS — (Continued)

For the Nine Months Ended September 30, 2007 and 2006

Columbia Gulf does not expect to make contributions to its pension plan in 2007. However, Columbia Gulf expects to contribute $0.5 million to other postretirement benefit plans during 2007. Through September 30, 2007, Columbia Gulf has not made a contribution to its pension plans and has contributed $0.4 million to other postretirement benefit plans.


9.	Other Commitments and Contingencies

A. Other Legal Proceedings. In the normal course of its business, Columbia Gulf has been named as defendant in various legal proceedings. In the opinion of management, the ultimate disposition of these currently asserted claims will not have a material adverse impact on Columbia Gulf’s financial position.

B. Other Growth Projects. Columbia Gulf recently expanded two interconnection points providing incremental delivery capacity of 30,000 dekatherms (Dth) per day to Henry Hub and 85,000 Dth per day to Southern Natural Gas near Lafayette, Louisiana. This capacity was sold via auction and placed into service in the third quarter of 2007. A successful open season was held in the first quarter of 2007 to auction capacity of 380,000 Dth per day relating to two interconnection points being constructed in southern Louisiana with Transcontinental Gas Pipeline that will provide increased access to downstream mid-Atlantic and Northeast markets. These interconnection points are expected to be placed into service in the fourth quarter of 2007.

A binding open season for expanded capacity on Columbia Gulf’s system for delivery to Florida Gas Transmission ended on November 2, 2007.

C. Regulatory Matters. Currently, various regulatory matters impact Columbia Gulf. Refer to Note 6, “Regulatory Matters”, in the Notes to Financial Statements for additional information.

D. Environmental Matters. There were no new environmental matters relating to Columbia Gulf’s operations during the nine months of 2007.

10. Affiliated Company Transactions.

Columbia Gulf receives executive, financial, and administrative and general services from an affiliate, NiSource Corporate Services. The costs of these services are charged to Columbia Gulf based on payroll costs and expenses incurred by NiSource Corporate Services employees for the benefit of Columbia Gulf. These costs totaled $9.4 million and $8.3 million for the nine months ended September 30, 2007 and 2006, respectively, consist primarily of employee compensation and benefits and are recorded within, “Operation and maintenance — affiliated” on the Statements of Income. Columbia Gulf also incurred expenses from an affiliate, Columbia Gas Transmission Corporation (Columbia Transmission), for various routine administrative activities totaling $3.1 million and $4.2 million for the nine months ended September 30, 2007 and 2006, respectively.

Columbia Gulf recorded gas transportation revenues from affiliates of $9.3 million and $10.2 million for the nine months ended September 30, 2007 and 2006, respectively.

The September 30, 2007 accounts receivable balance includes $1.7 million due from associated companies.

As of September 30, 2007, Columbia Gulf had a long-term debt affiliated balance of $67.9 million due to NiSource Finance Corp. (NiSource Finance) borrowings.

As of September 30, 2007, Columbia Gulf had short-term NiSource Money Pool borrowings of $26.7 million at an interest rate of 5.89%.

The September 30, 2007, accounts payable balance includes $28.9 million due to associated companies.

F-41

COLUMBIA GULF TRANSMISSION COMPANY

NOTES TO THE UNAUDITED FINANCIAL STATEMENTS — (Continued)

For the Nine Months Ended September 30, 2007 and 2006

The September 30, 2007 and 2006 Taxes Accrued balance includes $1.2 million and $1.8 million, respectively, of accrued federal and state income taxes that are payable to NiSource in accordance with its tax-sharing agreement.


11.	Capital Costs for Damages.

In September, 2004, hurricane Ivan damaged certain Columbia Gulf jointly owned property and in the third quarter of 2005, Columbia Gulf incurred additional damages to its jointly owned pipeline assets and wholly owned facilities as a result of hurricanes Katrina and Rita. Total costs recorded to repair damages on jointly owned and wholly owned facilities for nine months ended September 30, 2007 and September 30, 2006 were $7.8 million and $15.4 million, respectively. Columbia Gulf is covered by insurance for these damages subject to a $1.0 million deductible per incident. Amounts billed for reimbursement through insurance are recorded within “Accounts Receivable,” on the Balance Sheet. For the nine months ended September 30, 2007 and 2006, the Company had received $5.7 million, and $4.0 million in insurance recoveries related to these damages and incurred a deductible of zero, and $0.2 million under its insurance policies. Costs to repair damages are recognized when costs are incurred or as information becomes available to estimate the damages incurred. As of September 30, 2007, the Company had a receivable of $41.9 million related to the hurricanes, and since a portion of its facilities are jointly owned and operated by the other owner, the Company had a payable of $5.5 million to its partner for work they performed on the jointly owned facilities. Capital expenditures net of insurance recoveries for these damages were $19.0 million and $8.2 million for the nine months ended September 30, 2007 and 2006, respectively, and recorded as, “Capital costs to repair damages, net of insurance recoveries,” within investing activities on the Statement of Cash Flows.

On May 26, 2005, a turbine failure occurred at the Delhi compressor station located along Columbia Gulf’s mainline system in northeast Louisiana. Total costs recorded to repair damages to the facility for the nine months ended September 30, 2007 and September 30, 2006 were $1.7 million and $18.5 million respectively. Costs to repair damages are recognized when costs are incurred or as information becomes available to estimate the damages incurred. Columbia Gulf is covered by insurance for these damages and the claim was settled in 2007 for $25.0 million and included $5.9 million for business interruption revenue. The claim was subject to a $1 million deductible, which was incurred in 2005. The settlement resulted in $10.4 million not being recovered through insurance. The receivable for claims not recovered was written off to property, plant, and equipment as the claims were for capital charges incurred. For the nine months ended September 30, 2007 and 2006, the Company had received $13.8 million and $8.4 million in insurance recoveries related to these damages, of which $4.0 million and $1.6 million were business interruption receipts, respectively. Amounts billed for reimbursement through insurance are recorded within “Accounts Receivable,” on the Balance Sheet. As of September 30, 2007, the Company had a receivable of $0 million related to the damages incurred at the Delhi compressor station. Capital expenditures net of insurance recoveries for these damages were a credit of $8.1 million and $11.7 million for the nine months ended September 30, 2007 and 2006, respectively, and recorded as, “Capital costs to repair damages, net of insurance recoveries,” within investing activities on the Statement of Cash Flows.

F-42

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Partners of

NiSource Energy Partners, L.P.

Merrillville, Indiana

We have audited the accompanying balance sheet of NiSource Energy Partners, L.P. (“the Partnership”) as of December 5, 2007. This financial statement is the responsibility of the Partnership’s management. Our responsibility is to express an opinion on this financial statement based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Partnership is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, such financial statement presents fairly, in all material respects, the financial position of the Partnership as of December 5, 2007, in conformity with accounting principles generally accepted in the United States of America.

/s/ DELOITTE & TOUCHE LLP

Columbus, Ohio

December 14, 2007

F-43

NISOURCE ENERGY PARTNERS, L.P.

BALANCE SHEET

December 5, 2007


ASSETS
Total Assets	$	—


PARTNERS’ EQUITY
Partners’ Equity
Limited partners’ equity	$	1,960
General partners’ equity		40
Less note receivable from NiSource Inc. and its subsidiary NiSource GP, LLC		(2,000	)

Total Liabilities and Partners’ Equity	$	—

See note to the balance sheet

F-44

NISOURCE ENERGY PARTNERS, L.P.

NOTES TO THE BALANCE SHEET


1.	Nature of Operations

NiSource Energy Partners, L.P. is a Delaware limited partnership formed on December 5, 2007, to acquire the assets of the Columbia Gulf. In order to simplify NiSource Energy Partners, L.P.’s obligations under the laws of selected jurisdictions in which NiSource Energy Partners, L.P. will conduct business, NiSource Energy Partners, L.P.’s activities will be conducted through a wholly owned operating partnership.

NiSource Energy Partners, L.P. intends to offer 12,500,000 common units, representing limited partner interests, pursuant to a public offering and to concurrently issue 8,584,349 common units and 10,222,715 subordinated units, representing additional limited partner interests, to subsidiaries of NiSource, as well as an aggregate 2% general partner interest in NiSource Energy Partners, L.P. and its operating partnership on a combined basis to NiSource GP, LLC.

NiSource GP, LLC, as general partner, contributed $40 and a wholly owned subsidiary of NiSource Inc., as the organizational limited partner, contributed $1,960 all in the form of the note receivable to NiSource Energy Partners, L.P. on December 5, 2007. There have been no other transactions involving NiSource Energy Partners, L.P. as of December 5, 2007.

F-45

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Partners of

NiSource GP, LLC

Merrillville, Indiana

We have audited the accompanying balance sheet of NiSource GP, LLC (“the Company”) as of December 5, 2007. This financial statement is the responsibility of the Company’s management. Our responsibility is to express an opinion on this financial statement based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provide a reasonable basis for our opinion.

In our opinion, such financial statement presents fairly, in all material respects, the financial position of the Company as of December 5, 2007, in conformity with accounting principles generally accepted in the United States of America.

/s/ DELOITTE & TOUCHE LLP

Columbus, Ohio

December 14, 2007

F-46

NISOURCE GP, LLC

BALANCE SHEET

December 5, 2007


ASSETS
Current Assets
Investment in NiSource Energy Partners, L.P.	$	40

Total Assets	$	40


LIABILITIES AND PARTNERS’ EQUITY
Liabilities
Payable to NiSource Energy Partners, L.P.	$	40

Total Liabilities		40

Owner’s Equity
Total owner’s equity		1,000
Less receivable from NiSource Inc and its subsidiaries		(1,000	)

Total Owner’s Equity		—

Total Liabilities and Owner’s Equity	$	40

See note to balance sheet

F-47

NISOURCE GP, LLC

NOTES TO THE BALANCE SHEET


1.	Nature of Operations

NiSource GP, LLC is a Delaware limited liability company formed on December 5, 2007, to become the general partner of NiSource Energy Partners, L.P. NiSource GP, LLC is an indirect wholly owned subsidiary of NiSource Inc. NiSource GP, LLC owns a 2% general partner interest in NiSource Energy Partners, L.P.

On December 5, 2007, a wholly owned subsidiary of NiSource Inc. contributed $1,000 in the form of notes receivable to NiSource GP, LLC in exchange for a 100% ownership interest.

NiSource GP, LLC has invested $40 in the form of notes receivable in NiSource Energy Partners, L.P. There have been no other transactions involving NiSource GP, LLC as of December 5, 2007.

F-48

Appendix A

FIRST AMENDED AND RESTATED
AGREEMENT OF LIMITED PARTNERSHIP
OF
NISOURCE ENERGY PARTNERS, L.P.

A-1

Appendix B

APPLICATION FOR TRANSFER OF COMMON UNITS

Transferees of Common Units must execute and deliver this application to NISOURCE ENERGY PARTNERS, L.P., c/o NiSource GP, LLC, 801 East 86th Avenue, Merrillville, Indiana 46410; Attn: CFO, to be admitted as limited partners to NISOURCE ENERGY PARTNERS, L.P.

The undersigned (“Assignee”) hereby applies for transfer to the name of the Assignee of the Common Units evidenced hereby and hereby certifies to NISOURCE ENERGY PARTNERS, L.P. (the “Partnership”) that the Assignee (including to the best of Assignee’s knowledge, any person for whom the Assignee will hold the Common Units) is an Eligible Holder.*(

The Assignee (a) requests admission as a Substituted Limited Partner and agrees to comply with and be bound by, and hereby executes, the Amended and Restated Agreement of Limited Partnership of the Partnership, as amended, supplemented or restated to the date hereof (the “Partnership Agreement”), (b) represents and warrants that the Assignee has all right, power and authority and, if an individual, the capacity necessary to enter into the Partnership Agreement, (c) appoints the General Partner of the Partnership and, if a Liquidator shall be appointed, the Liquidator of the Partnership as the Assignee’s attorney-in-fact to execute, swear to, acknowledge and file any document, including, without limitation, the Partnership Agreement and any amendment thereto and the Certificate of Limited Partnership of the Partnership and any amendment thereto, necessary or appropriate for the Assignee’s admission as a Substituted Limited Partner and as a party to the Partnership Agreement, (d) gives the powers of attorney provided for in the Partnership Agreement, and (e) makes the waivers and gives the consents and approvals contained in the Partnership Agreement. Capitalized terms not defined herein have the meanings assigned to such terms in the Partnership Agreement. This application constitutes a Taxation Certification, as defined in the Partnership Agreement.

Date:

Social Security or other identifying number of Assignee

Signature of Assignee

Purchase Price including commissions, if any Name and Address of Assignee

Type of Entity (check one):

□ Individual □ Partnership □ Corporation

□ Trust □ Other (specify)

( * The Term “Eligible Holder” means (a) an individual or entity subject to United States federal income taxation on the income generated by the Partnership; or (b) an entity not subject to United States federal income taxation on the income generated by the Partnership, so long as all of the entity’s owners are subject to United States federal income taxation on the income generated by the Partnership. Individuals or entities are subject to taxation, in the context of defining an Eligible Holder, to the extent they are taxable on the items of income and gain allocated by the Partnership or would be taxable on the items of income and gain allocated by the Partnership if they had no offsetting deductions or tax credits unrelated to the ownership of the Common Units. Schedule I hereto contains a list of various types of investors that are categorized and identified as either “Eligible Holders” or “Non-Eligible Holders.”

B-1

If not an Individual (check one):

□ the entity is subject to United States federal income taxation on the income generated by the Partnership;

□ the entity is not subject to United States federal income taxation, but it is a pass-through entity and all of its beneficial owners are subject to United States federal income taxation on the income generated by the Partnership;

□ the entity is not subject to United States federal income taxation and it is (a) not a pass-through entity or (b) a pass-through entity, but not all of its beneficial owners are subject to United States federal income taxation on the income generated by the Partnership. Important Note — by checking this box, the Assignee is contradicting its certification that it is an Eligible Holder.

Nationality (check one):


□ U.S. Citizen, Resident or Domestic Entity		□ Non-resident Alien

□ Foreign Corporation

If the U.S. Citizen, Resident or Domestic Entity box is checked, the following certification must be completed.

Under Section 1445(e) of the Internal Revenue Code of 1986, as amended (the “Code”), the Partnership must withhold tax with respect to certain transfers of property if a holder of an interest in the Partnership is a foreign person. To inform the Partnership that no withholding is required with respect to the undersigned interestholder’s interest in it, the undersigned hereby certifies the following (or, if applicable, certifies the following on behalf of the interestholder).

Complete Either A or B:

A. Individual Interestholder

1. I am not a non-resident alien for purposes of U.S. income taxation.

2. My U.S. taxpayer identification number (Social Security Number) is .

3. My home address is .

B. Partnership, Corporation or Other Interestholder

1. The interestholder is not a foreign corporation, foreign partnership, foreign trust or foreign estate (as those terms are defined in the Code and Treasury Regulations).

2. The interestholder’s U.S. employer identification number is .

3. The interestholder’s office address and place of incorporation (if applicable) is .

The interestholder agrees to notify the Partnership within sixty (60) days of the date the interestholder becomes a foreign person.

The interestholder understands that this certificate may be disclosed to the Internal Revenue Service and the Federal Energy Regulatory Commission by the Partnership and that any false statement contained herein could be punishable by fine, imprisonment or both.

Under penalties of perjury, I declare that I have examined this certification and, to the best of my knowledge and belief, it is true, correct and complete and, if applicable, I further declare that I have authority to sign this document on behalf of:

Name of Interestholder

Signature and Date

Title (if applicable)

B-2

Note: If the Assignee is a broker, dealer, bank, trust company, clearing corporation, other nominee holder or an agent of any of the foregoing, and is holding for the account of any other person, this application should be completed by an officer thereof or, in the case of a broker or dealer, by a registered representative who is a member of a registered national securities exchange or a member of the National Association of Securities Dealers, Inc., or, in the case of any other nominee holder, a person performing a similar function. If the Assignee is a broker, dealer, bank, trust company, clearing corporation, other nominee owner or an agent of any of the foregoing, the above certification as to any person for whom the Assignee will hold the Common Units shall be made to the best of the Assignee’s knowledge.

B-3

SCHEDULE I

Eligible Holders

The following are considered Eligible Holders:


	•	Individuals (U.S. or non-U.S.)

	•	C corporations (U.S. or non-U.S.)

	•	Tax exempt organizations subject to tax on unrelated business taxable income or “UBTI,” including IRAs, 401(k) plans and Keough accounts

	•	S corporations with shareholders that are individuals, trusts or tax exempt organizations subject to tax on UBTI

Potentially Eligible Holders


	•	S corporations (unless they have ESOP shareholders*)

	•	Partnerships (unless its partners include mutual funds, real estate investment trusts or “REITs,” governmental entities and agencies, S corporations with ESOP shareholders* or other partnerships with such partners)

	•	Trusts (unless beneficiaries are not subject to tax)

Non-Eligible Holders

The following are not considered Eligible Holders:


	•	Mutual Funds

	•	REITs

	•	Governmental entities and agencies

	•	S corporations with ESOP shareholders*(

( * “S corporations with ESOP shareholders” are S corporations with shareholders that include employee stock ownership plans.

B-4

Appendix C

CERTIFICATION FORM FOR NON-INDIVIDUAL INVESTORS

As described in this Prospectus, only Eligible Holders (as defined on Schedule I hereto) may purchase common units in the Partnership’s proposed public offering (the “Offering”). In order to comply with this requirement, all potential investors that are not natural persons, including institutions, partnerships and trusts (“Non-individual Investors”), must complete this Certification Form.


	•	If you have an institutional sales account with Lehman Brothers Inc., you should fax signed forms to [ • ] by 12:00 pm Eastern time on [ • ], 2008 (the “Return Date”).

	•	If you have any other type of brokerage account with any of the broker-dealers on page 2, you should fax signed forms to your retail broker or financial advisor upon initial indication of interest.

Non-individual Investors who do not complete and return this form by the
Return Date will not be allocated units in this offering.

1. Acknowledgement and Consent to Forward this Certification Form. The undersigned Non-individual Investor acknowledges and understands that an underwriter who receives this Certification Form may forward it to the Partnership and/or the transfer agent for the Common Units. Accordingly, the undersigned hereby grants its consent for Lehman Brothers Inc. or any underwriter or affiliate thereof listed on page 2 to forward this Certification Form to the Partnership and/or the transfer agent for the Common Units.

2. Acknowledgement of Obligation to Complete a Transfer Application. The undersigned Non-individual Investor further acknowledges that, if it purchases Common Units in the Offering, it must complete a Transfer Application in the form included as Appendix B to the Prospectus and deliver it to the address as instructed on the Transfer Application. The undersigned Non-individual Investor further acknowledges that no underwriter or affiliate of an underwriter has any responsibility or obligation to complete or deliver a Transfer Application on behalf of the undersigned.

3. Certification as to Tax Status. The undersigned Non-individual Investor hereby certifies that it is either (check one):

□ an entity that is subject to United States federal income taxation on the income generated by the Partnership; or

□ an entity that is not subject to United States federal income taxation, but is a pass-through entity and all of its beneficial owners are subject to United States federal income taxation on the income generated by the Partnership.

Signing this form shall not obligate the undersigned Non-individual Investor to provide or share any tax-related information with the Partnership, the transfer agent or any underwriter in connection with the purchase and sale of common units in the Offering.

Executed this day of [ • ], 2008.

(Name of Entity)

By:

Name:

Title:

NON-INDIVIDUAL INVESTOR RETAIL BROKER DEALERS

Lehman Brothers Private Wealth Management

C-1

SCHEDULE I

An “Eligible Holder” is (a) an individual or entity subject to United States federal income taxation on the income generated by the Partnership or (b) an entity not subject to United States federal income taxation on the income generated by the Partnership, so long as all of the entity’s owners are subject to United States federal income taxation on the income generated by the Partnership or would be taxable on the items of income and gain allocated by the Partnership if they had no offsetting deductions or tax credits unrelated to the ownership of the Common Units. Set forth below is a list of various types of investors that are categorized and identified as Eligible Holders, Potentially Eligible Holders or Non-Eligible Holders.

Eligible Holders

The following are considered Eligible Holders:


	•	Individuals (U.S. or non-U.S.)

	•	C corporations (U.S. or non-U.S.)

	•	Tax exempt organizations subject to tax on unrelated business taxable income or “UBTI,” including IRAs, 401(k) plans and Keough accounts

	•	S corporations with shareholders that are individuals, trusts or tax exempt organizations subject to tax on UBTI

Potentially Eligible Holders

The following are considered Eligible Holders, unless the bracketed information applies:


	•	Partnerships (unless its partners include mutual funds, real estate investment trusts or “REITs,” governmental entities and agencies, S corporations with ESOP shareholders¹ ( or other partnerships with such partners)

	•	Trusts (unless beneficiaries are not subject to tax)

Non-Eligible Holders

The following are not considered Eligible Holders:


	•	Mutual Funds

	•	REITs

	•	Governmental entities and agencies

	•	S corporations with ESOP shareholders¹

¹ “S corporations with ESOP shareholders” are S corporations with shareholders that include employee stock ownership plans.

C-2

Appendix D

GLOSSARY OF TERMS

Adjusted Operating Surplus: For any period, operating surplus generated during that period is adjusted to:

(a) increase operating surplus by any net decreases made in subsequent periods in cash reserves for operating expenditures initially established with respect to such period;

(b) decrease operating surplus by any net decrease in cash reserves for operating expenditures with respect to that period not relating to an operating expenditure made with respect to that period; and

(c) increase operating surplus by any net increase in cash reserves for operating expenditures with respect to that period required by any debt instrument for the repayment of principal, interest or premium.

Adjusted operating surplus does not include the portion of operating surplus described in subpart (a)(2) of the definition of “operating surplus” in this Appendix D.

Available Cash: For any fiscal quarter ending prior to liquidation:

(a) the sum of:

(1) all cash and cash equivalents of NiSource Energy Partners, L.P. and its subsidiaries on hand at the end of that quarter; and

(2) if our general partner so determines all or a portion of any additional cash or cash equivalents of NiSource Energy Partners, L.P. and its subsidiaries on hand on the date of determination of available cash for that quarter;

(b) less the amount of cash reserves established by our general partner to:

(1) provide for the proper conduct of the business of NiSource Energy Partners, L.P. and its subsidiaries (including reserves for future capital expenditures and for future credit needs of NiSource Energy Partners, L.P. and its subsidiaries) after that quarter resulting from working capital borrowings made after the end of that quarter. Working capital borrowings are generally borrowings that are made under a credit facility, commercial paper facility or similar financing arrangement, and in all cases are used solely for working capital purposes or to pay distributions to partners and with the intent of the borrower to repay such borrowings within 12 months;

(2) comply with applicable law or any debt instrument or other agreement or obligation to which NiSource Energy Partners, L.P. or any of its subsidiaries is a party or its assets are subject; and

(3) provide funds for minimum quarterly distributions and cumulative common unit arrearages for any one or more of the next four quarters;

provided, however, that our general partner may not establish cash reserves pursuant to clause (b)(3) immediately above unless our general partner has determined that the establishment of reserves will not prevent us from distributing the minimum quarterly distribution on all common units and any cumulative common unit arrearages thereon for that quarter; and provided, further, that disbursements made by us or any of our subsidiaries or cash reserves established, increased or reduced after the end of that quarter but on or before the date of determination of available cash for that quarter shall be deemed to have been made, established, increased or reduced, for purposes of determining available cash, within that quarter if our general partner so determines.

Bcf: One billion cubic feet of natural gas.

Bcf/d: One billion cubic feet per day.

Btu: British Thermal Units.

D-1

Capital Account: The capital account maintained for a partner under the partnership agreement. The capital account of a partner for a common unit, a Class B unit, a subordinated unit, an incentive distribution right or any other partnership interest will be the amount which that capital account would be if that common unit, a Class B unit, subordinated unit, incentive distribution right or other partnership interest were the only interest in NiSource Energy Partners, L.P. held by a partner.

Capital Surplus: All available cash distributed by us on any date from any source will be treated as distributed from operating surplus until the sum of all available cash distributed since the closing of the initial public offering equals the operating surplus from the closing of the initial public offering through the end of the quarter immediately preceding that distribution. Any excess available cash distributed by us on that date will be deemed to be capital surplus.

Closing Price: The last sale price on a day, regular way, or in case no sale takes place on that day, the average of the closing bid and asked prices on that day, regular way, in either case, as reported in the principal consolidated transaction reporting system for securities listed or admitted to trading on the principal national securities exchange on which the units of that class are listed or admitted to trading. If the units of that class are not listed or admitted to trading on any national securities exchange, the last quoted price on that day. If no quoted price exists, the average of the high bid and low asked prices on that day in the over-the-counter market, as reported by the New York Stock Exchange or any other system then in use. If on any day the units of that class are not quoted by any organization of that type, the average of the closing bid and asked prices on that day as furnished by a professional market maker making a market in the units of the class selected by the our board of directors. If on that day no market maker is making a market in the units of that class, the fair value of the units on that day as determined reasonably and in good faith by our board of directors.

Cumulative Common Unit Arrearage: The amount by which the minimum quarterly distribution for a quarter during the subordination period exceeds the distribution of available cash from operating surplus actually made for that quarter on a common unit, cumulative for that quarter and all prior quarters during the subordination period.

Current Market Price: For any class of units listed or admitted to trading on any national securities exchange as of any date, the average of the daily closing prices for the 20 consecutive trading days immediately prior to that date.

Eligible Holders: Individuals or entities either (a) subject to United States federal income taxation on the income generated by us or (b) in the case of entities that are pass-through entities for United States federal income taxation, all of whose beneficial owners are subject to United States federal income taxation on the income generated by us.

GAAP: Generally accepted accounting principles in the United States.

Greenfield Construction: The construction of an asset or system in an area where no previous facilities existed.

Interim Capital Transactions: The following transactions if they occur prior to liquidation:

(a) borrowings, refinancings or refundings of indebtedness and sales of debt securities (other than for items purchased on open account in the ordinary course of business) by NiSource Energy Partners, L.P. or any of its subsidiaries;

(b) sales of equity interests and debt securities of NiSource Energy Partners, L.P. or any of its subsidiaries;

(c) sales or other voluntary or involuntary dispositions of any assets of NiSource Energy Partners, L.P. or any of its subsidiaries (other than sales or other dispositions of inventory, accounts receivable and other assets in the ordinary course of business, and sales or other dispositions of assets as a part of normal retirements or replacements);

(d) the termination of interest rate swap agreements or commodity hedge contracts prior to the termination date specified therein;

D-2

(e) capital contributions; and

(f) corporate reorganizations or restructurings.

Local Distribution Company or LDC: LDCs are companies involved in the delivery of natural gas to consumers within a specific geographic area.

Mcf: One thousand cubic feet of natural gas. We have converted each of the throughput numbers from a heating value number to a volumetric number based upon the following conversion factor: 1 MMBtu = 1 Mcf.

MMBtu: One million British thermal units which is roughly equivalent to one Mcf.

MMcf: One million cubic feet of natural gas.

MMBtu/d: One million British Thermal Units per day.

MMcf/d: One million cubic feet per day.

Operating Expenditures: All of our expenditures and expenditures of our subsidiaries, including, but not limited to, taxes, payments to our general partner reimbursements of expenses incurred by our general partner on our behalf, non-pro rata purchases of units, repayment of working capital borrowings, interest payments, payments made in the ordinary course of business under interest rate swap agreements and commodity hedge contracts and maintenance capital expenditures, subject to the following:

(a) Payments (including prepayments) of principal of and premium on indebtedness will not constitute operating expenditures.

(b) Operating expenditures will not include:

(1) repayment of working capital borrowings deducted from operating surplus;

(2) expansion capital expenditures;

(3) payment of transaction expenses (including taxes) relating to interim capital transactions;

(4) distributions to unitholders; and

(5) non-pro rata purchases of units of any class made with the proceeds of an interim capital transaction.

Where capital expenditures consist of both maintenance capital expenditures and expansion capital expenditures, the general partner, with the concurrence of the conflicts committee, shall determine the allocation between the amounts paid for each.

Operating Surplus: For any period prior to liquidation, on a cumulative basis and without duplication:

(a) the sum of:

(1) an amount equal to $ million;

(2) all cash receipts of NiSource Energy Partners, L.P. and our subsidiaries for the period beginning on the closing date of our initial public offering and ending with the last day of that period, excluding cash receipts from (i) borrowings other than working capital borrowings, (ii) sales of equity and debt securities, (iii) sales received or other dispositions of assets outside the ordinary course of business, (iv) the termination of commodity hedge contracts or interest rate swap agreements prior to the termination date specified therein, (v) corporate reorganizations or restructurings, and (vi) capital contributions received;

(3) working capital borrowings made after the end of any prior period but on or before the date of determination of operating surplus for that period; less

D-3

(b) the sum of:

(1) operating expenditures of NiSource Energy Partners, L.P. and our subsidiaries for the period beginning on the closing date of our initial public offering and ending with the last day of that period (excluding the repayment of borrowings) and maintenance capital expenditures; and

(2) the amount of cash reserves that is established by our general partner to provide funds for future operating expenditures; provided, however, that disbursements made (including contributions to a partner of NiSource Energy Partners, L.P. and our subsidiaries or disbursements on behalf of a partner of NiSource Energy Partners, L.P. and our subsidiaries) or cash reserves established, increased or reduced after the end of that period but on or before the date of determination of available cash for that period shall be deemed to have been made, established, increased or reduced for purposes of determining operating surplus, within that period if our general partner so determines; and

(3) 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.

Peak Day: The highest level of throughput transported through a pipeline system on any given day.

Subordination Period: The subordination period will extend from the closing of the initial public offering until the first to occur of the following dates:

(a) The first day of any quarter beginning after March 31, 2009 in respect of which each of the following tests are met:

(1) distribution of available cash from operating surplus on each of the outstanding common units and subordinated units equaled or exceeded the sum of the minimum quarterly distributions on all of the outstanding common units and subordinated units for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date;

(2) the adjusted operating surplus generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of the minimum quarterly distributions on all of the outstanding common units, subordinated units and general partner units during those periods on a fully diluted basis; and

(3) there are no outstanding cumulative common units arrearages.

(b) The first date after we have earned and paid at least $0.45 per quarter (150% of the minimum quarterly distribution of $0.30 per quarter, which is $1.80 on an annualized basis) on each outstanding limited partner unit and general partner unit for any four consecutive quarters ending on or after March 31, 2008; and

(c) The date on which the general partner is removed as our general partner upon the requisite vote by the limited partners under circumstances where cause does not exist and units held by our general partner and its affiliates are not voted in favor of the removal.

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

Throughput: The volume of natural gas transported or passing through a pipeline, plant, terminal or other facility in an economically meaningful period of time.

Working Gas: Natural gas storage capacity that can be used for system operations or is available to be sold to the market as firm or interruptible storage capacity or as the storage component of no notice service.

D-4

12,500,000 Common Units

Representing Limited Partner Interests

PROSPECTUS

, 2007

Joint Book-Running Managers

Lehman Brothers

Citi

PART II

INFORMATION NOT REQUIRED IN PROSPECTUS


ITEM 13.	*Other Expenses of Issuance and Distribution*

Set forth below are the expenses (other than underwriting discounts and commissions) expected to be incurred in connection with the issuance and distribution of the securities registered hereby. With the exception of the Securities and Exchange Commission registration fee, the FINRA filing fee and The New York Stock Exchange listing fee, the amounts set forth below are estimates:


SEC registration fee	$	9,268
FINRA filing fee		30,688
New York Stock Exchange listing fee		*
Printing and engraving expenses		*
Legal fees and expenses		*
Accounting fees and expenses		*
Transfer agent and registrar fees		*
Third party asset valuation		*
Structuring fee		*

TOTAL	$	3,900,000


*		To be filed by amendment.


ITEM 14.	*Indemnification of Directors and Officers*

The section of the prospectus entitled “The Partnership Agreement — Indemnification” is incorporated herein by this reference. Reference is also made to the Underwriting Agreement filed as Exhibit 1.1 to this registration statement. Subject to any terms, conditions or restrictions set forth in the partnership agreement, Section 17-108 of the Delaware Revised Uniform Limited Partnership Act empowers a Delaware limited partnership to indemnify and hold harmless any partner or other person from and against all claims and demands whatsoever.


ITEM 15.	*Recent Sales of Unregistered Securities*

On December 5, 2007, in connection with the formation of NiSource Energy Partners, L.P., or the Partnership, the Partnership issued to (i) NiSource GP, LLC the 2% general partner interest in the Partnership for $40 and (ii) Columbia Energy Group, a subsidiary of NiSource Inc. the 98% limited partner interest in the Partnership for $1,960. The issuance was exempt from registration under Section 4(2) of the Securities Act. There have been no other sales of unregistered securities within the past three years.


ITEM 16.	*Exhibits and Financial Statement Schedules*

a. The following are documents filed as exhibits to this registration statement:


1	.1*	—	Form of Underwriting Agreement.
3	.1	—	Certificate of Limited Partnership of NiSource Energy Partners, L.P.
3	.2*	—	Form of First Amended and Restated Agreement of Limited Partnership of NiSource Energy Partners, L.P. (included as Appendix A to the Prospectus)
3	.3	—	Certificate of Formation of NiSource GP, LLC
3	.4*	—	Form of Amended and Restated Limited Liability Company Agreement of NiSource GP, LLC
5	.1*	—	Opinion of Vinson & Elkins LLP relating to the legality of the securities being registered.
8	.1*	—	Opinion of Vinson & Elkins LLP relating to tax matters.

II-1


10	.1*	—	Form of Credit Agreement
10	.2*	—	Form of Contribution, Conveyance and Assumption Agreement
10	.3*	—	Form of Omnibus Agreement
10	.4*	—	Form of Long Term Incentive Plan of NiSource Energy Partners, L.P.
21	.1*	—	Subsidiaries of NiSource Energy Partners, L.P.
23	.1	—	Consent of Deloitte & Touche LLP
23	.2*	—	Consent of Vinson & Elkins LLP (contained in Exhibit 5.1)
24	.1	—	Power of Attorney (included on signature page)


*		To be filed by amendment

b. Financial Statement Schedules

II-2

COLUMBIA GULF TRANSMISSION COMPANY

SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES


			Additions				Deductions for
	Balance at		Charged to		Charged to		Purposes for
	Beginning of		Costs and		Other		which Reserves		Balance at End
	Period		Expense		Accounts		were Created		of Period
	(in thousands)

December 31, 2006:
Allowance for doubtful accounts	$	1,158	$	—	$	497		83	$	1,572
Environmental reserves		168		—		—		12		156

	$	1,326	$	—	$	497	$	95	$	1,728
December 31, 2005:
Allowance for doubtful accounts	$	1,960	$	—	$	—	$	802	$	1,158
Environmental reserves		41		163		—		36		168

	$	2,001	$	163	$	—	$	838	$	1,326
December 31, 2004
Allowance for doubtful accounts	$	1,960	$	—	$	—	$	—	$	1,960
Environmental reserves		25		40		—		24		41

	$	1,985	$	40	$	—	$	24	$	2,001


ITEM 17.	*Undertakings*

The undersigned Registrant hereby undertakes:

(a) Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the Registrant pursuant to the provisions described in Item 14, or otherwise, the Registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the Registrant of expenses incurred or paid by a director, officer or controlling person of the Registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the Registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Act and will be governed by the final adjudication of such issue.

(b) To provide to the underwriter(s) at the closing specified in the underwriting agreements, certificates in such denominations and registered in such names as required by the underwriter(s) to permit prompt delivery to each purchaser.

(c) For purpose of determining any liability under the Securities Act, the information omitted from the form of prospectus filed as part of this Registration Statement in reliance upon Rule 430A and contained in the form of prospectus filed by the Registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this Registration Statement as of the time it was declared effective.

(d) For the purpose of determining any liability under the Securities Act, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

II-3

SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, as amended, the Registrant has duly caused this Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Merrillville, in the State of Indiana on December 21, 2007.

NISOURCE ENERGY PARTNERS, L.P.


	By:	NISOURCE GP, LLC, its general partner

By:

/s/ Christopher A. Helms

Name: Christopher A. Helms
Title: President and Chief Executive Officer

KNOW ALL MEN BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints Michael W. O’Donnell and Carrie J. Hightman, and each of them severally, his true and lawful attorney or attorneys-in-fact and agents, with full power to act with or without the others and with full power of substitution and resubstitution, to execute in his name, place and stead, in any and all capacities, any or all amendments (including pre-effective and post-effective amendments) to this Registration Statement and any registration statement for the same offering filed pursuant to Rule 462 under the Securities Act of 1933, as amended, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents and each of them, full power and authority to do and perform in the name of on behalf of the undersigned, in any and all capacities, each and every act and thing necessary or desirable to be done in and about the premises, to all intents and purposes and as fully as they might or could do in person, hereby ratifying, approving and confirming all that said attorneys-in-fact and agents or their substitutes may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Act of 1933, as amended, this registration statement has been signed below by the following persons in the capacities and on December 21, 2007.


Signature				Title


/s/ Robert C. Skaggs, Jr. Robert C. Skaggs, Jr.				Chairman of the Board

/s/ Christopher A. Helms Christopher A. Helms				President, Chief Executive Officer and Director (Principal Executive Officer)

/s/ Michael W. O’Donnell Michael W. O’Donnell				Executive Vice President, Chief Financial Officer and Director (Principal Financial and Accounting Officer)

/s/ James F. Thomas James F. Thomas				Executive Vice President, Chief Commercial Officer and Director

II-4

EXHIBIT INDEX


1	.1*	—	Form of Underwriting Agreement.
3	.1	—	Certificate of Limited Partnership of NiSource Energy Partners, L.P.
3	.2*	—	Form of First Amended and Restated Agreement of Limited Partnership of NiSource Energy Partners, L.P. (included as Appendix A to the Prospectus)
3	.3	—	Certificate of Formation of NiSource GP, LLC
3	.4*	—	Form of Amended and Restated Limited Liability Company Agreement of NiSource GP, LLC
5	.1*	—	Opinion of Vinson & Elkins LLP relating to the legality of the securities being registered.
8	.1*	—	Opinion of Vinson & Elkins LLP relating to tax matters.
10	.1*	—	Form of Credit Agreement
10	.2*	—	Form of Contribution, Conveyance and Assumption Agreement
10	.3*	—	Form of Omnibus Agreement
10	.4*	—	Form of Long Term Incentive Plan of NiSource Energy Partners, L.P.
21	.1*	—	Subsidiaries of NiSource Energy Partners, L.P.
23	.1	—	Consent of Deloitte & Touche LLP
23	.2*	—	Consent of Vinson & Elkins LLP (contained in Exhibit 5.1)
24	.1*	—	Power of Attorney (included on signature page)


*		To be filed by amendment


Delaware	4922	51-0658510
(State or Other Jurisdiction of Incorporation or Organization)	(Primary Standard Industrial Classification Code Number)	(I.R.S. Employer Identification Number)


	Per Common Unit	Total

Initial public offering price	$	$
Underwriting discount(1)	$	$
Proceeds to NiSource Energy Partners, L.P. (before expenses)


David P. Oelman Vinson & Elkins L.L.P. 1001 Fannin Street, Suite 2500 Houston, Texas 77002 (713) 758-2222		Joshua Davidson Christopher Arntzen Baker Botts L.L.P. 910 Louisiana Street Houston, Texas 77002 (713) 229-1234


(1)		Includes common units issuable upon exercise of the underwriters’ option to purchase additional common units.

(2)		Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(o).


•	We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our general partner, to enable us to make cash distributions to holders of our common units and subordinated units at the initial distribution rate under our cash distribution policy.

•	Our natural gas transportation operations are subject to regulation by federal agencies, including the Federal Energy Regulatory Commission, which could have an adverse impact on our ability to establish transportation rates that would allow us to recover the full cost of operating our pipelines, including a reasonable return, and our ability to make distributions to you.

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

•	Affiliates of NiSource Inc. are not limited in their ability to compete with us and are not obligated to offer us the opportunity to pursue additional assets or businesses, which could limit our commercial activities or our ability to acquire additional assets or businesses.

•	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 at a price that may be below the current market price, unless you are (1) an individual or entity subject to U.S. federal income taxation on the income generated by us or (2) an entity not subject to U.S. federal taxation on the income generated by us, but all of whose owners are subject to such taxation.

•	Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors.

•	You will experience immediate and substantial dilution of $16.41 in tangible net book value per common unit.

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


(1)		Excludes an aggregate structuring fee equal to 0.375% of the gross proceeds of this offering, or approximately $ , payable to Lehman Brothers Inc.