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Northeast Generation Co – ‘S-4’ on 12/6/01

On:  Thursday, 12/6/01   ·   Accession #:  912057-1-542226   ·   File #:  333-74636

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  As Of                Filer                Filing    For·On·As Docs:Size              Issuer               Agent

12/06/01  Northeast Generation Co           S-4                   35:4.7M                                   Merrill Corp/FA

Registration of Securities Issued in a Business-Combination Transaction   —   Form S-4
Filing Table of Contents

Document/Exhibit                   Description                      Pages   Size 

 1: S-4         Registration of Securities Issued in a              HTML   1.90M 
                          Business-Combination Transaction                       
 2: EX-1.1      Purchase Agreement                                    29    130K 
 3: EX-3.1      Certificate of Incorporation                           2     17K 
 4: EX-3.2      By-Laws                                                7     29K 
 5: EX-4.1      Indenture                                             75    343K 
 6: EX-4.2      First Supplemental Indenture                          95    318K 
 7: EX-4.3      Form of Series A-1 Bond                               10     34K 
 8: EX-4.4      Form of Series B-1 Bond                               10     36K 
 9: EX-4.5      Registration Rights Agreement                         24    107K 
10: EX-5.1      Opinion re: Legality                                   2     16K 
11: EX-10.1     Power Purchase and Sales Agreement                    44    112K 
23: EX-10.10    Interconnection Agreement With Wmeco                  47    182K 
24: EX-10.11    (800) 688 - 1933                                      59    249K 
25: EX-10.12    Purchase and Sales Agreement Wmeco                    57    239K 
26: EX-10.13    Form of Exchange Agent Agreement                       9     39K 
12: EX-10.2     Guaranty                                              10     41K 
13: EX-10.3     Consent and Agreement                                  8     39K 
14: EX-10.4     Security Agreement                                    17     68K 
15: EX-10.5     Form of Mortgage                                      22     87K 
16: EX-10.6     Management and Operation Agreement                    44    120K 
17: EX-10.6(1)  (800) 688 - 1933                                       2     16K 
18: EX-10.7     Service Contract                                       9     36K 
19: EX-10.7(1)  Renewal of Service Contract                            2     17K 
20: EX-10.8     Tax Allocation Agreement                               8     38K 
21: EX-10.8-1   First Amendment to Tax Allocation Agreement           11     41K 
22: EX-10.9     (800) 688 - 1933                                      47    181K 
27: EX-12       Ratio of Earnings to Fixed Charges                     1     13K 
28: EX-23.1     Consent of Arthur Andersen                             1     11K 
29: EX-23.3     (800) 688 - 1933                                       2±    15K 
30: EX-23.4     Consent of Pa Consulting Services                      2±    14K 
31: EX-25.1     Form T-1                                               7     26K 
32: EX-99.1     Letter of Transmittal                               HTML     71K 
33: EX-99.2     Notice of Guaranteed Delivery                       HTML     26K 
34: EX-99.3     Brokers Letter                                      HTML     16K 
35: EX-99.4     Client Letter                                       HTML     22K 


S-4   —   Registration of Securities Issued in a Business-Combination Transaction
Document Table of Contents

Page (sequential) | (alphabetic) Top
 
11st Page   -   Filing Submission
"Table of Contents
"Notice to New Hampshire Residents
"Forward-Looking Statements
"Prospectus Summary
"The Exchange Offer
"Summary of the Terms of the Exchange Bonds
"The Issuer
"Our Ownership
"Summary Selected Financial Data
"Risk Factors
"Use of Proceeds
"Capitalization
"Selected Financial Data
"Management's Discussion and Analysis of Financial Condition and Results of Operations
"Industry Overview
"NEPOOL Annual Capacity and Summer Peak Load
"Our Business
"Summary of the Independent Technical Consultant's Report
"Station Performance Statistics (Average, %)
"Projected Cash Flow Summary
"Projected Debt Service Coverage Ratios
"Summary of the Independent Market Consultant's Report
"Our Affiliates
"Select Energy Management of Load Obligations
"Regulation
"Management
"Certain Relationships and Related Transactions
"Summary of Certain Principal Agreements
"Description of the Exchange Bonds
"Federal Income Tax Considerations
"Erisa Considerations
"Plan of Distribution
"Ratings
"Independent Consultants
"Legal Matters
"Independent Public Accountants
"Where You Can Find More Information
"Index to Financial Statements
"Report of Independent Public Accountants
"Northeast Generation Company Balance Sheets
"Northeast Generation Company Statements of Income
"Northeast Generation Company Statement of Stockholder's Equity
"Northeast Generation Company Statements of Cash Flows
"NORTHEAST GENERATION COMPANY NOTES TO FINANCIAL STATEMENTS Nine Months Ended September 30, 2001 (Unaudited) Years Ended December 31, 2000 And 1999
"Segment Information Balance Sheets at September 30, 2001 (Unaudited) and December 31, 2000
"Segment Information Statements of Income
"Legal Notice
"Electronic Mail Notice
"Independent Technical Review for Northeast Generation Company Table of Contents
"Table 1-1. Station Characteristics
"Table 1-2. Station Performance Statistics (Average, %)
"Table 3-1: Basic Unit Data
"Figure 3-1
"Figure 3-2
"Figure 3-3
"Figure 3-4
"Figure 3-5
"Figure 3-6
"Northfield Mountain System O&M Expenses (All Values in Nominal $000)
"Northfield Mountain System Capital & O&M Project Expenses (Nominal $000's)
"Table 4-1. Housatonic Hydro System
"Figure 4-1
"Figure 4-2
"Figure 4-3
"Figure 4-4
"Figure 4-5
"Figure 4-6
"Figure 4-7
"Figure 4-8
"Figure 4-9
"Figure 4-10
"Figure 4-11
"Housatonic Hydro System O&M Expenses (All Values in thousands of Nominal dollars)
"Housatonic Hydro System Capital and O&M Project Expenses (All Values in Nominal $000)
"Table 5-1 Basic Data for the Eastern Hydro Stations
"Eastern Hydro System O&M Expenses (All Values in Nominal $000)
"Eastern Hydro System Capital & O&M Project Expenses (All Values in Nominal $000's)
"ICU Air Pollution Emission Limitations
"Figure 6-1. Connecticut River Flow vs Northfield Generation
"Table 6-1 High Flow Impact on Northfield Mountain Operations
"Figure 6-2. Connecticut River Flow vs Cabot
"Table 6-2. Approximate Impact of Water Availability on Generation
"Table 7-1. Year 2001 PPA Pricing
"Table 7-2-Approved Capital Expenditures under the MOA
"Tranche A Amortization Schedule
"Tranche B Amortization Schedule
"Table 8-1. Technical Assumptions
"Cash Flow Summary ($MM Unless Otherwise Noted) Base Case
"Northeast Generation Company Cash Flow Summary ($MM Unless Otherwise Noted) Low Fuel Case
"Northeast Generation Company Cash Flow Summary ($MM Unless Otherwise Noted) Overbuild Case
"Disclaimer
"Chapter 1 Introduction
"Chapter 2 Regional Competitive Power Market Structures
"Figure 2-1 New England Transmission System (1)
"Chapter 3 Approach to Market Price Forecasting
"Figure 3-1 Price vs. Load-PJM West, February 2000
"Figure 3-2 Approach to Developing Compensation for Capacity and Energy Prices
"Figure 3-3 Example Supply and Demand Curve
"Figure 3-4 PJM Hourly Energy Prices, Summer 1999
"Figure 3-5 PJM Hourly Energy Prices, Production-Cost Model, Summer 1999
"Figure 3-6 Two Different Approaches to Modeling Hourly Demand
"Figure 3-7 Dispatch Results Simulated by a Conventional Production-cost Model
"Table 3-1 Possible Target Generating Unit Profit Levels
"Figure 3-8 PHB Hagler Bailly's Market Valuation Process (MVP SM )
"Chapter 4 Assumptions
"Table 4-7 Reference Terminal Assignments for No. 2 Fuel Oil Analysis
"Table 4-8 NPCC/MAAC Delivered No. 2 Fuel Oil Price (real 2000 $/MMBtu)
"Table 4-9 NPCC/MAAC Delivered No. 6 Fuel Oil Price (real 2000 $/MMBtu)
"Table 4-10 Projected Average Annual Load Growth Rates
"Table 4-11 SO 2 Cost Curves (real 2000 $/ton)
"Table 4-12 NOx Cost Curves (real 2000 $/ton)
"Table 4-13 NEPOOL Nuclear Unit Retirements-2000 through 2020
"Table 4-14 NEPOOL Base Case Additions-2000 through 2002
"Table 4-15 New CC Generating Characteristics (real 2000 $)
"Table 4-16 Full Load Heat Rate Improvement (Btu/kWh)(1)
"Chapter 5 Market Price Forecasts
"Figure 5-1 NEPOOL Load and Resource Balance
"Table 5-1 NEPOOL Case 1 Compensation for Capacity Forecast (real 2000 $/kW-yr)
"Table 5-2 NEPOOL West Case 1 Energy and All-In Price Forecasts (real 2000 $/MWh)
"Figure 5-4 NEPOOL West Case 1 Energy, All-In, and Compensation for Capacity Forecasts (1)
"Table 5-3 NEPOOL Case 2 Compensation for Capacity Forecast (real 2000 $/kW-yr)
"Table 5-4 NEPOOL West Case 2 Energy and All-In Price Forecasts (real 2000 $/MWh)
"Figure 5-5 NEPOOL West Case 2 Energy, All-In, and Compensation for Capacity Forecasts(1)
"Table 5-5 NEPOOL Case 3 Incremental Merchant Plant Assumptions
"Table 5-6 NEPOOL Case 3 Compensation for Capacity Forecast (real 2000 $/kW-yr)
"Table 5-7 NEPOOL West Case 3 Energy and All-In Price Forecasts (real 2000 $/MWh)
"Figure 5-6 NEPOOL West Case 3 Energy, All-In, and Compensation for Capacity Forecasts(1)
"Table 5-8 NEPOOL West Case 1 Energy Price Forecasts(1) Volatility Adjusted, Energy Only Market
"Table 5-9 NGC Portfolio Revenues(1)-NEPOOL West Case 1 Volatility Adjusted, Energy Only Market ($M)
"Table 5-10 NEPOOL West Case 2 Energy Price Forecasts(1) Volatility Adjusted, Energy Only Market
"Table 5-11 NGC Portfolio Revenues(1)-NEPOOL West Case 2 Volatility Adjusted, Energy Only Market ($M)
"Table 5-12 NEPOOL Case 3 Energy Price Forecasts(1) Volatility Adjusted, Energy Only Market
"Table 5-13 NGC Portfolio Revenues(1)-NEPOOL West Case 3 Volatility Adjusted, Energy Only Market ($M)
"Table 5-14 Relative Risk of Case 1 NGC Portfolio Revenues ($/kW-yr)
"APPENDIX A PRICING AREAS NPCC/MAAC Pricing Areas
"NPCC/MAAC Utilities by Pricing Area
"Appendix B Regional Specific Coal Price Discussion
"Appendix C Transfer Capability
"Appendix D Generic Capacity Additions
"Table D-1 Generic Capacity Additions in NEPOOL (MW)
"Part Ii Information Not Required in Prospectus
"Signatures
"Power of Attorney
"Exhibit Index
"QuickLinks

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As filed with the Securities and Exchange Commission on December 6, 2001



SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549


FORM S-4

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933


NORTHEAST GENERATION COMPANY

(Exact Name Of Registrant As Specified In Its Charter)

Connecticut   4911   06-1533879
(State or Other Jurisdiction
of Incorporation)
  (Primary Standard Industrial
Classification Code Number)
  (I.R.S. Identification Number)

107 Selden Street
Berlin, Connecticut 06037
(860) 655-5154

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

GREGORY B. BUTLER
Vice President, Secretary And General Counsel
Northeast Utilities Service Company
107 Selden Street
Berlin, Connecticut 06037
(860) 655-3532

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


Copy To:

MARTIN L. BUDD, ESQ.
BONNIE J. ROE, ESQ.
Day, Berry & Howard LLP
One Canterbury Green
Stamford, Connecticut 06901
(203) 977-7000


    APPROXIMATE DATE OF COMMENCEMENT OF PROPOSED SALE TO THE PUBLIC: As soon as practicable after this Registration Statement becomes effective.


    If the securities being registered on this form are being offered in connection with the formation of a holding company and there is compliance with General Instruction G, check the following box: / /

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

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


CALCULATION OF REGISTRATION FEE


Title of Each Class of Securities
to be Registered

  Amount to
be Registered

  Proposed Maximum Offering
Price Unit(1)

  Proposed Maximum
Aggregate Offering
Price(1)

  Amount of
Registration Fee(2)


4.998% Series A-1 Senior Secured Bonds due 2005   $120,000,000   100%   $120,000,000   $28,680

8.812% Series B-1 Senior Secured Bonds due 2026   $320,000,000   100%   $320,000,000   $76,480

  Total   $440,000,000     $440,000,000   $105,160

(1)
Estimated solely for the purpose of calculating the registration fee in accordance with Rule 457(f) promulgated under the Securities Act of 1933.
(2)
Calculated pursuant to Rule 457(f) of the rules and regulations under the Securities Act of 1933.

    THE REGISTRANT HEREBY AMENDS THIS REGISTRATION STATEMENT ON SUCH DATE OR DATES AS MAY BE NECESSARY TO DELAY ITS EFFECTIVE DATE UNTIL THE REGISTRANT SHALL FILE A FURTHER AMENDMENT THAT SPECIFICALLY STATES THAT THIS REGISTRATION STATEMENT SHALL THEREAFTER BECOME EFFECTIVE IN ACCORDANCE WITH SECTION 8(a) OF THE SECURITIES ACT OR UNTIL THIS REGISTRATION STATEMENT SHALL BECOME EFFECTIVE ON SUCH DATE AS THE SECURITIES AND EXCHANGE COMMISSION, ACTING PURSUANT TO SAID SECTION 8(a), MAY DETERMINE.




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

SUBJECT TO COMPLETION, DATED            , 2001
PRELIMINARY PROSPECTUS

$440,000,000

LOGO

Exchange Offer for all Outstanding
4.998% Series A Senior Secured Bonds due 2005
8.812% Series B Senior Secured Bonds due 2026


THIS EXCHANGE OFFER WILL EXPIRE AT 5:00 P.M., NEW YORK CITY TIME,
ON [      ], 2002, UNLESS EXTENDED.


TERMS OF THE EXCHANGE OFFER

    See the "Description of the Exchange Bonds" section beginning on page 77 for more information about the bonds to be issued in this exchange offer.

    Investing in the bonds involves risks. See "Risk Factors" beginning on page 12.


    Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or passed upon the adequacy or the accuracy of this prospectus. Any representation to the contrary is a criminal offense.


Prospectus dated [      ], 2001.


    You should rely only on the information contained in this prospectus. We have not authorized anyone to provide you with different information. We are not making an offer of these securities in any state where the offer is not permitted. You should not assume that the information contained in this prospectus is accurate as of any date other than the date on the front of this prospectus.

    Each broker-dealer that receives exchange bonds for its own account pursuant to the exchange offer must acknowledge that it will deliver a prospectus in connection with any resale of such exchange bonds. The letter of transmittal states that by so acknowledging and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an "underwriter" within the meaning of the Securities Act of 1933. This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of exchange bonds received in exchange for old bonds acquired by such broker-dealer as a result of market-making activities or other trading activities. We have agreed to make this prospectus available to any broker-dealer for use in connection with any such resale for such period of time as is necessary to comply with applicable laws in connection with any resale of such exchange bonds. See "Plan of Distribution," beginning on page 108.



TABLE OF CONTENTS

 
  Page
Notice to New Hampshire Residents   ii
Forward-Looking Statements   ii
Prospectus Summary   1
Risk Factors   12
The Exchange Offer   20
Use of Proceeds   31
Capitalization   31
Selected Financial Data   32
Management's Discussion and Analysis of Financial Condition and Results of Operations   34
Industry Overview   38
Our Business   42
Summary of the Independent Technical Consultant's Report   52
Summary of the Independent Market Consultant's Report   56
Our Affiliates   57
Regulation   61
Management   67
Certain Relationships and Related Transactions   68
Summary of Certain Principal Agreements   70
Description of the Exchange Bonds   77
Federal Income Tax Considerations   103
Erisa Considerations   107
Plan of Distribution   108
Ratings   109
Independent Consultants   110
Legal Matters   110
Independent Public Accountants   110
Where You Can Find More Information   110
Index to Financial Statements   F-1
Appendices
  Appendix A: Independent Technical Consultant's Report
  Appendix B: Independent Market Consultant's Report

i



NOTICE TO NEW HAMPSHIRE RESIDENTS

    Neither the fact that a registration statement or an application for a license has been filed under Chapter 421-B of the New Hampshire Revised Statutes with the State of New Hampshire nor the fact that a security is effectively registered or a person is licensed in the State of New Hampshire constitutes a finding by the Secretary of State that any document filed under RSA 421-B is true, complete and not misleading. Neither any such fact nor the fact that an exemption or exception is available for a security or a transaction means that the Secretary of State has passed in any way upon the merits or qualifications of, or recommended or given approval to, any person, security, or transaction. It is unlawful to make, or cause to be made, to any prospective purchaser, customer, or client any representation inconsistent with the provisions of this paragraph.


FORWARD-LOOKING STATEMENTS

    This prospectus contains forward-looking statements, which give our current expectations of future events. You will recognize these statements because they do not strictly relate to historical or current facts. Such statements may use words such as "anticipate," "estimate," "expect," "project," "intend," "think," "believe," "will," "should" and other words or terms of similar meaning in connection with any discussion of our future performance. For example, these include statements relating to future actions, future performance, expenses and the impact of the capital markets on our liquidity. From time to time, we also may provide oral or written forward-looking statements in other material released to the public.

    Any or all of our forward-looking statements in this prospectus and in any other public statements we make may turn out to be incorrect. They can be affected by inaccurate assumptions or by known or unknown risks and uncertainties. Many factors, which cannot be predicted with certainty, will be important in determining our future results. Among these factors are:

ii


    As a result of these factors, actual future results may vary materially from our current expectations. Some of these factors are more fully discussed under the caption "Risk Factors," which begins on page 12. Please note that the factors we discuss in this prospectus are those we think could cause our actual results to differ materially from expected and historical results. Other factors besides those listed above or under "Risk Factors" could also adversely affect us.

iii



PROSPECTUS SUMMARY

    This summary contains basic information about us and this exchange offer but may not contain all the information that is important to you. For a more complete understanding of this exchange offer, we encourage you to read this entire document and the documents which we refer you to. The words "we," "our," "ours," "ourselves" and "us," and the term "Northeast Generation" all refer to Northeast Generation Company, the issuer of the bonds. The term "old bonds" refers, collectively, to the 4.998% Series A Senior Secured Bonds due 2005 and 8.812% Series B Senior Secured Bonds due 2026, issued on October 18, 2001. The term "exchange bonds" refers, collectively, to the 4.998% Series A-1 Senior Secured Bonds due 2005 and 8.812% Series B-1 Senior Secured Bonds due 2026, offered for exchange in this prospectus. You should carefully consider the information set forth under "Risk Factors," beginning on page 12. In addition, certain statements are forward-looking statements which involve risks and uncertainties. See "Forward-Looking Statements," beginning on page ii.


The Exchange Offer

Old Bonds   On October 18, 2001, we sold in a private transaction the old bonds, which consist of (1) $120 million aggregate principal amount of our 4.998% Series A Senior Secured Bonds due 2005, and (2) $320 million aggregate principal amount of our 8.812% Series B Senior Secured Bonds due 2026, to Salomon Smith Barney Inc., Barclays Capital Inc., and TD Securities (USA) Inc. These initial purchasers then sold the old bonds to institutional investors. Simultaneously with the initial sale of the old bonds, we entered into a registration rights agreement with Salomon Smith Barney Inc. as representative of the initial purchasers under which we agreed, among other things, to deliver this prospectus to you and to complete an exchange offer for the old bonds. See "The Exchange Offer—Purpose of the Exchange Offer," on page 20.

The Exchange Offer; Exchange
Bonds

 

We are offering to exchange up to (1) $120 million aggregate principal amount of our 4.998% Series A-1 Senior Secured Bonds due 2005 that have been registered under the Securities Act for a like aggregate principal amount of our Series A Senior Secured Bonds due 2005, and (2) $320 million aggregate principal amount of our 8.812% Series B-1 Senior Secured Bonds due 2026 that have been registered under the Securities Act for a like principal amount of our 8.812% Series B Senior Secured Bonds due 2026. The terms of the exchange bonds are identical in all material respects to the terms of the old bonds, except that the transfer restrictions, registration rights and related increased interest rate provisions applicable to the old bonds are not applicable to the exchange bonds.

 

 

Old bonds may be tendered only in denominations of $100,000 and integral multiples of $1,000 in excess thereof. Subject to the satisfaction or waiver of specified conditions, we will exchange the exchange bonds for all old bonds that are validly tendered and not withdrawn prior to the expiration of the exchange offer. We will cause the exchange to be effected promptly after the expiration of the exchange offer.

1



 

 

Upon completion of the exchange offer, there may be no market for the old bonds, and if you fail to exchange the old bonds, you may have difficulty selling them.

Resales of the Exchange Bonds

 

Based on interpretations by the staff of the Securities and Exchange Commission, which we refer to as the SEC, we believe that the exchange bonds issued in the exchange offer may be offered for resale, resold or otherwise transferred by you, without compliance with the registration and prospectus delivery requirements of the Securities Act, if you:

 

 

• acquire the exchange bonds in the ordinary course of your business;

 

 

• are not engaging in and do not intend to engage in a distribution of the exchange bonds;

 

 

• do not have an arrangement or understanding with any person to participate in a distribution of the exchange bonds;

 

 

• are not an affiliate of ours within the meaning of Rule 405 under the Securities Act; and

 

 

• are not a broker-dealer that acquired the old bonds directly from us.

 

 

If any of these conditions is not satisfied and you transfer any exchange bonds without delivering a proper prospectus or without qualifying for a registration exemption, you may incur liability under the Securities Act. We do not assume or indemnify you against this liability.

 

 

In addition, if you are a broker-dealer seeking to receive exchange bonds for your own account in exchange for old bonds that you acquired as a result of market-making or other trading activities, you must acknowledge that you will deliver a prospectus in connection with any offer to resell, resale or other transfer of the exchange bonds that you receive in the exchange offer. See "Plan of Distribution," beginning on page 108.

Expiration Date

 

The exchange offer will expire at 5:00 p.m., New York City time, on [          ], 2002, unless we extend it.

Withdrawal

 

You may withdraw the tender of your old bonds at any time prior to the expiration of the exchange offer. We will return to you any of your old bonds that are not accepted for exchange for any reason, without expense to you, promptly after the rejection of the tender or the expiration or termination of the exchange offer.

Consequences of Failing to Exchange Your Old Bonds

 

The exchange offer satisfies our obligations and your rights under the registration rights agreement. After the exchange offer is completed, you will not be entitled to any registration rights with respect to your old bonds.

2



 

 

Therefore, if you do not exchange your old bonds, you will not be able to reoffer, resell or otherwise dispose of your old bonds unless:

 

 

• you comply with the registration and prospectus delivery requirements of the Securities Act; or

 

 

• you qualify for an exemption from those Securities Act requirements.

 

 

These conditions may adversely affect the market price of your old bonds.

Interest on the Exchange Bonds and the Old Bonds

 

Our Series A-1 bonds will bear interest at the annual rate of 4.998%. Our Series B-1 bonds will bear interest at the annual rate of 8.812%. Interest will be payable semi-annually on the exchange bonds each April 15 and October 15. Interest on the exchange bonds will accrue from October 18, 2001, the date of issuance of the old bonds, and will first be paid on the exchange bonds on the first April 15 or October 15 following the date the exchange offer is completed. If the exchange offer is not completed before interest has been paid on the old bonds, interest on the exchange bonds will accrue from the last date on which interest was paid on the old bonds. No interest will be paid in connection with the exchange. No interest will be paid on the old bonds following their acceptance for exchange. See "Description of the Exchange Bonds," beginning on page 77.

Conditions to the Exchange Offer

 

The exchange offer is subject to various conditions. We reserve the right to terminate or amend the exchange offer at any time before the expiration date if various specified events occur. The exchange offer is not conditioned upon any minimum principal amount of outstanding old bonds being tendered. See "The Exchange Offer—Conditions of the Exchange Offer," on page 28.

Exchange Agent

 

The Bank of New York.

Procedures for Tendering Old Bonds

 

If you wish to tender your old bonds, you must cause the following to be transmitted to and received by the exchange agent no later than 5:00 p.m., New York City time, on the expiration date of the exchange offer:

 

 

• a confirmation of a book-entry transfer of the tendered old bonds into the exchange agent's account at The Depository Trust Company, which we refer to as DTC;

 

 

• a properly completed and duly executed letter of transmittal in the form accompanying this prospectus (with any required signature guarantees) or, at the option of the tendering holder in the case of a book-entry tender, an agent's message instead of the letter of transmittal; and

3



 

 

• any other documents required by the letter of transmittal.

Guaranteed Delivery Procedures

 

If you wish to tender your old bonds and you cannot complete procedures for book-entry transfer or cause the old bonds or any other required documents to be transmitted to and received by the exchange agent before 5:00 p.m., New York City time, on the expiration date, you may tender your old bonds according to the guaranteed delivery procedures described in this prospectus under the heading "The Exchange Offer—Guaranteed Delivery Procedures," beginning on page 26.

Special Procedures for Beneficial Owners

 

If you are the beneficial owner of old bonds that are registered in the name of your broker, dealer, commercial bank, trust company or other nominee, and you wish to participate in the exchange offer, you should promptly contact the person in whose name your outstanding old bonds are registered and instruct that person to tender your old bonds on your behalf. See "The Exchange Offer—Procedures for Tendering," beginning on page 24.

Representations of Tendering Holders

 

By tendering old bonds pursuant to the exchange offer, you will, in addition to other customary representations, represent to us that:

 

 

• you are acquiring any exchange bonds you receive in the exchange offer in the ordinary course of your business;

 

 

• you do not have any arrangement or understanding with any person to participate in the distribution of the exchange bonds in violation of the Securities Act, within the meaning of the Securities Act;

 

 

• you are not an affiliate of ours within the meaning of Rule 405 of the Securities Act;

 

 

• if you are not a broker-dealer, you are not engaged in, and do not intend to engage in, the distribution of the exchange bonds; and

 

 

• if you are a broker-dealer, you will receive the exchange bonds in exchange for bonds that you acquired as a result of your market-making or other trading activities, for your own account and you will deliver a prospectus in connection with any resale of the exchange bonds you receive.

Acceptance of Old Bonds and Delivery of Exchange Bonds

 

Subject to the satisfaction or waiver of the conditions to the exchange offer, we will accept for exchange any and all old bonds that are properly tendered and not withdrawn prior to 5:00 p.m., New York City time, on the expiration date of the exchange offer. We will cause the exchange to be effected promptly after the expiration of the exchange offer.

4



Federal Income Tax Considerations

 

The exchange of old bonds for exchange bonds pursuant to the exchange offer generally will not be a taxable event for United States federal income tax purposes. See "Federal Income Tax Considerations," beginning on page 103.

Appraisal or Dissenters' Rights

 

You will have no appraisal or dissenters' rights in connection with the exchange offer.

Use of Proceeds

 

We will not receive any proceeds from the issuance of exchange bonds pursuant to the exchange offer. We will pay expenses incident to the exchange offer to the extent indicated in the registration rights agreement.


Summary of the Terms of the Exchange Bonds

    The terms of the exchange bonds will be identical in all material respects to the terms of the old bonds, except that the transfer restrictions, registration rights and related interest rate increase provisions applicable to the old bonds are not applicable to the exchange bonds. The exchange bonds will evidence the same debt as the old bonds. The exchange bonds and the old bonds will be governed by the same indenture. For more complete information about the exchange bonds, see "Description of the Exchange Bonds," beginning on page 77.


Issuer

 

Northeast Generation Company.

Exchange Bonds

 

We will offer the exchange bonds in two series: up to $120 million aggregate principal amount of 4.998% Series A-1 Senior Secured Bonds due 2005, and up to $320 million aggregate principal amount of 8.812% Series B-1 Senior Secured Bonds due 2026.

Interest

 

Interest will accrue from October 18, 2001 at a rate of 4.998% per year on the Series A-1 Senior Secured Bonds and at a rate of 8.812% per year on the Series B-1 Senior Secured Bonds. Interest will be payable semiannually in arrears on April 15 and October 15 of each year, beginning on April 15, 2002.

Maturity

 

Our Series A-1 bonds will mature on October 15, 2005 and our Series B-1 bonds will mature on October 15, 2026.

Average Life

 

The average life is 2.4 years for the Series A and Series A-1 Senior Secured Bonds due 2005 and 18.9 years for the Series B and Series B-1 Senior Secured Bonds due 2026.

Ranking

 

The exchange bonds will be senior obligations and rank equally in right of payment to all our existing and future senior secured indebtedness.

Ratings

 

The old bonds are rated, and the exchange bonds are expected to be rated, "Baa2" by Moody's Investors Service, Inc., "BBB-" by Standard & Poor's Ratings Services and "BBB-" by Fitch, Inc.

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Collateral

 

The exchange bonds will be secured by a security interest in all our existing real and tangible personal property and our rights under our power sales agreement with Select Energy through December 31, 2005, subject, in certain cases, to release on an item by item basis at the time of any permitted disposition of such property or if required in connection with any purchase money financing or renewal of any purchase money financing.

Debt Service Reserve Account

 

We are required to maintain a debt service reserve account for the benefit of the holders of the exchange bonds, unless each of Moody's, S&P and Fitch indicates that it will maintain investment grade ratings without a funded debt service reserve account. The debt service reserve account is funded and must be funded following the end of each fiscal quarter in an amount sufficient to pay the projected principal and interest due on all series of bonds then outstanding for the next six months (the debt service reserve requirement). The debt service reserve requirement may be satisfied by the deposit of cash or securities with the trustee, the delivery of a letter of credit, the delivery of a guarantee of Northeast Utilities or another acceptable guarantor or any combination of the foregoing.

Optional Redemption

 

We may redeem the exchange bonds, in whole or in part, at any time at redemption prices discussed under the caption "Description of the Exchange Bonds—Redemption and Repurchase—Optional Redemption," on page 82.

Mandatory Redemption

 

If we receive casualty insurance proceeds or other amounts (other than proceeds of business interruption or liability insurance) in excess of $10 million with respect to an event of loss, and we have either determined that the repair, restoration, rebuilding or replacement of the affected property is not commercially feasible or have decided not to repair, restore, rebuild or replace the affected property, and as a result a material adverse effect could be reasonably expected to occur, then we will be required to use such proceeds or other amounts in excess of $10 million to redeem the exchange bonds, in whole or in part, on a pro rata basis at a redemption price equal to 100% of the principal amount plus accrued interest.

Certain Covenants

 

The indenture limits our ability to, among other things, pay dividends, engage in mergers, consolidations or similar transactions, dispose of collateral, create liens or incur additional indebtedness.

Agreement with Select Energy

 

We will not be permitted to modify our power sales agreement with Select Energy in any way that is adverse to the interests of the bondholders, except as required by any regulatory authority. We are not required to renew or extend our agreement beyond December 31, 2005, nor are we restricted as to the permitted terms of any extension or renewal of our agreement. Northeast Utilities has agreed to guarantee the performance obligations of Select Energy under the power sales agreement, but has no obligation to guarantee the performance of Select Energy under any renewal or extension of this agreement beyond its expiration on December 31, 2005.

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Trustee

 

The Bank of New York.

Form of the Exchange Bonds

 

The exchange bonds will be represented by one or more permanent global securities in registered form deposited with The Bank of New York, as custodian, for the benefit of DTC. You will not receive bonds in registered form unless one of the events set forth under the heading "Description of the Exchange Bonds—Book-Entry Transfer" on page 26 occurs. Instead, beneficial interests in the exchange bonds will be shown on, and transfers of these interests will be effected only through, records maintained in book-entry form by DTC and its participants.

Absence of a Public Market for the Exchange Bonds

 

There has been no public market for the old bonds, and no active public market for the exchange bonds is currently anticipated. We do not intend to apply for a listing of the exchange bonds on any securities exchange or inclusion in any automated quotation system. We cannot make any assurances regarding the liquidity of the market for the exchange bonds, the ability of holders to sell their exchange bonds or the price at which holders may sell their exchange bonds.

Governing Law

 

The exchange bonds and documents related to the issuance of the exchange bonds will be governed by and construed in accordance with the laws of the State of New York.

Risk Factors

 

You should carefully consider all of the information set forth in this prospectus and, in particular, you should evaluate the specific factors set forth under "Risk Factors," beginning on page 12.

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The Issuer

    We are a major source of pumped storage and conventional hydroelectric power generation in the northeastern United States and an indirect, wholly-owned subsidiary of Northeast Utilities. We are an "exempt wholesale generator" under Section 32 of the Public Utility Holding Company Act of 1935, which means we are exempt from regulation as an "electric utility" under the provisions of the Public Utility Holding Company Act. We are the generation company of Northeast Utilities' deregulated energy business.

    Our Northfield Mountain pumped storage facility ("Northfield") is the largest pumped storage hydroelectric power generation facility in New England. Pumped storage facilities can transform off-peak energy into on-peak energy by pumping water into an upper reservoir during hours of low energy demand, when energy prices are relatively low, and releasing the water to generate power during hours of high energy demand, when energy prices are relatively high. By contrast, conventional hydroelectric power generation relies on the natural flow of the river through a turbine to generate electricity.

    We were formed for the purpose of acquiring generation facilities. In March 2000, we acquired the pumped storage and conventional hydroelectric facilities owned by our affiliates, The Connecticut Light & Power Company ("Connecticut Light & Power") and Western Massachusetts Electric Company ("Western Massachusetts Electric") in a competitive public auction mandated by Connecticut's comprehensive electric utility restructuring legislation.

    Our pumped storage facilities provide approximately 1,110 megawatts of generating capacity while our remaining facilities provide approximately 179 megawatts of generating capacity. The facilities are organized into three separate systems described below:

    We currently sell all our energy and capacity to our affiliate, Select Energy, which is engaged in the power marketing and trading business in the region comprised of the New England Power Pool ("NEPOOL"), the New York Independent System Operator and the Pennsylvania-New Jersey-Maryland Interconnection (the "PJM Power Pool").

    Our contract with Select Energy extends through December 2005. About 85% of our revenues from this contract (including all of the revenues from Northfield) are in the form of pre-determined, fixed monthly payments based on the capacity of specified facilities. The remaining 15% of the revenues are in the form of monthly payments at pre-determined rates per unit of actual energy output. We currently derive approximately 80% to 85% of our revenues from Northfield.

    We currently plan to renew the agreement with Select Energy after 2005. If our agreement with Select Energy were to terminate, however, our plan would be to aggressively market our power at times of peak usage and maximize revenues from the quick-start and reserve capabilities of our pumped storage facilities. We plan to pursue growth opportunities in the northeastern United States through the

8


acquisition of existing power plants and the development of new plants; however, our ability to do so is limited by capital and regulatory constraints.

    S&W Consultants, Inc. ("S&W"), an independent technical consultant, prepared a comprehensive independent technical report, dated October 11, 2001, concerning our facilities. A copy of the report is included as Appendix A to this prospectus. For a summary of this report, see "Summary of the Independent Technical Consultant's Report," beginning on page 52.

    PA Consulting Services, Inc. ("PA"), an independent power market consultant formerly known as PHB Haigler Bailly, Inc., prepared the independent market consultant's report, dated December 20, 2000, a copy of which is included as Appendix B to this prospectus. For a summary of this report, see "Summary of the Independent Market Consultant's Report," beginning on page 56.

    Our headquarters and principal executive offices are located at 107 Selden Street, Berlin, Connecticut, 06037. Our telephone number is (860) 665-5154.


Our Ownership

    Our indirect parent company, Northeast Utilities, is a publicly-owned holding company registered under the Public Utility Holding Company Act of 1935. Through its subsidiaries, Northeast Utilities engages in the generation, transmission, distribution and sale of electricity and natural gas to customers in the northeast region of the United States. The Northeast Utilities system distributes power supplying approximately 30% of New England's electric power needs. The Northeast Utilities system is one of the twenty-five largest electric utility systems in the United States measured by revenues. Through NU Enterprises, Inc., Northeast Utilities owns a number of deregulated energy and telecommunications related businesses, including us.

    The chart below illustrates the corporate relationships among us, Northeast Utilities, NU Enterprises and certain other direct and indirect subsidiaries of Northeast Utilities. Our affiliate, Northeast Generation Services Company ("Northeast Generation Services"), provides us with operational and management services. Corporate services are supplied by Northeast Utilities Service Company. Northeast Utilities is the parent company of Connecticut Light & Power, Western Massachusetts Electric, Public Service Company of New Hampshire and other regulated utilities.

CHART

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Summary Selected Financial Data

    The following table sets forth summary selected historical financial data for Northeast Generation. Northeast Generation was incorporated on December 28, 1998, but had no significant assets or operations prior to the acquisition of its facilities on March 14, 2000. The selected historical financial data have been derived from the audited and unaudited historical financial statements of Northeast Generation included elsewhere in this prospectus. The financial data as of and for the periods ended September 30, 2001 and September 30, 2000 are unaudited, but in the opinion of management reflect all material adjustments necessary, consisting only of normal and recurring adjustments, to present fairly our financial position as of September 30, 2001 and September 30, 2000 and the results of operations for the periods then ended. The information set forth below should be read in conjunction with the section of this prospectus captioned "Management's Discussion and Analysis of Financial Condition and Results of Operations" beginning on page 34 and our historical financial statements and the accompanying notes included in this prospectus.

 
  Nine months
ended
September 30, 2001
(unaudited)

  Nine months ended
September 30, 2000
(unaudited)

  Period from inception
(December 28, 1998) to
December 31,
2000

 
  (in thousands except for ratios)

Statement of Income Data (for the period):                  
Operating revenues   $ 99,400   $ 75,589   $ 108,473
Operating expenses     47,198     32,761     49,731
   
 
 
Operating income     52,202     42,828     58,742
Other income, net     1,036     614     1,061
Interest expense     19,537     25,131     36,543
   
 
 
Net income   $ 33,701   $ 18,311   $ 23,260
   
 
 
Balance Sheet Data (at the end of period):                  
Total assets(1)   $ 439,291   $ 461,573   $ 461,061
Total liabilities     359,683     422,034     413,426
Stockholder's equity(1)(2)     79,608     39,539     47,635

Other Data (for the period):

 

 

 

 

 

 

 

 

 
EBITDA(3)   $ 83,842   $ 59,932   $ 83,355
Capital expenditures     8,310     554     1,394
Ratio of earnings to fixed charges(4)     3.89x     2.21x     2.06x

(1)
Because our facilities were acquired from affiliates, they are required to be carried on our balance sheets at their book values on the balance sheets of Connecticut Light & Power and Western Massachusetts Electric prior to our acquisition of the facilities, less depreciation, rather than the cost we incurred to acquire the facilities. If the facilities were carried at their purchase price, less depreciation, our total assets would be $899,407 as of September 30, 2001 and our stockholder's equity as of September 30, 2001 would be $539,724. See note 5 to our financial statements included elsewhere in this prospectus.

(2)
On October 18, 2001, Northeast Generation used $75,000 of the proceeds of the offering to pay a dividend to, and repurchase certain shares of its stock from, its immediate parent, NU Enterprises, Inc. For further information, see "Capitalization," on page 31.

(3)
"EBITDA" refers to earnings before interest, taxes, depreciation and amortization. Information concerning EBITDA is presented here as a measure of ability to service debt and not as a measure of operating results. EBITDA may not be comparable to similarly titled measures by other

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(4)
On a pro forma basis, after giving effect to the repayment of the bank debt and the issuance of the old bonds as if they had occurred on the first day of each period, the ratio of earnings to fixed charges would be 2.96 for the nine months ended September 30, 2001, 2.17 for the nine months ended September 30, 2000 and 1.10 for the period from inception to December 31, 2000.

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RISK FACTORS

    You should carefully consider the risks described below as well as other information contained in this prospectus. Each of the following risks, if they were to occur, could have a material adverse effect on our business and financial performance and could result in a loss or a decrease in the value of your investment.

RISKS RELATING TO THE EXCHANGE OFFER

You may have difficulty selling the old bonds that you do not exchange.

    If you do not exchange your old bonds for the bonds offered in this exchange offer, you will continue to be subject to the restrictions on the transfer of your bonds. Those transfer restrictions are described in the first supplemental indenture governing the bonds and in the legend contained on the old bonds, and arose because we originally issued the old bonds under exemptions from, and in transactions not subject to, the registration requirements of the Securities Act.

    In general, you may offer or sell your old bonds only if they are registered under the Securities Act and applicable state securities laws, or if they are offered and sold under an exemption from those requirements. We do not intend to register the old bonds under the Securities Act.

    If a large number of old bonds are exchanged for bonds issued in the exchange offer, it may be more difficult for you to sell your unexchanged bonds. In addition, if you do not exchange your old bonds in the exchange offer, you will no longer be entitled to have those bonds registered under the Securities Act.

    See "The Exchange Offer—Consequences of Failure to Exchange Old Bonds" on page 30 for a discussion of the possible consequences of failing to exchange your bonds.

RISKS RELATED TO OUR BUSINESS OPERATIONS

The operation of our facilities involves risks.

    The operation of power generation facilities involves many operating risks, including:

    Any one or more of these operating risks could materially and adversely affect our business and financial performance.

Our operating results may differ from the projections of future performance of our facilities.

    The independent technical consultant's report findings are based upon our envisioned operating plans and associated capital, operating and maintenance budgets. If we were to significantly change the budgets for capital and operations and maintenance, or the operating plans, our ability to achieve

12


future operating results might not be the same as currently projected. In addition, any changes to the operation of our facilities due to unforeseen future regulatory and licensing requirements could similarly affect our projected results. The independent technical consultant's projection of our revenues depends on variables like fuel price forecasts, future supply and demand situations, the structure of the electricity market and price volatility. Our actual revenues could differ significantly from the revenues projected in the independent technical consultant's report.

    No inference should be made about the likely existence of any particular future set of facts or circumstances. Potential investors should carefully review the independent technical consultant's report and the independent market consultant's report, as well as the qualifications in those reports. The projections are not necessarily indicative of our future performance or the performance of any individual facility. We do not intend to provide investors with any revised projections or analyses of the differences between the projections and actual operating results.

During the term of our contract with Select Energy, we will not be able to take advantage of ancillary service revenues or increases in the price of energy.

    Because of our agreement with Select Energy, we are currently unable to take advantage of increases in the market price for electricity, and we will not be able to recoup additional costs through price increases for sales. While this agreement is in effect, we are not able to derive profits from the quick-start or reserve capabilities of Northfield. Our agreement with Select Energy does not include automatic price adjustment provisions to cover increased costs or capital improvements, although it permits us to discuss with Select Energy the need for capital additions to our facilities and to amend the agreement for changes in terms, conditions or price to reflect mutually agreed upon capital additions. Because of the agreement with Select Energy, we may not be able to take advantage of opportunities for growth or profit that are available to our competitors.

    Our agreement with Select Energy also obligates us to negotiate a renewal of the agreement with Select Energy in good faith by December 2004. Due to our affiliate relationship with Select Energy, future pricing and other contractual arrangements with Select Energy may not be negotiated at arm's length and may not reflect market prices or terms and conditions.

If our contractual arrangements with Select Energy were to terminate, we would face a number of additional risks related to competing in a changing market for electric power.

    If our contractual arrangements with Select Energy were to terminate:

    It is currently impossible to predict what the long-term consequences of a termination of our contract with Select Energy would be.

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Our facilities may require significant capital expenditures for maintenance and updating.

    The generating units at many of our smaller conventional hydroelectric facilities were constructed 70 to 80 years ago, and although they have been updated and modernized through the years, significant capital expenditures may be required to maintain operations. Our financial projections generally include those capital expenditures that we currently believe will be required and for which we have budgeted, but we cannot assure you that additional expenditures will not be necessary or that funds will be available when needed. Spare parts for older equipment also may be difficult to obtain, which could cause delays in making repairs and outages in our facilities.

Weather and climatic conditions beyond our control could adversely affect our operations.

    Any weather or climatic conditions that affect the amount of water in the rivers feeding our conventional hydroelectric power stations may adversely affect our ability to generate power at those stations. This is especially true at stations that operate in "run-of-river" condition and depend upon the natural flow of water for power generating operations.

We may acquire generating facilities in the future that could significantly diversify our existing generation portfolio and increase our exposure to risk.

    While our generating assets currently consist of pumped storage and conventional hydroelectric facilities, and one internal combustion generator, we may acquire other types of generating assets, such as coal or natural gas burning facilities. Such facilities are typically subject to greater environmental regulation and greater risk of liability for environmental clean-up. In addition, such facilities could have significantly different cost profiles and operating risks than our existing facilities.

We have limited experience operating our facilities in a market-based competitive environment.

    We have been operating our facilities as the deregulated generating company for the Northeast Utilities system only since we acquired them in March 2000. Because of our agreement with Select Energy, we have no direct experience dealing with price fluctuations and other uncertainties connected with selling electricity directly into competitive markets. We cannot assure you that we would be successful in operating our facilities in a competitive environment in which energy rates are set by market forces if we terminate or do not renew our agreement with Select Energy.

    Our facilities were operated as integrated parts of regulated utilities prior to our acquisition of them, and their output of electricity was sold at prices based upon rates set by regulatory authorities. We cannot assure you that we will achieve contract terms in a competitive environment that will be sufficient to support our indebtedness, the cost of operating our facilities and the capital expenditures needed to maintain them.

The sale of power by Select Energy depends on power transmission facilities that it does not own or control. If these facilities fail to provide adequate transmission capacity, Select Energy may not be able to deliver our wholesale electric power products to its customers, which could affect Select Energy's ability to meet its payment obligations to us under our contract with Select Energy. We will be subject to the same delivery risk directly if our agreement with Select Energy terminates.

    Select Energy depends on transmission and distribution facilities owned by both affiliated and unaffiliated electric utilities to deliver power to its customers. If the transmission infrastructure is inadequate, Select Energy's recovery of costs and profits may be limited. The imposition of restrictive transmission price regulation may reduce the incentive for transmission companies to invest in expansion of transmission infrastructure.

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    Currently, under the terms of our contract with Select Energy, we are responsible for delivering electricity to delivery points that are, for the most part, located at our facilities. These delivery points are all owned and/or operated by either Connecticut Light & Power or Western Massachusetts Electric. We utilize the delivery points pursuant to separate interconnection agreements with each of Connecticut Light & Power or Western Massachusetts Electric. If the transmission or interconnection to the delivery point failed, our ability to sell and deliver our products to Select Energy would be disrupted.

    The Federal Energy Regulatory Commission ("FERC") has issued power and gas transmission initiatives that require electric and gas transmission services to be offered separately from commodity sales. Although these initiatives are designed to encourage wholesale market transactions for electricity and gas, there is the potential that fair and equal access to transmission systems will not be available. We cannot predict the timing or scope of industry response to these initiatives. We also cannot predict the adequacy of the expansion of transmission facilities in specific markets where such expansion may be required as a result of these initiatives and on which we will rely.

We face ongoing changes in the U.S. electric utility industry which could increase the number of low cost competitors.

    The electric utility industry in the United States is currently experiencing increasing competitive pressures, primarily in wholesale markets, as a result of consumer demand, technological advances, greater use of natural gas for new power generation, the restructuring of wholesale power markets, legislative and regulatory activity and other factors. FERC has implemented and continues to propose regulatory changes to increase access to the transmission grid by utility and non-utility purchasers and sellers of electricity. This could increase the ability of low-cost producers of electricity to transmit their electricity to areas that currently have higher electricity costs, thereby generally driving down the cost of electricity. In addition, a number of states have implemented methods to introduce and promote retail competition. Industry deregulation and privatization could continue to facilitate the current trend towards consolidation in the utility industry, creating larger potential competitors. Deregulation and privatization could also increase the number of existing competitors by encouraging the disaggregation of vertically integrated utilities into separate generation, transmission and distribution businesses.

    If the price of power declines as a result of increased competition or new technologies during the period of our contract with Select Energy, the profit margins of Select Energy could be negatively affected. After the initial contract period expires on December 31, 2005, if our contract with Select Energy is not renewed on similar terms, our profit margins could be negatively affected by a decline in power prices. Under these circumstances, we might not achieve our targeted revenues and earnings levels.

    Proposals have been introduced in Congress to repeal the Public Utility Holding Company Act. FERC and the SEC have publicly indicated support for such repeal. If the repeal of the Public Utility Holding Company Act occurs, either separately or as part of federal legislation designed to encourage the broader introduction of wholesale and retail competition, additional changes in the electricity market could occur, and additional competitors could emerge, including large corporations that are at present limited in competitive generating activities by the Public Utility Holding Company Act.

We may face increased competition due to the construction and development of new and more efficient energy generation facilities.

    While demand for electric energy services is generally increasing throughout the United States, the rate of construction and development of new, more efficient electric generation facilities may exceed increases in demand in some regional electric markets, including the northeastern United States. The start-up of new facilities in the regional markets in which we have facilities could increase competition

15


in the wholesale power market in these regions. In addition, new technologies could be developed that reduce the competitiveness of our facilities and lessen the competitive advantages of Northfield. A decline in energy prices or in the prices of quick-start and reserve ancillary services provided by Northfield could negatively affect the profit margins of Select Energy during the term of our contract with Select Energy.

    If the Select Energy contract were to terminate, our profit margins could be affected by changes in the demand for our ancillary services or by a decline in the spread between peak and off-peak energy prices.

Our business is subject to substantial regulation and permitting requirements and may be adversely affected by our inability to comply with existing regulations or requirements or changes in applicable regulations or requirements.

    Our business could be materially and adversely affected by statutory or regulatory changes or judicial or administrative interpretations of existing statutes, regulations or licenses that impose more comprehensive or stringent requirements on us.

    Some of our hydroelectric generating facilities are covered by FERC project licenses issued under Part I of the Federal Power Act. The licenses expire on various dates over the next two decades; renewal of FERC licenses will be required for Northfield and the other facilities in the Northfield Mountain-Connecticut River System in 2018. We cannot assure you that any license will be renewed or that the terms and conditions of a new license will be as favorable to us as the licenses that have existed to date. A FERC relicensing proceeding gives the current owner an opportunity to obtain a new or renewed license for the generating facilities. Such proceedings can impose additional conditions on the generating facilities that were not included in the original license, such as the construction of fish passages or other actions to protect fish and wildlife. These conditions could result in increased costs or reduced productivity, which could have a material adverse effect on our financial performance.

Our business operates in the deregulated segments of the electric power industry created by restructuring initiatives at both state and federal levels. If the present trend towards competitive restructuring of the electric power industry is reversed, discontinued or delayed, our business prospects and financial condition could be adversely affected by efforts to control price volatility through re-regulation or price controls.

    Some restructured markets have recently experienced supply problems and price volatility. These supply problems and volatility have been the subject of a significant amount of press coverage, much of which has been critical of the restructuring initiatives. In some of these markets, including California, interested parties have made proposals to re-regulate areas of these markets that have been previously deregulated. FERC has imposed limited price controls in several Western states. Price ceilings apply under certain limited operating conditions in New England through the fall of 2001 and are likely to be continued thereafter. Other proposals to re-regulate in our industry may be made, and legislative or other attention to the electric power industry restructuring process may cause the process to be delayed, discontinued or reversed in the states in which we currently, or may in the future, operate. If the competitive restructuring of the wholesale and retail power markets is delayed, discontinued or reversed, the business prospects and financial condition of Select Energy could be materially adversely affected.

Our business is subject to substantial regulation relating to the environment, and the cost of compliance with environmental laws could affect our cash flow and profitability.

    We are subject to extensive environmental and land use regulation by federal, state and local authorities. We are required to comply with numerous laws, regulations and ordinances, and to obtain

16


numerous licenses and permits in our operations. These laws, regulations and ordinances address, among other things, the discharge of effluents into the water, emissions into the air, the use of water, wetlands preservation and the protection of endangered species. We have incurred and will continue to incur significant additional costs because of our compliance with these requirements. If we fail to comply with them, we could be subject to civil or criminal liability, the revocation of our permits and the imposition of liens or fines. In addition, environmental reports prepared for our facilities point to several possible areas of contamination. The costs of any required remediation are difficult to estimate, and we cannot assure you that cost estimates included in our financial projections will be sufficient to cover any required remediation. We cannot assure you that we will at all times be in compliance with all applicable environmental laws and regulations or that steps to bring our facilities into compliance will not limit our ability to make payments on the bonds.

    Issues of riverbank erosion and fish passages are on-going concerns for hydroelectric power generators, including us. For an explanation of how these issues affect our facilities, see "Regulation—Environmental Regulatory Matters—Licensing of Hydroelectric Generating Facilities" on page 63. In addition, issues involving contaminants in river sediments could affect some of our facilities. See "Regulation—Environmental Regulatory Matters—Soil and Sediment Contamination" beginning on page 65.

    Our operations could also be materially and adversely affected by changes in laws or regulations governing the environment and land use.

We assumed certain environmental liabilities when we acquired our facilities.

    In acquiring our facilities, we generally assumed the environmental liabilities associated with them, regardless of when such liabilities arose and whether known or unknown, and generally agreed to indemnify the former owners of the facilities, Connecticut Light & Power and Western Massachusetts Electric, for environmental liabilities other than those related to the treatment, disposal or storage of hazardous materials which were sent by Connecticut Light & Power or Western Massachusetts Electric to offsite disposal facilities prior to our acquisition of the facilities or liabilities for any known criminal violations of environmental laws by Connecticut Light & Power or Western Massachusetts Electric associated with the facilities.

RISKS RELATING TO OUR AFFILIATE RELATIONSHIPS AND OUR CAPITAL STRUCTURE

Northeast Utilities controls us and its interests may come into conflict with yours.

    We are an indirect, wholly-owned subsidiary of Northeast Utilities, which has the power to control us, our sole customer, Select Energy, and our major vendor, Northeast Generation Services. Our board of directors consists entirely of officers of Select Energy and Northeast Generation Services, and our officers are also officers of these or other affiliates of ours. In circumstances involving a conflict of interest between Northeast Utilities as our sole indirect equity owner, and the bondholders as our direct creditors, Northeast Utilities may exercise control over us in a manner that would benefit Northeast Utilities to the detriment of the bondholders.

    Northeast Utilities may compete with us in the future, directly or indirectly, including by acquiring electrical generation assets that sell energy, capacity and ancillary services into markets served by us. Northeast Utilities currently owns other electric power generation assets through its electric utility subsidiary, Public Service Company of New Hampshire.

We rely on contractual arrangements with our affiliates to conduct our business.

    We currently have no employees of our own and, accordingly, we are dependent on contractual arrangements with our affiliates Northeast Generation Services, Select Energy and Northeast Utilities

17


Service Company to conduct our business. Since we, Select Energy, Northeast Generation Services and Northeast Utilities Service Company are all directly or indirectly owned and controlled by Northeast Utilities, decisions concerning the interpretation or operation of these agreements could be made from perspectives other than the interests solely of us or our creditors, including the holders of the bonds. If these arrangements were terminated, it could be difficult or impossible to replace them with similar arrangements with a third party. In addition, if our affiliates perform their obligations in a manner that results in a loss to us, our possible remedies and indemnities under our agreements with them may not make us completely whole due to limitations on liability in these contractual arrangements. Under SEC rules, Northeast Generation Services can only supply services to us at cost, rather than at a possibly lower market rate.

We are the only ones required to make payments on the bonds. Northeast Utilities may not be able or willing to provide us with additional equity funding.

    Since our formation, Northeast Utilities has indirectly provided all of our equity funding. Our only source of funding other than incurring debt is the cash flow from our facilities. Neither Northeast Utilities nor any of our other affiliates is obligated to provide any loans or equity contributions to make up a shortfall between the amount of our commitments and our cash flow. In addition, Northeast Utilities is limited by SEC regulations as to how much equity it can contribute to an exempt wholesale generator like us, and any future equity contributions could require SEC approval. Within certain limitations provided in the bonds, Northeast Utilities could cause us to pay dividends, thus limiting the amount available to satisfy our obligations under the bonds or to invest in our business. See "Description of the Exchange Bonds—Certain Covenants—Restricted Payments," on page 86.

We cannot be certain about our future capital needs and our access to capital.

    To date, the capital for the acquisition of our facilities has been provided by Northeast Utilities and certain borrowings. We cannot guarantee that we will not need additional capital from time to time, or that we can obtain sufficient additional capital from Northeast Utilities or additional borrowings to enable us to fund all of our future capital requirements. Our ability or inability to obtain additional capital may have important consequences, including:

18


We may incur additional debt, which could adversely affect you.

    Subject to the indenture, we may incur additional debt, including additional series of bonds, to pay for certain capital improvements and expansions of our facilities or the acquisition of new facilities, to refinance existing indebtedness and to make additional distributions to our owners. Certain types of this permitted indebtedness may rank equally with the bonds.

RISKS RELATING TO THE EXCHANGE BONDS

There is no existing market for the exchange bonds, and we cannot guarantee that an active trading market will develop.

    The exchange bonds are a new issue of securities and will not be listed on any securities exchange. Prior to this offering of the exchange bonds, there has been no market for the exchange bonds. We have been informed by the initial purchasers that they intend to make a market in the exchange bonds after the completion of the exchange offer. However, the initial purchasers are not required to make a market in the exchange bonds, and they may cease market-making at any time without notice. We cannot assure you that an active market for the exchange bonds will develop. Moreover, even if a market for the exchange bonds does develop, you may be unable to resell the exchange bonds for an extended period of time, if at all. Consequently, you may not be able to liquidate your investment readily, or liquidate it at an attractive price. In addition, lenders may not readily accept the exchange bonds as collateral for loans.

19



THE EXCHANGE OFFER

Purpose of the Exchange Offer

    We initially sold the old bonds in a private offering on October 18, 2001 to Salomon Smith Barney Inc., Barclays Capital Inc., and TD Securities (USA) Inc. as the initial purchasers pursuant to a purchase agreement dated October 12, 2001 between us and Salomon Smith Barney Inc. as representative of the initial purchasers. These initial purchasers resold the old bonds to qualified institutional buyers in reliance on, and subject to the restrictions imposed under, Rule 144A under the Securities Act. As of the date of this prospectus, $440 million in aggregate principal amount of old bonds are outstanding.

    In connection with the private offering of the old bonds, we entered into a registration rights agreement dated October 12, 2001 with Salomon Smith Barney Inc. as representative of the initial purchasers. In the registration rights agreement, we agreed, among other things, to:


    We are not obligated to consummate the exchange offer if we determine, based upon advice of our outside counsel, that we are not permitted to effect the exchange due to a change in law or applicable interpretations thereof by the SEC. We have agreed to file a shelf registration statement covering resales of the old bonds as described under "—Shelf Registration Statement" below if we determine that we are not permitted to effect the exchange.

    We are making this exchange offer to satisfy our obligations and your registration rights under the registration rights agreement. If we fail to complete an exchange offer without a shelf registration statement being filed with the SEC on or prior to October 14, 2002, we must pay you, as a holder of outstanding old bonds, additional interest at a rate of 0.50% per annum from October 14, 2002 to but excluding the earlier of the date on which the exchange offer is completed and the date on which the shelf registration statement is declared effective.

Effect of the Exchange Offer

    Based on several no-action letters issued by the staff of the SEC to third parties in unrelated transactions, we believe that you may offer for resale, resell or otherwise transfer any exchange bonds issued to you in the exchange offer without further registration under the Securities Act or delivery of a prospectus if you:

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    If you do not satisfy these criteria:

    Broker-dealers receiving exchange bonds for their own account in the exchange offer will have a prospectus delivery requirement with respect to resales of such exchange bonds. The SEC has taken the position that participating broker-dealers may fulfill their prospectus delivery requirements with respect to exchange bonds, other than a resale of an unsold allotment from the original sale of the bonds, by delivering the prospectus contained in the exchange offer registration statement to prospective purchasers. Under the registration rights agreement, we are required to allow broker-dealers to use the prospectus contained in the exchange offer registration statement in connection with the resale of such exchange bonds. We have agreed that we will make the prospectus available to any broker-dealer for use in connection with any such resale for such period of time as is necessary to comply with applicable laws in connection with any resale of the exchange bonds.

    Each broker-dealer that receives exchange bonds for its own account in exchange for old bonds it acquired as a result of market-making or other trading activities, may be a statutory underwriter and must acknowledge that it will deliver a prospectus in connection with any resale of its exchange bonds. This will not be an admission by the broker-dealer that it is an underwriter within the meaning of the Securities Act. See "Plan of Distribution," beginning on page 108.

Shelf Registration Statement

    If (1) we determine that applicable laws or the applicable interpretations of the staff of the SEC do not permit us to effect the exchange offer, (2) the exchange offer is not consummated on or before October 14, 2002, (3) we receive a request from any initial purchaser with respect to any old bonds held by it that are not eligible to be exchanged for exchange bonds in the exchange offer after the completion of the exchange offer, (4) any holder of old bonds is not permitted pursuant to applicable law or applicable policies of the SEC to participate in the exchange offer and thereby receive exchange bonds, or (5) an initial purchaser that participates in the exchange offer does not receive freely tradable exchange bonds in exchange for old bonds constituting any portion of an unsold allotment, we have agreed that we will, at our cost:

    We will have no obligation to file a shelf registration statement covering bonds held by a holder described in clauses (3), (4) or (5) of the paragraph above unless such holder notifies us prior to October 14, 2002 that such holder desires to have such holder's old bonds covered by a shelf registration statement.

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    In lieu of filing a shelf registration statement for an initial purchaser who has received exchange bonds in respect of its unsold allotment, we may, if permitted by current interpretations by the SEC's staff, file a post-effective amendment to this registration statement containing the information that would be required in a shelf registration statement with respect to the initial purchaser and its plan of distribution.

    If you sell old bonds or exchange bonds pursuant to the shelf registration statement:

    Each holder of old bonds or exchange bonds to be sold pursuant to a shelf registration statement must deliver such information to us as we may reasonably require for inclusion in the shelf registration statement in order to have its old bonds or exchange bonds included in the shelf registration statement. No holder other than an initial purchaser will be entitled to have the old bonds held by it covered by a shelf registration statement unless the holder agrees in writing to be bound by all of the provisions of the registration rights agreement and furnishes to us all information concerning the holder and the holder's plan of distribution that is required pursuant to the shelf registration statement or required to make the information furnished by the holder not misleading.

    We will notify each holder of old bonds covered by a shelf registration statement (1) when the shelf registration statement or any amendment thereto has been filed with the SEC and when such registration statement or amendment becomes effective, (2) of various actions and requests by the SEC with respect to such registration statement, including the issuance of a stop order or initiation of proceedings for a stop order, and (3) of the happening of any event that requires any change in the registration statement so that the statements therein are not misleading and do not omit to state a material fact required to be stated therein or necessary to make the statements therein (in light of the circumstances under which they were made) not misleading. In the case of a notice described in (2) or (3) above, the notice will be accompanied by an instruction to suspend use of the prospectus contained in the registration statement until the basis for such suspension has been remedied. We will provide each holder of old bonds covered by the shelf registration statement with copies of the prospectus contained in the shelf registration statement and any amendment or supplement thereto.

    Our obligation to keep the shelf registration statement effective and usable for offers and sales of the old bonds or the exchange bonds may be suspended by us in good faith for valid business reasons, including, without limitation, a pending acquisition or divestiture of assets. You may not sell any old bonds or exchange bonds pursuant to the shelf registration statement during any such period of suspension.

    The foregoing is a summary description of the material provisions of the registration rights agreement. Because it is a summary, it does not include all of the information that is included in the registration rights agreement. We encourage you to read the entire text of the registration rights agreement carefully because it, and not this description, defines your rights as a holder of the old bonds. The registration rights agreement is included as an exhibit to the registration statement of which

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this prospectus is a part. You may request a copy of the registration rights agreement at our address set forth under "Where You Can Find More Information," on page 110.

Terms of the Exchange Offer

    We will accept all old bonds validly tendered and not withdrawn prior to 5:00 p.m., New York City time, on the expiration date of the exchange offer. You should read "—Expiration Date; Extensions; Amendments" below for an explanation of how the expiration date may be amended.

    Holders may exchange some or all of their old bonds in denominations of $100,000 and integral multiples of $1,000 in excess thereof. We will issue and deliver $100,000 principal amount of exchange bonds in exchange for each $100,000 principal amount of outstanding old bonds, and $1,000 principal amount of exchange bonds in exchange for each $1,000 of outstanding old bonds, accepted in the exchange offer.

    By tendering old bonds in exchange for exchange bonds and by signing the letter of transmittal (or delivering an agent's message instead of a letter of transmittal), you will be representing that, among other things:

    The terms of the exchange bonds are identical in all material respects to the terms of the old bonds, except that the registration rights and related increased interest rate provisions and the transfer restrictions applicable to the old bonds are not applicable to the exchange bonds. The exchange bonds will evidence the same debt as the old bonds and will be entitled to the benefits of the indenture governing the old bonds.

    In connection with the exchange offer, holders of the old bonds do not have any appraisal or dissenters' rights under law or the indenture governing the old bonds.

    We are sending this prospectus and the letter of transmittal to all registered holders of old bonds as of the close of business on            , 2001.

    We are not conditioning the exchange offer upon the tender of any minimum amount of old bonds.

    We have provided for customary conditions, which we may waive in our discretion. See "—Conditions of the Exchange Offer."

    We may accept tendered old bonds by giving oral or written notice to the exchange agent. The exchange agent will act as your agent for the purpose of receiving the exchange bonds from us and delivering them to you.

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    You will be required to pay brokerage commissions or fees and transfer taxes with respect to the exchange of old bonds. We will pay charges and expenses in connection with the exchange offer to the extent indicated in the registration rights agreement.

Expiration Date; Extensions; Amendments

    The exchange offer will expire at 5:00 p.m., New York City time, on      , 2002, unless we, in our sole discretion, extend it. We may extend the exchange offer at any time and from time to time by giving oral (promptly confirmed in writing) or written notice to the exchange agent and by making a public announcement of the extension before 9:00 a.m., New York City time, on the next business day after the previously scheduled expiration date. We may also accept all properly tendered old bonds as of the expiration date and extend the expiration date in respect of the remaining outstanding old bonds. We may, in our sole discretion,

    We will give prompt notice of any amendment to the registered holders of the old bonds. If we materially amend the exchange offer, we will promptly disclose the amendment in a manner reasonably calculated to inform you of the amendment and we will extend the exchange offer to the extent required by law.

Procedures for Tendering

    Only a holder of old bonds may tender them in the exchange offer. For purposes of the exchange offer, the term "holder" or "registered holder" includes any participant in DTC whose name appears on a security position listing as a holder of old bonds.

    To tender in the exchange offer, you must cause the following items to be transmitted to and received by the exchange agent no later than 5:00 p.m., New York City time, on the expiration date:

    If you wish to tender your old bonds and your old bonds are not available, you cannot complete the procedures for book-entry transfer or you cannot cause the old bonds or any other required documents to be transmitted to and received by the exchange agent before 5:00 p.m., New York City time, on the expiration date, you may tender your old bonds according to the guaranteed delivery procedures described in this section under the heading "—Guaranteed Delivery Procedures."

    Any beneficial owner of old bonds that are registered in the name of a broker, dealer, commercial bank, trust company or other nominee who wishes to participate in the exchange offer should promptly contact the person through which it beneficially owns its old bonds and instruct that person to tender old bonds on behalf of the beneficial owner. See the Letter to Registered Holders and DTC Participants Regarding the Offer to Exchange in the form accompanying this prospectus, which is included as an exhibit to the registration statement of which this prospectus is a part. If the beneficial

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owner wishes to tender on his or her own behalf, the owner must, prior to completing and executing the letter of transmittal and delivering the beneficial owner's old bonds, either make appropriate arrangements to register ownership of the old bonds in the owner's name or obtain a properly completed bond power from the registered holder. The transfer of registered ownership may take considerable time.

    The tender by a holder of old bonds will constitute an agreement between the holder and us in accordance with the terms and subject to the conditions specified in this prospectus and in the letter of transmittal. If a holder tenders less than all the old bonds held, the holder should fill in the amount of old bonds being tendered in the appropriate box on the letter of transmittal. The exchange agent will deem the entire amount of old bonds delivered to it to have been tendered unless the holder has indicated otherwise.

    The method of delivery of the letter of transmittal or agent's message and all other required documents to the exchange agent is at your election and risk. Instead of delivery by mail, we recommend that you use an overnight or hand delivery service. In all cases, you should allow sufficient time to ensure delivery to the exchange agent prior to the expiration date. Do not send your letter of transmittal or other required documents to us.

    Each broker-dealer that receives exchange bonds for its own account in exchange for old bonds that were acquired by that broker-dealer as a result of market-making activities or other trading activities, must acknowledge that it will deliver a prospectus in connection with any resale of those exchange bonds. See "Plan of Distribution," beginning on page 108.

Signature Requirements and Signature Guarantee

    You must arrange for an "eligible institution" to guarantee your signature on the letter of transmittal or a notice of withdrawal, unless the old bonds are tendered:

The following are "eligible institutions":

    If a letter of transmittal is signed by a person other than the registered holder of any old bonds listed in the letter of transmittal, the old bonds must be endorsed or accompanied by a properly completed bond power and signed by the registered holder as the registered holder's name appears on the old bonds.

    If trustees, executors, administrators, guardians, attorneys-in-fact, officers of corporations or others acting in a fiduciary or representative capacity, sign or endorse any required documents, they should so indicate when signing and must submit evidence satisfactory to us of their authority to so act with the letter of transmittal.

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Book-Entry Transfer

    The exchange agent will make a request promptly after the date of this prospectus to establish an account with respect to the old bonds in DTC's book-entry system. Subject to the establishment of the account, any financial institution that is a participant in DTC's system may make book-entry delivery of old bonds by causing DTC to transfer them into the exchange agent's account with respect to the old bonds. However, the exchange agent will only exchange the old bonds so tendered after a timely confirmation of their book-entry transfer into the exchange agent's account, and timely receipt of an agent's message and any other documents required by the letter of transmittal.

    The term "agent's message" means a message, transmitted by DTC to, and received by, the exchange agent and forming part of the confirmation of a book- entry transfer, which states that:

    Although you may effect delivery of old bonds through book-entry transfer into the exchange agent's account at DTC, unless the exchange agent receives an agent's message in compliance with the automated tender option program, you must provide the exchange agent a completed and executed letter of transmittal with any required signature guarantee (or an agent's message instead of a letter of transmittal) and all other required documents prior to the expiration date. If you comply with the guaranteed delivery procedures described below, you must provide the letter of transmittal (or an agent's message instead of a letter of transmittal) to the exchange agent within the time period provided under those procedures. Delivery of documents to DTC does not constitute delivery to the exchange agent.

Guaranteed Delivery Procedures

    If you wish to tender your old bonds and your old bonds are not immediately available, you cannot deliver your old bonds, the letter of transmittal or any other required documents to the exchange agent prior to the expiration date or you cannot complete the procedure for book-entry transfer on a timely basis, you may instead effect a tender if:

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Withdrawal of Tenders

    Except as otherwise provided in this prospectus, you may withdraw tendered old bonds at any time before 5:00 p.m., New York City time, on the expiration date. To do so, you must provide the exchange agent with a written or facsimile transmission notice of withdrawal before 5:00 p.m., New York City time, on the expiration date.

    Any notice of withdrawal must:

    We will determine all questions as to the validity, form and eligibility, including time of receipt, of all withdrawal notices. Our determination will be final and binding on all parties. We will not deem any old bonds withdrawn to be validly tendered for purposes of the exchange offer and will not issue exchange bonds for them unless the holder of old bonds withdrawn validly retenders them. You may retender withdrawn old bonds by following one of the procedures described above under "—Procedures for Tendering" at any time prior to the expiration date.

Determination of Validity

    We will determine all questions as to the validity, form, eligibility, including time of receipt, acceptance and withdrawal of the tendered old bonds in our sole discretion. Our determination will be final and binding. We may reject any and all old bonds that are not properly tendered or any old bonds of which our acceptance would, in our opinion or the opinion of our counsel, be unlawful. We also may waive any irregularities or conditions of tender as to particular old bonds. Our interpretation of the terms and conditions of the exchange offer, including the instructions in the letter of transmittal, will be final and binding on all parties. Unless waived, you must cure any defects or irregularities in connection with tenders of old bonds within a time period determined by us.

    Although we intend to notify tendering holders of defects or irregularities with respect to tenders of old bonds, neither we nor anyone else has any duty to do so. Neither we nor the exchange agent shall incur any liability for failure to give that notification. Your old bonds will not be deemed tendered until you have cured or we have waived any irregularities. As soon as practicable following the expiration date, the exchange agent will return any old bonds that we reject due to improper tender or otherwise unless you cured all defects or irregularities or we waive them.

    We reserve the right in our sole discretion:

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    The terms of any of those purchases or offers may differ from the terms of the exchange offer.

Conditions of the Exchange Offer

    We will not be required to accept for exchange, or to issue exchange bonds for, any old bonds, and we may terminate, waive any conditions to or amend the exchange offer if, in our sole judgment, the exchange offer would violate applicable law or any applicable interpretation of the staff of the SEC.

    These conditions are for our sole benefit and may be asserted by us regardless of the circumstances giving rise to any of these conditions. We may waive these conditions in our reasonable discretion in whole or in part at any time and from time to time. The failure by us at any time to exercise any of the above rights will not be deemed a waiver of that right and that right will be deemed an ongoing right that may be asserted at any time and from time to time. If we determine in our reasonable discretion that any of the conditions are not satisfied, we may:

    If we determine that a waiver constitutes a material change in the exchange offer, we will promptly disclose the change in a manner reasonably calculated to inform the holders of the change, and we will extend the exchange offer to the extent required by law.

Acceptance of Old Bonds for Exchange; Delivery of Exchange Bonds

    Upon satisfaction or waiver of all of the conditions to the exchange offer, we will accept, as soon as practicable after the expiration date, all old bonds that have been validly tendered and not withdrawn, and will issue the applicable exchange bonds in exchange for those old bonds promptly after our acceptance of those old bonds. For purposes of the exchange offer, we will be deemed to have accepted validly tendered old bonds for exchange when, as and if we have given written and oral notice of acceptance to the exchange agent.

    For each old bond accepted for exchange, the holder of the old bond will receive an exchange bond having a principal amount equal to that of the surrendered old note. Interest will be payable semi-annually on the exchange bonds each April 15 and October 15. Interest on the exchange bonds will accrue from the date of issuance of the old bonds and will first be paid on the exchange bonds on the first April 15 or October 15 following the date the exchange offer is completed. If the exchange offer is not completed before interest has been paid on the old bonds, interest on the exchange bonds will accrue from the last date on which interest was paid on the old bonds. No interest will be paid in connection with the exchange. Old bonds accepted for exchange will cease to accrue interest from and after the date on which they are accepted for exchange. Holders whose old bonds are accepted for exchange will not receive any payment for accrued interest on the old bonds otherwise payable on any interest payment date and will be deemed to have waived their rights to receive the accrued interest on the old bonds.

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    If any tendered old bonds are not accepted for any reason or if old bonds are submitted for a greater principal amount than the holder desires to exchange, those unaccepted or non-exchanged old bonds will be returned without expense to the tendering holder of the old bonds or, if the old bonds were tendered by book-entry transfer, the non-exchanged old bonds will be credited to an account maintained with the book-entry transfer facility. In either case, the return of old bonds will be effected promptly after the expiration or termination of the exchange offer.

Exchange Agent

    We have appointed The Bank of New York as the exchange agent for the exchange offer. You should send all executed letters of transmittal to the exchange agent as follows:

    Delivery to: The Bank of New York, Exchange Agent

By registered or certified mail: By hand or overnight courier:
The Bank of New York
15 Broad Street
New York, New York 10007
Attn: William Buckley
The Bank of New York
Reorganization Department
15 Broad Street, 16th Floor
New York, New York 10007
Attn: William Buckley

    Eligible institutions may deliver documents by facsimile at: (212) 235-2261, Attn: William Buckley.

    For facsimile confirmation only, you may call the exchange agent at: (212) 265-2352.

    If you deliver the letter of transmittal to an address other than as set forth above or transmit instructions by facsimile other than as set forth above, that delivery or those instructions will not be effective.

    You should direct questions and requests for assistance, requests for additional copies of this prospectus or the letter of transmittal and requests for notices of guaranteed delivery to the exchange agent at the address and telephone number set forth in the letter of transmittal.

Fees and Expenses

    We will bear all of our own expenses in connection with the exchange offer and have agreed to bear the reasonable fees and disbursements of one counsel to Salomon Smith Barney Inc., Barclays Capital Inc. and TD Securities (USA) Inc., as the initial purchasers of the old bonds, in connection with this registration statement. You are responsible for your own expenses, fees, underwriting discounts, commissions and transfer taxes, if any, relating to the sale or disposition of the old bonds. We are making the principal solicitation pursuant to the exchange offer by mail. Our officers and employees and those of our affiliates may also make solicitations in person, by telephone, e-mail or facsimile transmission.

    We have not retained any dealer-manager in connection with the exchange offer and will not make any payments to brokers, dealers or other persons soliciting acceptances of the exchange offer. We, however, will pay the exchange agent reasonable and customary fees for its services and will reimburse its reasonable out-of-pocket costs and expenses and will indemnify the exchange agent for all losses and claims incurred by it as a result of the exchange offer. We may also pay brokerage houses and other custodians, nominees and fiduciaries the reasonable out-of-pocket expenses incurred by them in forwarding copies of this prospectus, letters of transmittal and related documents to the beneficial owners of the old bonds and in handling or forwarding tenders for exchange.

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Transfer Taxes

    We will not pay any transfer taxes applicable to the exchange of old bonds pursuant to the exchange offer.

    In addition to transfer taxes imposed with respect to the exchange of old bonds pursuant to the exchange offer, the tendering holder will pay transfer taxes, if:

    If you do not submit satisfactory evidence of payment of taxes for which you are liable or exemption from those taxes with your letter of transmittal, we will bill you for the amount of these transfer taxes directly.

Accounting Treatment

    We will record the exchange bonds at the same carrying value as the old bonds, which is the principal amount as reflected in our accounting records on the date of the exchange. Accordingly, we will not recognize any gain or loss for accounting purposes. We will capitalize the expenses of the exchange offer for accounting purposes. We will classify these expenses as debt issuance costs and include them in other assets on our balance sheet. We will amortize these expenses on a straight line basis over the life of the exchange bonds.

Consequences of Failure to Exchange Old Bonds

    Holders of old bonds who do not exchange their old bonds for exchange bonds pursuant to the exchange offer will continue to be subject to the restrictions on transfer of those old bonds. The old bonds were originally issued in a transaction exempt from registration under the Securities Act, and may be offered, sold, pledged or otherwise transferred only:

    The offer, sale, pledge or other transfer of old bonds must also be made in accordance with any applicable securities laws of any state of the United States, and the seller must notify any purchaser of the old bonds of the restrictions on transfer described above. We do not currently anticipate that we will register the old bonds under the Securities Act.

Appraisal or Dissenters' Rights

    Holders of the old bonds will not have appraisal or dissenters' rights in connection with the exchange offer.

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USE OF PROCEEDS

    We will not receive any proceeds from the exchange. We used a portion of the proceeds from the sale of the old bonds to repay the $346.5 million bank debt remaining from the debt incurred to purchase the facilities and other assets we acquired from Connecticut Light & Power and Western Massachusetts Electric. We used the remaining proceeds to pay costs, expenses and fees associated with the offering of the old bonds (approximately $5.1 million), and to return $75.0 million in capital to our indirect parent, Northeast Utilities.


CAPITALIZATION

    The following table sets forth the actual unaudited capitalization of Northeast Generation as of September 30, 2001, and the pro forma capitalization of Northeast Generation on such date after giving effect to (i) the issuance of the old bonds and (ii) the application of the proceeds therefrom as described above in "Use of Proceeds." The pro forma capitalization is presented for illustrative purposes only and is not necessarily indicative of the capitalization of Northeast Generation as a result of the offering of the old bonds.

 
  As of September 30, 2001
 
 
  Actual
Capitalization

  Pro Forma
Capitalization

 
 
  (in thousands)

 
Total assets   $ 439,291   $ 452,691  
Short term debt:              
  Term loan facility     346,500      
Long term debt:              
  Bonds         440,000  
   
 
 
Total debt   $ 346,500   $ 440,000  
Stockholder's equity     79,608     1,548 (1)(2)
   
 
 
Total debt and stockholder's equity   $ 426,108   $ 441,548  
   
 
 

(1)
Because our facilities were acquired from affiliates, they are required to be carried on our balance sheets at their book values on the balance sheets of Connecticut Light & Power and Western Massachusetts Electric prior to our acquisition of the facilities, less depreciation, rather than the cost we incurred to acquire the facilities. If the facilities were carried at their purchase price, less depreciation, our total assets would be $899,407 as of September 30, 2001 and our stockholder's equity as of September 30, 2001 would be $539,724. On a pro forma basis after giving effect to the issuance of the old bonds and the application of the proceeds therefrom as described in "Use of Proceeds," our total assets as of September 30, 2001 would be $912,807 and our stockholder's equity as of September 30, 2001 would be $461,664. See Note 5 to the financial statements included elsewhere in this prospectus.

(2)
On October 18, 2001, we used approximately $53.7 million of the proceeds of the old bonds to pay a dividend to our immediate parent, NU Enterprises, Inc., and approximately $21.3 million of the proceeds of the old bonds to repurchase a portion of our stock from NU Enterprises, Inc.

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SELECTED FINANCIAL DATA

    The following table sets forth selected historical financial data for Northeast Generation. Northeast Generation was incorporated on December 28, 1998, but had no significant assets or operations prior to the acquisition of its facilities on March 14, 2000. The selected historical financial data have been derived from the audited and unaudited historical financial statements of Northeast Generation included elsewhere in this prospectus. The financial data as of and for the periods ended September 30, 2001 and September 30, 2000 are unaudited, but in the opinion of management reflect all material adjustments necessary, consisting only of normal and recurring adjustments, to present fairly our financial position as of September 30, 2001 and September 30, 2000 and the results of operations for the periods then ended. The information set forth below should be read in conjunction with the section of this prospectus captioned "Management's Discussion and Analysis of Financial Condition and Results of Operations" and our historical financial statements and the accompanying notes included in this prospectus.

 
  Nine months
ended
September 30, 2001
(unaudited)

  Nine months ended
September 30, 2000
(unaudited)

  Period from Inception
(December 28, 1998) to
December 31, 2000

 
  (in thousands except in ratios)

Statement of Income Data (for the period):                  
Operating revenues   $ 99,400   $ 75,589   $ 108,473
Operating expenses     47,198     32,761     49,731
   
 
 
Operating income     52,202     42,828     58,742
Other income, net     1,036     614     1,061
Interest expense     19,537     25,131     36,543
   
 
 
Net income   $ 33,701   $ 18,311   $ 23,260
   
 
 
Balance Sheet Data (at the end of period):                  
Total assets(1)   $ 439,291   $ 461,573   $ 461,061
Total liabilities     359,683     422,034     413,426
Stockholder's equity(1)(2)     79,608     39,539     47,635
Other Data (for the period):                  
EBITDA(3)   $ 83,842   $ 59,932   $ 83,355
Capital expenditures     8,310     554     1,394
Ratio of earnings to fixed charges(4)     3.89x     2.21x     2.06x

(1)
Because our facilities were acquired from affiliates, they are required to be carried on our balance sheets at their book values on the balance sheets of Connecticut Light & Power and Western Massachusetts Electric prior to our acquisition of the facilities, less depreciation, rather than the cost we incurred to acquire the facilities. If the facilities were carried at their purchase price, less depreciation, our total assets would be $899,407 as of September 30, 2001 and our stockholder's equity as of September 30, 2001 would be $539,724. See note 5 to our financial statements included elsewhere in this prospectus.

(2)
On October 18, 2001 Northeast Generation used $75,000 of the proceeds of the offering to pay a dividend to, and repurchase certain shares of its stock from, its immediate parent, NU Enterprises, Inc. For further information, see "Capitalization," on page 31.

(3)
"EBITDA" means earnings before interest, taxes, depreciation and amortization. Information concerning EBITDA is presented here as a measure of ability to service debt and not as a measure of operating results. EBITDA may not be comparable to similarly titled measures by other

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(4)
On a pro forma basis, after giving effect to the repayment of the bank debt and the issuance of the old bonds as if they had occurred on the first day of each period, the ratio of earnings to fixed charges would be 2.96 for the nine months ended September 30, 2001, 2.17 for the nine months ended September 30, 2000 and 1.10 for the period from inception to December 31, 2000.

Operating Data for Our Generating Assets

    The following table describes the historical operating data for generating assets that we acquired from Connecticut Light & Power and Western Massachusetts Electric, regulated electricity subsidiaries of Northeast Utilities.

 
  Nine months
ended
September 30,
2001

  Year Ended December 31,
 
 
  2000
  1999
  1998
  1997
  1996
 
Total Capacity (megawatts)     1,289     1,289     1,289     1,330     1,328     1,289  
Average Availability Factor     93.6 %   90.0 %   93.8 %   91.5 %   97.1 %   95.0 %
Average Capacity Factor     18.1 %   18.0 %   16.3 %   15.1 %   15.3 %   19.6 %
Net Generation (excluding plant use in megawatt-hours)     1,457,480     1,653,306     1,562,815     1,440,401     1,559,221     2,011,324  
Operating and Maintenance Cost per megawatt-hour ($ per megawatt-hour)   $ 8.22   $ 11.70   $ 12.56   $ 14.22   $ 10.91   $ 8.60  

    In the table above, "availability factor" is a percentage representing the number of hours a generating unit is available to produce power (regardless of the amount of power) in a given period, compared to the total number of hours in the period; "capacity factor" is the ratio of the power produced by a generating unit for a period of time to the power that could have been produced at continuous full-power operation during the same period; and "net generation" excludes power used by the plant for its own operation.

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

    The following discussion contains forward-looking statements. These statements are based on current plans and expectations and involve risks and uncertainties that could cause actual future activities and results of operations to be materially different from those set forth in the forward-looking statements. Important factors that could cause actual results to differ include risks set forth in "Risk Factors."

Corporate Structure

    Northeast Generation is a subsidiary of NU Enterprises, Inc., a wholly owned subsidiary of Northeast Utilities. We are a deregulated business affiliate formed to acquire and manage generation facilities.

    In March 2000, we acquired 1,289 megawatts of primarily pumped storage and conventional hydroelectric generation assets in Connecticut and Massachusetts from Connecticut Light & Power and Western Massachusetts Electric, two affiliated companies. The acquisition was completed through an independent auction overseen by the Connecticut Department of Public Utility Control and an independent investment banking firm.

    We have contracted to sell all of the energy and capacity of our generation assets to our deregulated affiliate, Select Energy, through December 31, 2005. Additionally, we have contracted with Northeast Generation Services, another affiliate, to operate, manage and maintain our generation assets. We have also contracted with Northeast Utilities Service Company, another affiliate, for corporate services.

    Prior to the acquisition of the facilities from Connecticut Light & Power and Western Massachusetts Electric, the facilities were operated by their former owners on a fully-integrated basis with other assets and operations of those former owners. Therefore, no historical financial information (other than operating data provided under "Selected Financial Data—Operating Data for Our Generating Assets", on page 33) is available that would be meaningful or indicative of the future results that may be achieved through the operation of the facilities in light of the manner and regulatory and market environments in which we operate our generation assets. As a result, this Management's Discussion and Analysis of Financial Condition and Results of Operations reflects our operations since formation but does not include a discussion of, or comparison to, prior periods.

Earnings Overview

    In conjunction with the transfer of 1,289 megawatts of generation assets to Northeast Generation from Connecticut Light & Power and Western Massachusetts Electric, two affiliated companies, in March 2000, Northeast Generation increased its operations in 2001 and 2000, as compared to 1999. Northeast Generation, Connecticut Light & Power and Western Massachusetts Electric are wholly owned subsidiaries of Northeast Utilities.

    Our earnings totaled $33.7 million for the nine months ended September 30, 2001, compared with $18.3 million for the same period of 2000, $26.4 million for the year ended December 31, 2000, and a loss of $3.2 million for the same period of 1999. We benefited in 2001 and 2000 from our contract with Select Energy, our deregulated marketing affiliate, to sell all of our output and capacity to Select Energy for a term expiring on December 31, 2005.

    For the nine months ended September 30, 2001, our revenues amounted to $99.4 million, compared with $75.6 million for the same period of 2000, $108.5 million for the year ended

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December 31, 2000, and no revenues for the same period of 1999. This growth in revenues is attributable to the aforementioned hydroelectric generation asset transfer and contract with Select Energy.

Results of Operations

    The components of significant income statement variances for the nine months ended September 30, 2001, as compared to the nine months ended September 30, 2000, as well as the components of significant income statement variances for the year ended December 31, 2000, as compared to the year ended December 31, 1999, are provided in the table below.

 
  Income Statement Variances
(Millions of Dollars)

 
 
  2001 over/
(under) 2000

  2000 over/
(under) 1999

 
 
  Nine
Months

  Percent
  Year
Ended

  Percent
 
Operating revenues   $ 24   32 % $ 108    %
Operating expenses:                      
  Operation and maintenance       2     16   (a )
  Depreciation     1   38     2    
  Federal and state income taxes     11   87     19   (a )
  Taxes other than income taxes     3   (a )   6   (a )
   
 
 
 
 
      Total operating expenses     15   44     43   (a )
   
 
 
 
 
Operating income/(loss)     9   22     65   (a )
Other income, net     1   69     1    
Interest expense     (5 ) (22 )   36   (a )
   
 
 
 
 
Net income/(loss)   $ 15   84 % $ 30   (a )%
   
 
 
 
 

(a)
Percent greater than 100.

Comparison of the Nine Months Ended September 30, 2001,
to the Nine Months Ended September 30, 2000

Operating Revenues

    Total revenues increased by $24 million in 2001, primarily due to a full nine months of revenues in 2001, as compared to approximately six months of revenues in 2000, resulting from the transfer of 1,289 megawatts of generation assets to Northeast Generation from Connecticut Light & Power and Western Massachusetts Electric in March 2000, and Northeast Generation's contract with Select Energy to sell all of Northeast Generation's output and capacity to Select Energy for a period ending December 31, 2005. Revenues from Select Energy represent close to 100 percent of Northeast Generation's operating revenues in 2001 and 2000.

Federal and State Income Taxes

    Federal and state income taxes increased in 2001, primarily due to higher book taxable income.

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Interest Expense

    Interest expense decreased by $5 million, primarily due to a decrease in short-term debt as a result debt repayments made during 2001.

Comparison of the Year Ended December 31, 2000, to the Year Ended December 31, 1999

Operating Revenues and Operation and Maintenance Expenses

    Total revenues and operation and maintenance expenses increased by $108 million and $16 million, respectively, in 2000, primarily due to the transfer of 1,289 megawatts of generation assets to Northeast Generation from Connecticut Light & Power and Western Massachusetts Electric in March 2000, and Northeast Generation's contract with Select Energy to sell all of Northeast Generation's output and capacity to Select Energy for a period ending December 31, 2005. Revenues from Select Energy represent close to 100 percent of Northeast Generation's operating revenues in 2000.

Federal and State Income Taxes

    Federal and state income taxes increased in 2000, primarily due to higher book taxable income.

Interest Expense

    Interest expense increased by $36 million, primarily due to an increase in short-term debt as a result of the transfer of the generation assets in 2000.

Liquidity and Capital Resources

    Northeast Generation's net cash flows provided by operating activities totaled $53.5 million for the nine months ended September 30, 2001, compared with $19.2 million for the same period of 2000, $43 million for the year ended December 31, 2000, and net cash flows used in operating activities of $6.5 million for the same period of 1999. This growth is attributable to the aforementioned transfer of generation assets and contract with Select Energy, resulting in a $15.4 million increase in net income for the nine months ended September 30, 2001, compared with the same period of 2000, and a $29.6 million increase in net income for the year ended December 31, 2000, compared with the same period in 1999.

    The net cash payment for the transfer of generation assets from Connecticut Light & Power and Western Massachusetts Electric in March 2000, resulted in a significant increase in cash flows used in investing activities in 2000. Northeast Generation's net cash flows used in investing activities totaled $8.3 million for the nine months ended September 30, 2001, compared with $870.3 million for the same period of 2000, $871.2 million for the year ended December 31, 2000, and no cash flows from investing activities in 1999.

    Northeast Generation financed the asset transfer with a short-term credit agreement collateralized by the generation assets transferred and an equity infusion from Northeast Utilities. Northeast Generation's financing activities for the year ended December 31, 2000, included a $402.4 million increase in short-term debt and $463 million in capital contributions, compared with the same period in 1999. Financing activities for the nine months ended September 30, 2001, included a decrease in short-term debt of $55.9 million as a result of debt repayments. Financing activities for the nine months ended September 30, 2000, included a $416.3 million increase in short-term debt and $463 million in capital contributions as a result of the asset transfer.

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    For further information regarding Northeast Generation's borrowing facility, see Note 3, "Credit Agreement," to the financial statements included elsewhere in this prospectus.

    Northeast Generation used a portion of the proceeds from the issuance of the old bonds on October 18, 2001 to repay the $346.5 million bank debt remaining from the debt incurred to purchase the generation assets. Approximately $53.7 million of the proceeds were used to pay a dividend to our direct parent, NU Enterprises, Inc., and approximately $21.3 million was used to repurchase a portion of our stock from NU Enterprises, Inc. The proceeds of the dividend and the repurchase of our stock were thereafter paid to Northeast Utilities. Northeast Generation satisfied the $29.1 million initial debt service requirement of the bonds using a combination of cash on hand and proceeds from the offering of the bonds.

    Northeast Generation's capital requirements are expected to consist primarily of expenditures to maintain the operation of the existing facilities, including expenditures for repairs, replacement and refurbishment of equipment and environmental compliance. Northeast Generation currently forecasts construction expenditures of approximately $14 million for the year ended December 31, 2001. Depending on the actual work performed and the projects scheduled, some of these expenditures may not be made until 2002.

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INDUSTRY OVERVIEW

    The overall structure of the electric power industry in the United States has undergone substantial change over the last several years. Various regulatory initiatives as well as federal and state legislative actions have all been targeted to increasing competition in the electricity marketplace. In the past, local electric utilities provided generation, transmission and distribution services to their retail service territories under exclusive franchises. These companies recovered costs plus a rate of return on invested capital based upon the rate orders approved by a regulatory body. The new initiatives are designed to encourage traditional electric utilities to divest their generating assets, encourage new companies to enter the market and introduce competition on both a wholesale and retail level in many states.

Competitive Wholesale Power Generation

    The most sweeping change in recent years followed the passage of the Energy Policy Act of 1992. This legislation amended both the Federal Power Act and the Public Utility Holding Company Act and was intended to provide a "comprehensive national energy policy" designed to increase U.S. energy security "in cost-effective and environmentally beneficial ways." Among other things, the Energy Policy Act authorizes FERC to promote competition in wholesale bulk power markets by requiring utility companies to provide transmission services upon request if FERC finds that such transmission would be in the public interest and would not unreasonably impair the continued reliability of affected electric systems.

    As traditional, investor-owned utilities began seeking market-based rates for wholesale sales of excess capacity, FERC extended its market power analysis to these companies also. In return for allowing these utilities to charge market-based rates, FERC required that such utilities open their transmission system to other wholesale generators, sellers and buyers of electricity on a nondiscriminatory basis. FERC has also strongly encouraged utilities to join regional transmission organizations that would control their transmission facilities.

    In addition, the Energy Policy Act facilitated the development of competition in the United States by creating the regulatory category of "exempt wholesale generators" and permitting any person to acquire exempt wholesale generators without the need to apply for or receive prior approval of the SEC. An exempt wholesale generator is exempt from regulation as an "electric utility" under the Public Utility Holding Company Act. Our facilities are all exempt wholesale generators, although we are owned indirectly by a registered public utility holding company regulated by the SEC under the Public Utility Holding Company Act.

Deregulation

    In addition to FERC making transmission services available to wholesale customers, state legislators and regulators throughout the United States have begun to establish a framework to allow retail customers to choose their energy suppliers. This framework still requires the incumbent utilities to deliver energy over their transmission and distribution systems, but allows other suppliers to sell power and energy to customers once served exclusively by the incumbent utilities. Various states are in different stages of the process of determining a framework for deregulation.

    As part of the transition to a deregulated market, a number of investor-owned electric utilities nationwide have divested or are in the process of divesting all or a portion of their generation assets. As additional companies enter the deregulated market, the industry is likely to see the emergence of more purchasers of electricity into the wholesale marketplace, resulting in an increase in the volume of transactions. Such additional players will enhance the liquidity of the market, which is a key to a successful competitive marketplace.

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Power Markets, Products and Services

    In December 1999, FERC issued its Order 2000, which proposed that a handful of new entities, referred to as regional transmission organizations, would control the nation's electric transmission grid, in order to facilitate expanded and free-flowing wholesale electric markets. On July 12, 2001, FERC issued an order proposing that the region encompassed by NEPOOL, the New York Independent System Operator and the PJM Power Pool form a single regional transmission organization and ordering the commencement of negotiations to form such regional transmission organization. FERC identified the PJM Power Pool market structure as the model for standardized market and transmission rules, but also encouraged the proposed regional transmission organization to incorporate the best practices of the independent system operators for New York and New England. A number of interventions have been filed with FERC with respect to this order.

    The following discussion of power markets, products and services describes the market as it currently exists. It is too early to predict the effects on our market, products and services of the new FERC orders or the creation a single northeastern regional transmission organization, although we believe it will make it easier for our power to be marketed beyond the New England states and that, overall, we will not be adversely affected.

    The New England Power Pool.  NEPOOL is a voluntary, cooperative association of electric service providers and other entities in New England, including investor-owned, municipal and consumer-owned utility systems, power marketers, joint-marketing agencies, load aggregators, independent power producers, end users and exempt wholesale generators. NEPOOL was originally formed to capture the benefits of economic dispatch and joint planning for a large number of utilities.

    Creation of New England's Independent System Operator.  In 1997, NEPOOL created New England's Independent System Operator ("ISO New England") with responsibility to administer the NEPOOL tariff transmission facilities in a fair and neutral manner. ISO New England also administers the restructured electric power marketplace. This organization immediately assumed responsibility for the management of the New England region's electric bulk power generation and transmission systems and the administration of the region's open access transmission tariff.

    The independent system operator concept was developed by FERC as part of the framework to support the deregulation of the electric industry in the United States. FERC envisioned the establishment of regional independent system operators across the country, which would be approved and regulated by FERC. FERC stated its principles for independent system operator operation and governance in Order No. 888. Key principles include:

    By supporting the establishment of ISO New England, the NEPOOL members created the new level of independence sought by the FERC to protect against the potential for any participant to unduly influence access to the region's transmission system, the dispatch order of generation resources, or the competitiveness of the emerging wholesale marketplace.

    To maintain an arm's-length business relationship between ISO New England and NEPOOL, the parties entered into a services agreement that provides procedures governing the interface between ISO New England and NEPOOL. Standards and policies for system reliability, market rules and dispute resolution are established within the NEPOOL governance structure in consultation with ISO New England. However, under emergency conditions, ISO New England has the ability to unilaterally establish new rules or change rules, as deemed necessary to either ensure system reliability or protect the competitiveness of the marketplace. This agreement gives ISO New England the authority to operate the generation and transmission systems as well as the residual wholesale electric market.

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    The NEPOOL Market.  In the NEPOOL region, oil and gas units operate in the margin. NEPOOL has five nuclear units, the continuing operational status of which is, at present, unclear; this factor affects the capacity needs in NEPOOL's service area. Transmission constraints limit power transmission within the region and limit exports and imports to and from neighboring regions. As of March 2001, NEPOOL had a total installed capacity of 25,725 megawatts. The table below shows the ISO New England statistics on historical and forecasted annual capacity in terms of gigawatt hours and the annual peak load requirement in terms of megawatts.


NEPOOL Annual Capacity and Summer Peak Load

 
  Actual
  Forecast
 
  1999
  2000
  2001
  2005
  2010
Energy (GWh)   121,873   124,886   127,650   136,273   146,503
Summer Peak (MW)   22,544   21,919   23,650*   25,308   27,075

(Source: NEPOOL CELT Reports—2000 and 2001)


*
On August 9, 2001, New England experienced an unofficial new record peak demand of 25,158 megawatts, exceeding the forecasted peak of 23,650 megawatts for 2001 shown in the table above.

    On May 1, 1999, ISO New England began administering NEPOOL's restructured electricity marketplace through which energy, automatic generation control and several reserve services are supplied. ISO New England administers a "residual" wholesale electricity market in accordance with market rules approved by NEPOOL participants. "Residual" means that to the extent that a participant in the marketplace produces electricity in excess of its load obligations, it can sell the excess to other participants through a spot market administered by ISO New England.

    As part of the deregulation of the electric industry, access to New England's transmission system has been opened to competition. Participants who desire to reserve transmission services for the supply of electricity through and out of the New England region, can do so through ISO New England. The cost for regional transmission services is a uniform flat rate derived from calculating the actual costs for building and maintaining transmission facilities. This rate is reviewed and approved by FERC. Local distribution companies charge separate transmission rates for use of their local networks.

    Under our management and operation agreement with Northeast Generation Services, Northeast Generation Services is responsible for qualifying each of our facilities with ISO New England as generating resources in New England and for communicating with ISO New England regarding the hourly operation of each facility. Under our agreement with Select Energy, Select Energy is responsible for bidding and scheduling our facilities with ISO New England.

    Wholesale Electricity Market.  There are six wholesale electricity products that are bought and sold in New England. Although these six products are in place today, based on the ongoing evolution of the New England power market they are likely to change as the market structures in New England, New York and the PJM market converge over time or are merged together pursuant to FERC's mediation orders. Various proposals have been made that would have the effect of limiting the number of reserve capabilities that are currently marketed as separate ancillary service products within NEPOOL. While this could change the way our power is marketed, we believe that the inherent flexibility of pumped storage technology and the quick-start capabilities of Northfield will continue to be critical to our markets and that any changes to the products sold in NEPOOL would be unlikely to have a material adverse effect on the revenues from our generating assets. The six products are:

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    Energy is power produced in the form of electricity, measured in kilowatt-hours or megawatt-hours. This electricity is ultimately delivered to customers for use in lighting, heating, air conditioning and the operation of other electrical equipment. All our resources produce energy, which is committed to Select Energy under our power purchase and sales contract through December 2005.

    Automatic generation control is a measure of the ability of a generator to respond automatically within a specified time to remote directions to increase or decrease its output in order to control frequency and to maintain proper power flows into and out of the NEPOOL control area. ISO New England compensates generators for automatic generation control by calculating a lost opportunity payment and a production cost charge for automatic generation control. ISO New England ranks generators based on their automatic generation control bids. Generators successful in this market are paid the revenues they would have otherwise received plus compensation for the loss in efficiency of their units.

    Ten-minute spinning reserve generally is the capability of a generator that is synchronized to the system to increase its energy output within ten minutes. It might have to reduce its energy requirements and maintain those reduced requirements pursuant to a dispatch direction to create spinning reserve. A generator committed to ten-minute spinning reserve is reimbursed by receipt of the energy market clearing price for spinning reserve for the megawatts provided and a lost opportunity payment for the margin it would have received had it participated in the energy market during that time. Hydroelectric facilities (including pumped storage facilities) and dispatchable generators are allowed to bid into the ten-minute spinning reserve market.

    Ten-minute non-spinning reserve generally means the capability of a generator that is not synchronized to the system to supply energy within ten minutes or reduce its energy requirements within ten minutes and maintain those reduced requirements pursuant to dispatch direction.

    Thirty-minute operating reserve generally means the capability of a generator to supply a designated amount of energy within thirty-minutes of demand, or reduce its energy requirements within thirty minutes and maintain those reduced requirements pursuant to dispatch direction.

    Installed capacity generally refers to the obligation of NEPOOL participants to maintain a pre-determined electric generating capacity with respect to units operated by them. To ensure that sufficient capacity is available in the market to meet reliability standards, NEPOOL requires load serving entities to own or contractually control physical generation capacity in excess of their peak demand. Each participant's monthly installed capacity requirement is determined following the end of the month. Participants which are deficient in meeting their obligations must pay a deficiency charge, but may avoid the assessment of a deficiency charge by purchasing the excess capacity of other participants through bilateral agreements. The revenues collected from the deficiency charge payments are distributed to those participants with surplus capacity and to those participants who have covered their installed capacity obligations. FERC has indicated a willingness to consider alternatives, and this system of deficiency charges may be modified or replaced if alternative mechanisms for meeting the region's needs for reserve capacity are developed and subsequently approved.

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OUR BUSINESS

    We are the deregulated generating subsidiary of Northeast Utilities and are a major provider of pumped storage and conventional hydroelectric power in the northeastern United States. We own and operate a portfolio of approximately 1,289 megawatts of generating assets in New England. Our portfolio, as represented in the chart below, consists of:

    The chart below shows the size, in terms of megawatt capacity, of our various facilities.

LOGO

    Northeast Utilities' vision is to continue to strengthen its position as one of the major energy providers in the northeastern United States. The deregulated energy business is a core focus of Northeast Utilities. Northeast Generation performs functions that are critical to Northeast Utilities' strategy on both the wholesale and retail levels by providing access to electric generation within the Northeast Utilities system and thus limiting the exposure of Select Energy to the risk of energy price fluctuations.

    We signed a power purchase and sales agreement with Select Energy, our retail and wholesale marketing and trading affiliate, to sell 100% of the electric energy output and capacity of our facilities through December 2005. This power purchase and sales agreement provides Select Energy with access to a large block of highly flexible generating capacity that enables Select Energy to serve its growing portfolio of wholesale power sales contracts.

Our Acquisition of the Generating Assets

    The acquisition of our assets is an example of the trend toward the disaggregation of electric utility company assets. In 1998, the State of Connecticut enacted comprehensive electric utility restructuring legislation (Public Act 98-28, "An Act Concerning Electric Restructuring") requiring, among other things, that Connecticut Light & Power divest its generating assets. The auction occurred in the spring and summer of 1999 and was conducted by an independent investment banking firm. Western Massachusetts Electric, which owned certain assets in the Northfield Mountain-Connecticut River System, was allowed to include those assets in the auction.

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    To finance the acquisition of our assets, we borrowed $430 million from a syndicate of banks led by Citibank N.A. pursuant to a credit facility that would have matured on November 27, 2001. We paid the remaining $435.5 million of the purchase price with the proceeds of a single-day equity bridge loan, which was repaid with a capital contribution of $435.5 million from Northeast Utilities. This capital contribution was made through our immediate parent, NU Enterprises. Because our facilities were acquired from our affiliates, generally accepted accounting principles require us to carry the facilities at their book value, less depreciation, on the books of Connecticut Light & Power and Western Massachusetts Electric at the time of sale, rather than at their purchase price, less depreciation. Accordingly, the facilities and other acquired items were initially recorded on our books at $128.6 million, or $736.9 million less than their purchase price of $865.5 million.

Our Competitive Strengths

    We believe that we have a number of competitive strengths:

    Benefits of Pumped Storage Technology and Value of Northfield Mountain Pumped Storage Facility. Pumped storage technology permits the use of lower cost off-peak power to pump water into an upper reservoir. The water is then released to generate electricity during higher-priced on-peak hours. This means that pumped storage generation can be profitable whether energy prices as a whole are low or high, so long as there is a differential between the price of peak and off-peak power.

    Northfield, the largest of our assets, is the most responsive pumped storage facility in New England and is among the most responsive pumped storage facilities in the United States. On average, it can achieve full plant output from a shut down in about three minutes. This enables the facility to respond rapidly to short term events and emergencies on the transmission and distribution system. Northfield has the ability to turn around from full pumping to full generating in about 15 minutes. Northfield's flexibility enables it to supply power in response to unexpected spikes in demand. As a result, the facility's "quick-start" and reserve capabilities can be marketed as ancillary services within the NEPOOL market structure.

    Northfield is one of only two large pumped storage facilities in NEPOOL. Its ability to respond rapidly and flexibly to short-term events on the NEPOOL transmission and distribution system makes Northfield critically important to NEPOOL.

    Recently, as a direct result of concerns over system reliability, FERC granted Northfield a temporary amendment to its FERC license allowing it to increase storage in its upper reservoir and generate more electricity during times of system emergencies effective from June 1, 2001 to April 30, 2002. We believe this temporary amendment is a direct recognition of the value of Northfield to the reliability of NEPOOL.

    Northfield's potential profitability is based on the on-peak/off-peak power price differential, not the absolute price of power. It has the ability to capture value in the marketplace under both high and low volatility situations. The differential between on-peak and off-peak prices is an inherent characteristic of the power marketplace because generation capacity is largely fixed in the short run, while demand varies sharply throughout the day and from day to day. Volatility is a pervasive feature of electricity markets that we believe will remain even as the market matures. We anticipate that Northfield can be operated profitably even under low volatility conditions and that additional price volatility would enhance its value.

    Stable Revenue Stream and Cash Flows Through 2005.  Our contract with Select Energy provides us with a stable revenue stream at fixed prices, and provides us with steady and predictable cash flows. The contract insulates us to a large extent from the impact of longer term fluctuations in energy prices. Because our contract with Select Energy compensates us at fixed prices for all of the electric energy

43


output and capacity of Northfield, we will not profit directly from the ability of this facility to deliver power at times of peak demand and peak energy prices unless the Select Energy contract is not renewed at the expiration of its term. However, the contract with Select Energy compensates us at prices that are currently higher than average wholesale energy prices in the markets that our facilities serve. Select Energy's performance obligations under this contract are guaranteed by Northeast Utilities.

    Our agreement with Select Energy makes Select Energy responsible for the cost of pumping water from the lower to the upper reservoirs at our pumped storage facilities and for providing fuel to the Tunnel internal combustion unit. We bear the risk that our other costs will exceed the fixed prices established in our contract with Select Energy.

    Central Location within NEPOOL.  The Northfield Mountain-Connecticut River System is centrally located in a non-congested area and directly connects to the 345 kilovolt electricity transmission grid. Its quick-start capabilities fulfill a critical need within New England to provide peak power to manage the regional power grid. It has access to multiple markets through NEPOOL's interconnections with the New York Independent System Operator, Hydro Quebec and New Brunswick. Because of this, Northfield has the ability to arbitrage New England and New York energy prices.

    NEPOOL has established a competitive bid market for energy, spinning and operating reserves, and automatic generation control, as well as a capacity obligation and an administratively determined deficiency change. ISO New England has affirmed the need for quick-start resources. Northfield and our Tunnel internal combustion unit are both quick-start resources. Although FERC's recent orders calling for the creation of a single northeastern regional transmission organization create some uncertainty about the future structure of our market, we expect that the economics of Northfield, would not be adversely affected by the creation of a single regional transmission organization for the region now serviced by NEPOOL, the New York Independent Service Operator and the PJM Power Pool.

    In New England, significant new capacity additions are needed to meet strong demand growth and replace a rapidly aging fleet of generators. There is a proliferation of new merchant plants proposed or under construction in NEPOOL. According to the independent power market consultant's report included as Appendix B to this prospectus, most of the new capacity is expected to come from combined cycle plants. The independent power market consultant anticipates that the addition of new plants will tend to drive down both on-peak and off-peak prices and will not have a significant effect on Northfield's economics because Northfield's pumped storage system will still take advantage of the spread between on-peak and off-peak prices. Also, unlike Northfield, this new combined cycle capacity cannot provide the quick-start peaking capacity being sought in NEPOOL.

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    Reliability of Assets.  Our assets are highly reliable, with proven availability. The following table summarizes the main characteristics of these assets:

 
   
   
  Five Year (1996-2000 Average)
 
Group/Station

  Type
  Capacity
(MW)

  Net
Generation
(MWh)

  Forced
Outage Rate
(%)

  Availability
Factor
(%)

  Capacity
Factor
(%)

 
Northfield Mountain-Connecticut River System                          
  Northfield   Pumped Storage   1,080.0   997,652   <1   92.6   11.5 *
  Cabot   Conventional Hydro   53.0   268,824   <1   97.9   59.4  
  Turners Falls   Conventional Hydro   6.3   17,807   <1   96.7   32.0  
Housatonic Hydroelectric System                          
  Falls Village   Conventional Hydro   11.0   45,840   <1   97.6   48.4  
  Bulls Bridge   Conventional Hydro   8.4   41,876   6.3   89.2   59.5  
  Rocky River   Pumped Storage   29.9   13,228   <1   98.5   5.2  
  Shepaug   Conventional Hydro   43.4   131,624   2   96.8   36.3  
  Stevenson   Conventional Hydro   28.9   104,806   1.1   97.9   43.2  
  Robertsville   Conventional Hydro   0.6   622   0   100   12.2  
  Bantam   Conventional Hydro   0.3   993   1.1   98.9   37.2  
Eastern Hydroelectric System                          
  Scotland   Conventional Hydro   2.2   6,394   N/A ** 90.4   35.1  
  Tunnel   Conventional Hydro   2.1   8,506   N/A ** 98.4   48.6  
  Taftville   Conventional Hydro   2.0   6,452   N/A ** 91.8   40.6  
  Tunnel ICU   Internal Combustion Unit   20.8   788   <1   97.0   0.7  
       
 
             
TOTAL       1,288.9   1,645,412       93.3 % 15.6 %

(Source: the independent technical consultant's report included as Appendix A to this prospectus)


*
Based on its efficiency (i.e., pumping-to-generating ratio of 1.35x), the maximum capacity factor for Northfield would be 42.6%.

**
For Scotland, Tunnel and Taftville, forced outage rate statistics are not maintained.

    Low Hydrology Risks.  Our largest asset, Northfield, is less affected than conventional "run-of-river" facilities by the variability of precipitation and run-off over time, which would impact the flow level of the Connecticut River. Northfield's lower reservoir is controlled by the Turners Falls dam with a normal water level that varies between 176 and 185 feet associated with the pump/generation cycle at the facility. The lower reservoir water storage in this "wedge" of water is dedicated to Northfield pumped storage operations. During periods of low flows in the Connecticut River, the outflow at Turners Falls dam equals the inflow and the storage amount required by Northfield to operate remains fairly constant. Because of this, low flows pose little risk to the operation of Northfield.

    Continuity of Experienced Operators and Management.  Our assets are operated by an experienced staff. Under our contract with Northeast Generation Services, we have been able to access the experienced station management and operation and maintenance staff that had operated the assets on behalf of Connecticut Light & Power and Western Massachusetts Electric. We believe this enhances the continued dependable operation of our power plants.

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    Ability of Conventional Hydroelectric Power to Meet "Green Power" Portfolio Requirements.  In a number of New England states, laws that have been enacted but are not yet effective are expected to require competitive retail electricity suppliers to have a "green" component in their supply portfolios. As a renewable resource, our conventional hydroelectric assets are expected to help Select Energy meet these "green power" portfolio requirements in some New England states.

Business Strategy

    Our goal is to continue to be the generation arm of Northeast Utilities' deregulated energy business. We plan to continue to profitably operate our generating facilities in an economic and efficient manner. Future plans could potentially include the addition of more generating resources through either development or acquisition. These resources could provide additional diversity to our current portfolio of assets. However, due to current limitations imposed by the SEC on the amount that Northeast Utilities may invest in exempt wholesale generators such as Northeast Generation, the acquisition of additional generating assets would require the approval of the SEC. We cannot guarantee that the SEC would approve any such acquisition.

    To implement our strategy we plan to:

    Maintain a Stable Stream of Revenues and Cash Flows through our Agreement with Select Energy. Under the power purchase and sales agreement with Select Energy, Select Energy has agreed to purchase all of our power and capacity at specified prices. The agreement with Select Energy provides us with a stable stream of revenues, with 85% of the payments being made on a fixed price basis independent of the amount of generation produced by the facilities. We anticipate a renewal of this contract with Select Energy after December 31, 2005. However, we cannot assure you that a renewal will be available on attractive terms or that both parties will wish to continue the contract when it is up for renewal. Prices on any renewal of our contract with Select Energy may not reflect market prices.

    We believe that in the event that we do not continue our contract with Select Energy beyond the current term, we will be able to sell the products from our generating assets either in the spot market or to a third party and continue to capture the value from our facilities. We will continue to maximize the output from our facilities through ongoing improvement programs designed to upgrade capacity, where appropriate, shorten unit outages and enhance our level of availability.

    Pursue Opportunities for Peak Rate Power and Ancillary Service Revenues if the Select Energy Contract Terminates.  Our pumped storage and internal combustion assets provide quick-start, reserve and other ancillary services that are critical to NEPOOL. Under our agreement with Select Energy, Select Energy has the ability to market these services in the NEPOOL markets and benefits from any revenues so generated. For example, Northfield can provide spinning and operating reserves and automatic generation control. These ancillary service products are important for system reliability and provide Select Energy with additional revenue streams from our assets. If our agreement with Select Energy were to terminate, we would be able to benefit directly from sales of these services in the NEPOOL markets, and we expect that we would aggressively market our peak rate power and ancillary service capabilities.

    Increase Our Margins by Continuing to Manage Costs.  In order to increase our margins, we have a continuing commitment to effectively manage our costs of operation. Working closely with the operator of our facilities, Northeast Generation Services, we continually strive to reduce our costs, while maintaining our efficiency and reliability. We utilize services from Northeast Utilities Service Company for corporate support, managerial and administrative services.

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    Pursue Attractive Growth Opportunities in the New England, New York and Mid-Atlantic Region.  We believe we have the potential for future growth of our portfolio of assets through the acquisition of existing power plants or the development of new power plants, either on our own or in partnership with other companies within the New England, New York and mid-Atlantic region. The addition of assets would be accomplished in a disciplined manner to enhance the competitiveness and diversity of our portfolio of generating units, in terms of both location and fuel source. The addition of assets would effectively dovetail with Northeast Utilities' strategy of growth of its wholesale marketing, risk management and trading activities in this target region. Any such asset acquisition would require the approval of the SEC.

    Assist Northeast Utilities in its Goal of Growing its Deregulated Power Business.  As the generation arm of the deregulated market segment of Northeast Utilities, and as a major source of power generation for Select Energy, we support and assist in the development of the deregulated power business of Northeast Utilities.

    Maintain our Commitment to the Environment.  We seek ways to improve our performance while maintaining a strong commitment to environmental stewardship at our power plants.

Competition

    The Energy Policy Act laid the groundwork for the current competitive framework in U.S. wholesale electricity markets. This legislation expanded FERC's authority to order electric utilities to open their transmission systems to allow third-party suppliers to transmit, or "wheel," electricity over their lines. In 1996, FERC issued a series of orders that resulted in expanded open access to transmission lines, providing eligible third-party wholesale marketers comparable transmission access. These actions have enabled power marketers, independent power producers, exempt wholesale generators and utilities to compete actively in wholesale markets, while giving consumers the right to choose their energy suppliers and letting competition set the price of the generation component of electricity bills in deregulated areas.

    During the last several years, additional legislation has been introduced to further encourage competition at the retail level (often referred to as "customer choice"). It is expected that efforts at the federal level to restructure the nation's electricity industry, encourage competition and greater industry flexibility and allow retail customer choice will continue. At present, the timing and effect of federal restructuring legislation cannot be predicted with any degree of certainty. Nevertheless, an increasing number of states have enacted legislation to open their markets to customer choice and retail competition. In the NEPOOL market region, several states have already begun the process of restructuring their electricity markets. Retail power markets opened to competition in Massachusetts and Rhode Island in 1998, and competition began in Connecticut and Maine in 2000. New Hampshire began phasing in competition in 2001.

    During the transition of the energy industry to competitive markets, it is difficult to assess our position versus the position of existing power generators and new market entrants. So long as Select Energy remains the sole customer for our energy and capacity, we could be affected by any competitive pressures experienced by Select Energy. As the power market continues to evolve, those pressures could come from existing generators or new generators entering the marketplace. Existing competitors would include independent power producers (with or without trading capabilities), other utilities that form generation and trading affiliates, wholesale power marketers or some combination of these. There is a proliferation of new merchant plants proposed or under construction in the NEPOOL market that we expect will consist primarily of combined cycle plants. While we anticipate that this additional generating capacity in the NEPOOL market will tend to drive down both on-peak and off-peak prices, we do not believe that it will have a significant effect on Northfield's economics since it will still be capable of capturing any differential between on-peak and off-peak prices. In addition, whether Select

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Energy remains our sole customer or whether we begin selling directly to other parties, we believe that Northfield is likely to remain the single largest source of pumped-storage capacity in the NEPOOL service area for the foreseeable future, and new combined cycle generating facilities will not be able to provide the quick-start peaking capacity needed in NEPOOL and provided by Northfield.

Our Generating Facilities

    The power generating assets that we acquired in March 2000 constitute all of our facilities and are divided among three systems and their constituent generating stations: the Northfield Mountain-Connecticut River System, the Housatonic Hydroelectric System and the Eastern Hydroelectric System.

    Northfield Mountain-Connecticut River System.  The Northfield Mountain-Connecticut River System is located along the Connecticut River in towns in Massachusetts, New Hampshire and Vermont, and includes one major pumped storage station and two conventional hydroelectric power stations. Northfield was previously owned 81% by Connecticut Light & Power and 19% by Western Massachusetts Electric. The Cabot and Turners Falls No.1 stations were owned solely by Western Massachusetts Electric.

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    Each of the facilities in the Northfield Mountain-Connecticut River System has a projected remaining economic life of 40 years.

    Housatonic Hydroelectric System.  The Housatonic Hydroelectric System is an integrated system of hydroelectric plants on or near the Housatonic River and its tributaries, and includes six conventional hydroelectric stations and one combined hydroelectric and pumped storage station. The facilities of the Housatonic Hydroelectric System were previously owned by Connecticut Light & Power. The system consists of the Falls Village, Bulls Bridge, Rocky River, Shepaug Stevenson Robertsville and Bantam stations.

    The Robertsville and Bantam stations each have projected remaining economic lives of 20 years. The other stations on the Housatonic Hydroelectric System have projected remaining economic lives of 40 years.

    Eastern Hydroelectric System.  The Eastern Hydroelectric System is located along the Shetucket and Quinebaug rivers in Connecticut, and includes three conventional hydroelectric plants and one internal combustion unit. The facilities of the Eastern Hydroelectric System were previously owned by

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Connecticut Light & Power. The system consists of the Scotland project and the Taftville and Tunnel stations.

    The Tunnel station also includes combustion generation in the form of the Tunnel internal combustion unit, which is located at the station and operated at peak service times. The unit is a Pratt & Whitney FT4A-8 Turbojet Power Pac series gas turbine jet engine which runs on jet fuel, is quick-start capable and has a rated capacity of 20.8 megawatts. The Tunnel internal combustion unit was commissioned in 1969.

    Each of the stations in the Eastern Hydroelectric System has a projected remaining economic life of 20 years.

Employees

    We have no employees and rely on Northeast Generation Services to provide the operating personnel for all of our facilities. Northeast Utilities Service Company supplies us with certain corporate services. Northeast Generation Services employs approximately 102 people at our several facilities. Northeast Generation Services employs nearly all the same people to operate our facilities that operated those facilities previously for Connecticut Light & Power and Western Massachusetts Electric. Employees at Northfield and our Falls Village station do not belong to a union. Employees at our other facilities, except for certain management, clerical and technical employees, are members of the International Brotherhood of Electrical Workers Union. There have been no arbitrations filed against Northeast Generation since it acquired the facilities.

Insurance

    We maintain insurance coverages that we believe are consistent with those normally carried by companies engaged in the same or similar businesses owning similar properties and operating in the same or similar locations. The insurance program includes all-risk property insurance that provides replacement value coverage for all real and personal property, losses from machinery breakdowns and losses from business interruption for large generating assets. All of these policies are subject to certain sublimits. We also carry general liability insurance covering liabilities to third parties for bodily injury or property damages resulting from operations, automobile liability insurance and excess liability insurance. Further, we have the benefit of title insurance and workers' compensation insurance. Limits and deductibles in respect of these insurance policies are comparable to those carried by other electric generating enterprises with similar capital structures and owning and operating facilities of like size and type as our facilities.

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Legal Proceedings

    The Connecticut Department of Revenue Services has challenged the computation of real estate conveyance taxes due in connection with our acquisition of facilities from Connecticut Light & Power in March 2000. The issue relates to how much of the acquisition price was attributable to real estate as opposed to other assets. The deficiency claimed by the Connecticut Department of Revenue Services is approximately $0.6 million. We are currently unable to predict the outcome of this dispute.

    Connecticut Light & Power is a defendant in litigation brought by the Schaghticoke Tribal Nation concerning land originally purchased from overseers of the tribe by predecessors in interest to Connecticut Light & Power and thereafter conveyed to us. The land claimed by the tribe includes land within the project boundary of our Bulls Bridge facility and is land over which we have flowage rights. The tribe claims that the land should be returned to the tribe because the original purchase from the tribe was not approved by the U.S. Congress, as required by the Indian Nonintercourse Act. The tribe also claims that Connecticut Light & Power appropriated ancient burial grounds, and seeks money damages based on the fair rental value of the property until the land is returned. The tribe must obtain federal recognition for the Indian Nonintercourse Act to apply and for the tribe to be able to prosecute its claim. We do not expect the administrative process required for federal recognition by the Bureau of Indian Affairs to conclude until 2003. If the tribe is successful in obtaining federal recognition, it may prosecute the land claims at that time. Connecticut Light & Power believes the disputes to be covered by a prior settlement of earlier litigation. We have not been joined in the litigation thus far, and do not believe that the outcome of the litigation brought by the tribe will have a material adverse effect upon us.

    Except for the claims described above and the relicensing proceedings described below under "Regulation—Electric Regulatory Matters—Federal Law," beginning on page 61, and proceedings described under "Regulation—Environmental Regulatory Matters," beginning on page 62, we are not currently involved in any legal proceedings the outcome of which, if determined against us, would have a material adverse effect on our financial condition or results of operations.

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SUMMARY OF THE INDEPENDENT TECHNICAL CONSULTANT'S REPORT

    S&W Consultants, Inc. ("S&W"), an independent technical consultant, prepared a comprehensive independent technical report, dated October 11, 2001, a copy of which is attached as Appendix A to this prospectus. S&W prepared an independent technical review of the facilities in December 1999. The October 11, 2001 report, which we refer to as the "S&W report" or the "independent technical consultant's report," is the result of a re-evaluation of our facilities and presents updated findings. S&W is an engineering and consulting firm with expertise in the electric power industry.

    The S&W report includes their assessment of our facilities, based on, among other things, a review of the available technical data, historical performance and cost data, and visits to each facility. The S&W report presents their findings and conclusions regarding, among other things:

    Subject to the information contained and the assumptions relied upon in the S&W report, S&W expressed a number of opinions with respect to the facilities, which opinions are set forth in full in Appendix A. In summary, S&W is of the opinion that:

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Station Performance Statistics (Average, %)

System

  Historical
Availability, 1996-2000

  Historical
Capacity Factor,
1996-2000

  Projected
Capacity Factor,
2001-2009*

Northfield Mountain-Connecticut River System            
Northfield Mountain Project   92.6   11.5   17.5
Cabot Station   97.9   59.4   57.1
Turners Falls No.1 Station   96.7   32.0   27.3

Housatonic Hydroelectric System

 

 

 

 

 

 
Falls Village Station   97.6   48.4   42.4
Bulls Bridge Station   89.2   59.5   61.0
Rocky River Station   98.5   5.2   5.9
Shepaug Station   96.8   36.3   31.7
Stevenson Station   97.9   43.2   40.5
Robertsville Station   100.0   12.2   24.7
Bantam Station   98.9   37.2   50.0

Eastern Hydroelectric System

 

 

 

 

 

 
Scotland Station   90.4   35.1   41.5
Tunnel Station (hydroelectric)   98.4   48.6   51.8
Tunnel Station (internal combustion unit)   97.0   0.7   1.0
Taftville Station   91.8   40.6   36.3

*
The projected capacity factor at the conventional hydroelectric stations is based on statistical patterns of river flow. Predictions of river flow for individual years would not be valid.

We are able to access the experienced station management, operations and maintenance staff necessary for the continued safe and reliable operation and effective maintenance of the facilities. The projected staffing levels, projected operating and capital expenses, maintenance and overhaul schedules and spare parts inventories are generally reasonable for the intended utilization of the facilities.

Some of the facilities are undergoing FERC license renewals that could affect the future utilization of those facilities. The issues facing them are ones common to most other hydroelectric generation facilities in New England, including fish passage, minimum flow requirements and impoundment level fluctuations.

While environmental reports prepared for our facilities point to several possible areas of contamination, the costs of any required remediation, although difficult to estimate, probably will not exceed $2 million and, in general, the hydroelectric plants have been operated responsibly from an environmental point of view.

Operational plans for the power plants take into account identified environmental issues. Our projected utilization of the power plants is based on sound environmental principles and the existing body of regulatory knowledge.

The general trend for Northfield is that annual generation increases slightly as average annual river flow decreases. Conversely, the data indicates that the conventional "run-of-river" plants generate less energy at lower average annual flows. The results of the flow analyses, while approximate, also indicate that generation from Northfield has not been significantly affected by historical flow variations, either flood or drought. These combined results tend to reduce overall sensitivity of the facilities to fluctuations in the hydrologic cycle.

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Financial Projections

    S&W prepared financial projections for our facilities for the years 2002 through 2026. S&W's revenue projections through December 31, 2005 are based on contract sales pursuant to our power sales agreement with Select Energy. S&W's projected cash flow summary for the years 2002 through 2005 is presented below.


Projected Cash Flow Summary

 
  Year Ended December 31
 
 
  2002
  2003
  2004
  2005
 
 
  (in thousands, except for ratios)

 
Net Revenues                          
  Contract sales   $ 136,448   $ 138,131   $ 138,131   $ 138,131  
  Market sales                  
   
 
 
 
 
  Total net revenues   $ 136,448   $ 138,131   $ 138,131   $ 138,131  

Non-Fuel Expense

 

 

 

 

 

 

 

 

 

 

 

 

 
  Fixed operations and maintenance expense     18,808     20,177     18,858     18,221  
  Indirect operations and maintenance expense     5,041     5,193     5,350     5,513  
  Property taxes     7,793     7,969     8,076     8,187  
   
 
 
 
 
  Total non-fuel expense   $ 31,642   $ 33,339   $ 32,284   $ 31,921  

EBITDA

 

 

104,806

 

 

104,792

 

 

105,847

 

 

106,210

 
Changes in working capital     (200 )   (172 )   (259 )   (205 )
Capital expenditures     (11,896 )   (9,875 )   (7,486 )   (2,360 )
   
 
 
 
 
Cash flow available for debt service   $ 92,710   $ 94,745   $ 98,102   $ 103,645  

Debt service

 

$

57,896

 

$

59,659

 

$

62,753

 

$

67,104

 
Debt service coverage ratio     1.60x     1.59x     1.56x     1.54x  

    S&W's financial projections for the remaining years, through 2026, include revenue estimates that are based on market pricing data provided in the power market report provided by PA Consulting Services, Inc., an independent market consultant, which is included as Appendix B to this prospectus. In projecting future prices and revenue for energy and capacity, the power market report examined three cases. The base case incorporates a forecast for the price of gas and oil fuels based on actual spot and futures gas and oil prices in 2000 and 2001, as well as a "consensus" forecast of prices through 2020 from four major forecasters. Case 2 tests the sensitivity of the base case to lower fuel prices. The overall effect of Case 2 is lower compensation for capacity, as well as lower energy prices, throughout a majority of the study period as compared to the base case. Case 3 tests the sensitivity of the base case to excess merchant plant construction. The result of Case 3 is lower compensation for capacity than the base case. S&W used the projected market data to develop projected cash flows for our facilities for the years 2006 through 2026 for each of the three cases. While the power market report does not extend beyond 2020, S&W extrapolated from the projected market data through 2020 to develop cash flow projections through 2026.

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    S&W's projected average and minimum (lowest projected) debt service coverage ratios for each of the three cases for the years 2006 through 2026 are presented below.


Projected Debt Service Coverage Ratios

 
  Period from 2006-2026
 
  Average
  Minimum
Base case   3.33x   2.69x
Case 2—low fuel prices   3.03x   2.49x
Case 3—excess construction   3.31x   2.56x

    The S&W financial projections show lower revenues for the years 2006 and thereafter for all three cases as a result of S&W's assumption for the purposes of the report that the Select Energy contract will terminate on December 31, 2005. The debt service coverage ratios are in each case higher in the years 2006 and thereafter, however, because the required debt service payments on the bonds will be lower after the Series A Secured Bonds are repaid. The S&W financial projections do not reflect certain planned capital expenditures for fish passages required in the Housatonic Hydroelectric System in 2014 and 2024, but the financial projections do show more than adequate free cash flow to cover these expenditures, which are expected to total approximately $14 million in constant 2000 dollars. S&W's projected cash flow summary for each of the years 2006 through 2026 begins on page A-87 in the S&W report in Appendix A to this prospectus.

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SUMMARY OF THE INDEPENDENT MARKET CONSULTANT'S REPORT

    PA Consulting Services, Inc. ("PA"), an independent power market consultant, formerly known as PHB Haigler Bailly, Inc., prepared the independent market consultant's report dated December 20, 2000, which we refer to as the "power market report," a copy of which is attached as Appendix B to this prospectus.

    In the preparation of the power market report and the opinions expressed in it, PA has made the following qualifications with respect to the information contained in its report and the circumstances under which its report was prepared: (i) some of the information in the power market report is necessarily based on predictions and estimates of future events and behavior; (ii) those predictions or estimates may differ from those which other experts specializing in the electricity industry might present; (iii) the provision of a report by PA does not obviate the need for potential investors to make further appropriate inquiries as to the accuracy of the information included in it, or to undertake an analysis of their own; (iv) the power market report is not intended to be a complete and exhaustive analysis of the issues and does not consider some factors that are important to a potential investor's decision making; and (v) PA and its employees do not accept liability for loss suffered in consequence of reliance on the power market report, and nothing in the power market report should be taken as a promise or guarantee as to the occurrence of any future events.

    The power market report provides market price projections used in the independent technical consultant's report.

Assumptions

    In developing its energy price forecasts for the market served by us, PA relied on various assumptions, including assumptions concerning the price of alternative energy sources (natural gas, fuel oil and coal), the operating characteristics of existing generation units (including fossil fuel, hydroelectric and nuclear power units) and increases and decreases in energy generation capacity through the building of new units, the upgrade of existing units and the decommissioning of older units and nuclear power plants and other assumptions detailed in the power market report. PA also assumed that peak demand in the entire NEPOOL market would grow at a forecasted annual compound rate of approximately 2% per year from 2000 through 2020, and that the system-wide reserve margin in that period would remain at approximately 15%. The reserve margin is that amount of additional capacity that must be present in order to ensure that adequate generation capacity is available in the market. After 2002, the forecasts assume that new generating units are developed and put into use to meet the reserve margin.

    The power market report price forecast is limited to the market represented by the western region of NEPOOL, which is the region currently served by the electric utilities owned by Northeast Utilities.

Market Forecasts

    In estimating the value of electric generation units based on price levels and volatility, PA utilized a proprietary market valuation process that integrates the production-cost model analysis and volatility analysis. The forecast is composed of two price streams: those associated with the system marginal cost of producing in the energy market and the additional compensation for capacity that must be present in the market to ensure that adequate generation capacity is available in the market. The two streams are combined in all-in price forecasts in three different market scenarios referred to as "cases," which are the three cases used in the S&W report. The cases reflect PA's best assessment of future market conditions and sensitivities on some of the conditions for the NEPOOL market. PA also subjected each of these cases to a separate volatility analysis. The sensitivities developed in Cases 2 and 3 may not present all of the risk factors to be considered, however, as other market conditions could also change and affect the revenues from the facilities.

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OUR AFFILIATES

Northeast Utilities

    Northeast Utilities is engaged, through its subsidiaries, in the generation, transmission, distribution and sale of electricity to customers in the northeast region of the United States. The Northeast Utilities system serves approximately 30 percent of New England's electric needs and is one of the 25 largest electric utility systems in the country in terms of revenues. The Northeast Utilities system also furnishes natural gas service in much of Connecticut through its Yankee Gas Services Company subsidiary.

    The Northeast Utilities system is the leading owner of electric transmission lines in New England. Northeast Utilities has announced plans to construct two 345 kilovolt transmission lines from inland Connecticut into Norwalk, Connecticut and to help rebuild an existing 138,000 volt transmission line beneath Long Island Sound. Northwest Utilities has also proposed building a new direct current transmission line from Norwalk, Connecticut to western Long Island. Together, these projects are expected to provide increased transmission capability, access to competitively priced power and improved power supply reliability for customers in Connecticut and New York. The projects will require various federal and state regulatory approvals.

    Through NU Enterprises, Northeast Utilities owns a number of deregulated energy and telecommunications businesses, including Northeast Generation, Select Energy, Northeast Generation Services, Select Energy Services Inc. and Mode 1 Communications, Inc. Select Energy Services Inc. provides energy efficiency engineering and design services primarily for governmental and institutional clients, including other utilities, in the eastern United States. Mode 1 is engaged in the development of various telecommunications projects in the northeastern United States.

    For the first nine months of 2001, Northeast Utilities earned $193.5 million on revenues of $5.1 billion. Excluding the cumulative effect of an accounting change, Northeast Utilities earned $216.0 million for the first nine months of 2001. After taking into effect a number of extraordinary items associated with electric utility industry restructuring in New Hampshire and the discontinuation of Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation," Northeast Utilities sustained a loss of $28.6 million in 2000 on revenues of $5.9 billion. Earnings before these items in 2000 were $205.3 million.

    The common shares of Northeast Utilities are traded on the New York Stock Exchange. Northeast Utilities is also registered as a public utility holding company under the Public Utility Holding Company Act. Additional and more detailed information concerning Northeast Utilities and its subsidiaries is set forth in its annual and periodic reports filed with the SEC. See "Where You Can Find More Information," on page 110.

Select Energy

    Select Energy is the marketing and trading subsidiary within Northeast Utilities' deregulated energy business. Select Energy sells multiple energy products including electricity, natural gas and oil to wholesale and retail customers in the northeastern United States.

    Select Energy's retail operations commenced in 1997, and its wholesale marketing operations commenced in December 1998. Select Energy evolved from the Northeast Utilities regulated wholesale marketing group. Our facilities represent the bulk of the Northeast Utilities' owned generating assets needed to execute Select Energy's supply strategy for energy marketing. The chart below illustrates how Select Energy manages its load obligations to wholesale and retail customers through a portfolio consisting of generating assets owned indirectly by Northeast Utilities (including our facilities) and supply acquired pursuant to contracts with unaffiliated third parties.

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Select Energy Management of Load Obligations

LOGO

    Select Energy is licensed to provide retail electric supply in Connecticut, Delaware, Maine, Maryland, Massachusetts, New Jersey, New York, Pennsylvania and Rhode Island. Within these states, Select Energy is currently qualified to do business with approximately 36 electric distribution companies and 52 gas distribution companies to provide retail services. Select Energy's goal is to be the regional leader in providing energy services to those northeastern and mid-Atlantic markets opened to retail competition. In 2000, Select Energy provided more than 5,000 megawatts of standard offer load, making it one of the largest providers of standard offer service in New England. During 2000, Select Energy provided several utilities with standard offer full requirements service and default services, comprising in the aggregate approximately 43% of its 2000 revenues. This includes providing 3,000 megawatts to an unaffiliated Massachusetts utility. Select has entered into similar contracts with various other unaffiliated entities for service during 2001.

    On January 1, 2000, Select Energy became responsible for serving one-half of Connecticut Light & Power's standard offer load for a four year period. This equates to approximately 2,000 megawatts annually for each of the four contract years. Approximately 27% of Select Energy's 2000 competitive energy revenues came from this contract. This contract extends through the end of 2003, at fixed prices. The servicing of supply obligations such as the contract with Connecticut Light & Power subjects Select Energy to market risk. This risk is partially mitigated by Select Energy entering into contracts to purchase energy from providers such as ourselves, as well as the purchase of other resources in the energy marketplace. Select Energy has contracted to acquire the vast majority of the energy supplies it expects to need in 2002 and 2003 to serve its current power supply obligations. As a result, Northeast Utilities considers the energy supply book of Select Energy to be satisfactorily hedged for both 2002 and 2003.

    Select Energy has also entered into contracts with various retail customers to provide electric generation supply services at fixed rates. Under these retail contracts, Select Energy has the option to have the local utility provide electric generation services through the utility's standard offer service tariff rate. If Select Energy elects to exercise this option, it is obligated to compensate the customer for the difference between the contract price and standard offer rate. For the year ended December 31,

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2000, the required payments to customers under these contracts totaled approximately $3.6 million. These payments may increase or decrease in the future. Policies and procedures have been established to manage the exposure to this risk, including the use of risk management instruments and the purchase of insurance. As a result of the recent significant decrease in energy prices, Select Energy has re-enrolled many of the customers it had previously opted to have the local utility serve, and has hedged the associated supply obligations at favorable energy costs. In addition, beginning in January 2000, Select Energy assumed responsibility for serving approximately 500 megawatts of market-based wholesale contracts throughout New England with electric energy supply that was previously provided by Connecticut Light & Power and Western Massachusetts Electric. For the most part, the prices are fixed by contract and applicable to actual volumes.

    Select Energy has a number of contracts to supply electricity to high volume retail electric customers in states throughout the northeast and mid-Atlantic region. Generally, these contracts have a one year term at fixed rates. As of June 30, 2001, these contracts represented, in the aggregate, approximately 225 megawatts of supply obligations to about 7,000 service locations. This retail load establishes Select Energy as one of the largest competitive retail suppliers in New England as measured by megawatt load. There is no single retail customer that accounts for over 10% of Select Energy's expected retail revenues.

    The energy marketing business is intensely competitive. There are many large energy companies bidding for business in the increasingly restructured electric and natural gas markets. In 2000, the sharp increases in the cost of power supply caused by the extreme increases in oil and gas fuel costs, among other things, provided significant challenges and opportunities for Select Energy. Select Energy increased its 2000 revenue by more than 200% over the 1999 revenue level, reporting $1.8 billion in 2000, as compared with $554.9 million in 1999. In the first nine months of 2001, Select Energy sustained a loss (before the cumulative effect of an accounting change) of $40.4 million on revenues of $2.0 billion This loss was due primarily to high replacement power purchases as a result of extended outages at two nuclear plants that supply electricity to Select Energy, as well as higher energy costs to serve customers. Revenues for the first nine months of 2001 increased by over $584.7 million, or about 42%, over revenues for the corresponding period of 2000, due to sales growth and higher energy prices.

    Disputes pertaining to interpretation and implementation of NEPOOL market rules have arisen with respect to various competitive product markets. In certain cases, Select Energy and the Northeast Utilities operating companies stand to gain as a result of resolution of such disputes. In other cases, Select Energy and the Northeast Utilities operating companies could incur additional costs as a result of resolution of the disputes. These disputes are in various stages of resolution through alternative dispute resolution and regulatory review. It is too early to ascertain the level of potential gain or loss that may result upon resolution of these issues.

    Select Energy also markets natural gas, and during 2000 Select Energy significantly increased its competitive retail and wholesale natural gas business. Select Energy's revenue from this business segment increased from approximately $21 million in 1999, to approximately $222 million in 2000. As of December 31, 2000, Select Energy had contracts with approximately 2,000 retail gas customers, primarily located in Connecticut, Massachusetts and Pennsylvania. These contracts generally have one-year terms and include only commercial, institutional and industrial accounts. There is no single retail gas customer that accounts for over 5% of Select Energy's expected retail gas revenues. In 2000, Select Energy's retail gas revenues were approximately $68 million, representing a 450% increase over 1999. The competitive retail gas business has contracted for approximately $100 million in gas sales, which will extend into 2002.

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Northeast Generation Services

    Northeast Generation Services is our affiliate and was formed in 1999 to provide energy-related operation and maintenance services to the owners of generating facilities and the industrial market in the northeastern United States. Northeast Generation Services provides turnkey management and operation services, and performs a full range of industrial and consulting services. Northeast Generation Services provides industrial services such as maintenance, permitting and environmental and specialized electrical testing services to large and medium-sized industrial businesses. Northeast Generation Services also provides consulting services to these customers, including engineering and design, construction management, asset development, due diligence reviews and environmental regulatory and permitting services. During 2000, Northeast Generation Services' revenues were approximately $44.4 million, including $13.8 million or 31.1% from its work related to our sites. The revenues of Northeast Generation Services are expected to grow significantly in 2001 as a result of the acquisition of an electrical contracting business and a number of pending contracts with new and repeat customers.

    We have a contract with Northeast Generation Services under which Northeast Generation Services provides us with goods and services necessary for the operation of our business on a daily basis, including management, supervision, operations, maintenance, administration, labor, consumables, and water. Northeast Generation Services contracts with a mutual affiliate of ours, Northeast Utilities Service Company, to provide some of the personnel at our facilities.

Northeast Utilities Service Company

    Northeast Utilities Service Company is a wholly-owned subsidiary of Northeast Utilities that provides centralized accounting, administrative, information technology, engineering, financial, legal, operational, planning, purchasing and other services to the Northeast Utilities system companies.

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REGULATION

Electric Regulatory Matters

    Federal Power Act.  FERC approves rates, terms and conditions for wholesale sales of electricity and transmission in interstate commerce for private utilities, power marketers, power pools, power exchanges, independent system operators and regional transmission organizations. FERC oversees the issuance of certain debt and equity securities, the assumption of obligations and liabilities, and mergers and acquisitions. FERC also reviews the holding of officer and director positions by top officials in utilities and other firms with which they do business. Finally, FERC reviews rates set by the federal power marketing administrations, confers exempt wholesale generator status, certifies qualifying small power production and cogeneration facilities and licenses hydroelectric facilities. For these purposes, FERC acts under the legal authority of the Federal Power Act, the Public Utility Regulatory Policies Act of 1978 and the Energy Policy Act.

    FERC's authorization for an entity (such as an exempt wholesale generator) to sell electric power at wholesale market-based rates also typically contains an exemption from much of the traditional public utility company rate regulation.

    Several of our facilities are covered by FERC hydroelectric project licenses issued under Part I of the Federal Power Act:

    We are an electric wholesale generator and sell our power only into the wholesale market through our agreement with Select Energy. As a wholesaler of power, we are a "public utility" subject to the Federal Power Act. The market-based rate authorization that we have received from FERC exempts us from some, but not all, of the Federal Power Act regulations, including traditional cost-based rate regulation. However, because we are a wholesale marketer that owns its own generation facilities, we must file information concerning long-term transactions (such as our agreement with Select Energy) and quarterly transaction summaries with FERC.

    Public Utility Holding Company Act.  The Public Utility Holding Company Act provides that any corporation, partnership or other entity or organized group that owns, controls or holds power to vote 10% or more of the outstanding voting securities of a "public-utility company" or a company that is a "holding company" of a public-utility company is subject to registration and regulation under the Public Utility Holding Company Act as a registered holding company, unless an exemption is established or an order is issued by the SEC declaring it exempt. Registered holding companies under the Public Utility Holding Company Act are required to limit their utility operation to a single integrated utility system and to divest any other operations not functionally related to the operation of the utility system. In

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addition, a public-utility company that is a subsidiary of a registered holding company under the Public Utility Holding Company Act is subject to financial and organizational regulation, including approval by the SEC of certain of its financing transactions. However, under an amendment effected by the Energy Policy Act, a company engaged exclusively in the business of owning and/or operating a facility used for the generation of electric energy exclusively for sale at wholesale may be exempted from the Public Utility Holding Company Act regulation as an electric utility by operation of its status as an exempt wholesale generator as defined under Section 32 of the Public Utility Holding Company Act. We qualify as an exempt wholesale generator and FERC has confirmed that status. We are still subject to regulation related to certain intercompany relationships under the Public Utility Holding Company Act.

    If a "material change" in facts occurs that might affect our continued eligibility for exempt wholesale generator status, we have 60 days in which to (i) file a written explanation of why the material change does not affect our exempt wholesale generator status, (ii) file a new application for exempt wholesale generator status or (iii) notify FERC that we no longer wish to maintain exempt wholesale generator status. If we were to lose our exempt wholesale generator status, we would be subject to regulation under the Public Utility Holding Company Act as a public utility company. Since Northeast Utilities is already a registered public utility holding company, it is unlikely that such a change would have a material adverse effect on our operations.

    Connecticut.  Pursuant to Title 16, Chapter 277 of the Connecticut General Statutes, a "public service company" includes electric companies, but does not include exempt wholesale generators. In addition, a generator of electric power is only a public service company if it owns transmission wires that cross a public right-of-way and serves retail customers, neither of which conditions apply to us. Consequently, we are not regulated by the Connecticut Department of Public Utility Control.

    Massachusetts.  Under Chapter 164 of the Massachusetts General Laws we are a "wholesale generation company," which is defined as "a company engaged in the business of producing, manufacturing or generating electricity for sale at wholesale only." As an exempt wholesale generator, we do not provide electricity directly to retail customers, but instead sell our electric generation capacity and output at wholesale only to Select Energy. Wholesale generation companies are subject to very limited regulation by the Massachusetts Department of Telecommunications and Energy. As we currently operate our business, there is no basis for regulatory oversight by the Massachusetts Department of Telecommunications and Energy.

Competitive Market Rules and Deregulation

    Federal.  The Energy Policy Act laid the groundwork for a competitive wholesale market for electricity. Among other things, the Energy Policy Act expanded FERC's authority to order wholesale wheeling, thus allowing qualifying facilities under the Public Utility Regulatory Policies Act, power marketers and exempt wholesale generators to compete more effectively in the wholesale market.

    In May 1996, FERC issued the first of the Open Access Rules, which require utilities to offer eligible wholesale transmission customers non-discriminatory open access on utility transmission lines on a comparable basis to the utilities' own use of the lines. In addition, the Open Access Rules direct the regional power pools (including NEPOOL) that control the major electric transmission networks to file uniform, non-discriminatory open access tariffs. Issues regarding open access continue to evolve and may be the subject of future regulation and adjudication.

    Over the past few years, Congress has considered various pieces of legislation to restructure the electric industry that would require, among other things, customer choice and the repeal of the Public Utility Holding Company Act and certain provisions of the Public Utility Regulatory Policies Act. The effect of enacting such legislation cannot be predicted with any degree of certainty.

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    State.  The Energy Policy Act did not preempt state authority to regulate retail electric service. Historically, in most states, competition for retail customers has been limited by statutes or regulations granting existing electric utilities exclusive retail franchises and service territories. Since the passage of the Energy Policy Act, the advisability of retail competition has been the subject of debate in federal and state legislative and regulatory forums. Throughout the United States a number of states have taken active steps towards allowing retail customers to choose their electricity suppliers, with incumbent utilities required to deliver such electricity over their transmission and distribution systems ("wheeling"). Several electric utilities are in the process of divesting all or a portion of their generation business or are expected to commence such a process in the foreseeable future, as legislative and regulatory developments drive the industry to disaggregate. Retail competition commenced in Massachusetts in 1998 and in Connecticut in 2000.

Environmental Regulatory Matters

    General.  Our operations are subject to environmental regulation, including requirements with respect to air emissions, discharges to surface water, land use, disposal of wastes, preservation of endangered species and clean-up of contamination. Existing environmental regulations and permitting requirements could require changes to our operations over time, while changes to environmental regulation may also impose additional requirements and operating costs. We will continue to monitor potential regulatory developments that may affect our operations, and we will participate, where appropriate, in any rulemakings that are applicable to us.

    Licensing of Hydroelectric Generating Facilities.  Several of our hydroelectric power facilities are required to possess licenses issued by FERC under Part I of the Federal Power Act. These licenses must be renewed periodically, and such renewal can trigger a review of the environmental impact of the licensed facility. Our facilities are also subject to regulation by other federal, state and local environmental authorities. The facilities that are not within FERC's jurisdiction are nonetheless subject to certain state authorities, including the Connecticut Department of Environmental Protection.

    Northfield Mountain-Connecticut River System.  All of the facilities in the Northfield Mountain-Connecticut River System are subject to FERC authority and licensing requirements. Relicensing will be required for all three facilities in 2018.

    Some areas along the Connecticut River within the Northfield Mountain-Connecticut River System have experienced riverbank erosion, which has been partially attributed to the rise and fall of water levels during pumped storage operations. Although natural river processes may have caused some of the erosion, FERC has directed us to provide for riverbank stabilization in the affected areas. Anticipated compliance costs are included in our financial projections.

    As part of FERC's recent amendment to Northfield's license allowing it to increase its upper reservoir and generate more electricity during times of system emergencies, FERC required us to install a barrier to protect downstream migrating Atlantic salmon smelts during migration periods.

    Housatonic Hydroelectric System Relicensing.  All of the Housatonic Hydroelectric System stations, except for Robertsville and Bantam, are subject to FERC's authority. FERC licensed stations of the Housatonic Hydroelectric System, which are currently separately licensed, are expected to be combined in a single FERC license in 2002. In August 1999, we filed renewal applications and are now in the renewal process. If the renewal proceedings extend beyond the current license expiration date, these facilities would operate under annual renewal authorizations.

    A number of environmental and citizens' groups, including the Schaghticoke Tribal Nation, have intervened in proceedings for the relicensing of the various facilities in the Housatonic Hydroelectric System. While we do not believe there is a realistic possibility that the affected licenses will not be renewed, it is possible that these interventions may slow down the relicensing proceedings or result in

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requirements that increase capital and operating costs associated with the Housatonic Hydroelectric System.

    Under the FERC relicensing process, the state regulatory authority must issue a water quality certification indicating any special conditions required to maintain or achieve the state's water quality standards, which conditions are typically included in the renewed FERC license. In August 2000, the Connecticut Department of Environmental Protection issued a water quality certificate to us which contains a condition that the Falls Village and Bulls Bridge facilities of the Housatonic Hydroelectric System operate in a "run-of- river" condition. This provision eliminates the current practice of daily and weekend pooling of water to refill the water impoundments at the stations and requires that outflow beneath each of the developments equal the inflow to each on an instantaneous basis. Although this will shift some power generation from on-peak periods to off-peak periods, the amount of generation affected during periods of high value, such as summertime extreme peak periods, is expected to be small.

    The August 2000 water quality certificate also imposed the following requirements on the facilities in the Housatonic Hydroelectric System:

    These certification requirements for the fish passages are expected ultimately to require construction costs (in 2000 dollars) of approximately $2 million at Bulls Bridge, $7 million at the Shepaug facility, and $5 million at the Stevenson facility. These anticipated capital expenditures are not included in S&W's financial projections, but we expect to have sufficient cash flow to cover these expenditures. In addition, existing state of the art fish passages for the American eel could require shutting down generators on some evenings in the fall, affecting off-peak generation at the Bulls Bridge, Shepaug and Stevenson facilities. Future fish passage designs could have different requirements. The new oxygenation system is expected to increase the facility's capacity by eliminating or reducing the need to spill water through the facility's spillway during summer generation and making this water available for generation. Anticipated compliance costs for the oxygenation system are included in our financial projections.

    Candlewood Lake in western Connecticut is the upper reservoir for the Rocky River pumped storage facility. Since there is residential real estate located along the shores of the lake and recreational activities take place in and around the lake, Connecticut Light & Power, our predecessor in ownership, followed a water drawdown policy designed to be in harmony with that environment. For example, in alternate winters Connecticut Light & Power would drawdown the water level of the lake to 419 feet in order to kill milfoil weed growing along the shore, or to 424 feet to prevent ice damage to boat ramps, docks and other shorefront properties. Future operation of this drawdown process will be governed by restrictions that will be established in the ongoing FERC relicensing process, which could affect generation from these facilities. In addition, in August 1999 Connecticut Light & Power committed to an approval of conveyance on conservation restrictions on the operation of the reservoir.

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The agreement limits the summer drawdown to 418 feet and the maximum reservoir elevation to 440 feet at all times, essentially confirming traditional operating limits.

    Eastern Hydroelectric System.  The Scotland station of the Eastern Hydroelectric System is also a FERC licensed facility. The facility's present license expires in 2012. In anticipation of relicensing, we expect to begin preparation of the renewal application in 2008 and to be engaged in relicensing proceedings through 2014. It is possible that FERC may consider fish passages a part of relicensing in 2012.

    The Tunnel and Taftville stations of the Eastern Hydroelectric System are not under FERC's jurisdiction because they lie on non-navigable rivers and there has been no post-1935 construction. Accordingly, FERC has not implemented environmental requirements with respect to these facilities. In August 2000, however, we signed a memorandum of agreement with the Connecticut Department of Environmental Protection and the U.S. Fish and Wildlife Service to develop upstream and downstream fish passages at both the Taftville and Tunnel stations of the Eastern Hydroelectric System. Construction must be completed at the Tunnel dam by 2007, and at the Taftville dam by early 2005. We estimate that the study, design, construction and monitoring of the upstream and downstream fish passage at the Tunnel station will cost approximately $1.7 million. We estimate that the study, design, construction and monitoring of the upstream and downstream fish passage at the Taftville station will cost approximately $1.4 million.

    Water Pollution Issues.  Like other hydroelectric facilities, our facilities are subject to permit requirements to protect water quality. The Northfield and Cabot stations operate with National Pollutant Discharge Elimination System ("NPDES") permits issued by the U.S. Environmental Protection Agency under the federal Clean Water Act. The remainder of our facilities in Connecticut, except for the Shepaug facility, which operates under a NPDES permit issued by the State of Connecticut, are presently operating without NPDES permits under a consent decree we entered into with the Connecticut Department of Environmental Protection. That consent decree primarily imposes requirements to study the possibility of regulated releases from our other dams and facilities and could ultimately result in the requirement to obtain NPDES permits for those facilities.

    Soil and Sediment Contamination.  All five of our facilities on the Housatonic River could be affected by contamination of the Housatonic River by polychlorinated biphenyls ("PCBs") that were allegedly released upstream of our facilities by the General Electric Company's Pittsfield, Massachusetts facility.

    The U.S. Environmental Protection Agency has formed a committee to study the effects of the PCB contamination, but has issued no specific conclusions and has not made regulatory recommendations. The applicable state agencies have not established standards for PCB clean-up in river sediments and have not required us to investigate areas of the Housatonic River in which we operate. The U.S. Fish and Wildlife Service has asked us to undertake a sediment transport study to show that present operations do not resuspend PCB contaminated sediments. At present, however, we have very little information upon which to base any projection of costs that might be incurred with respect to this issue.

    Concentrations of polycyclic aromatic compounds, total petroleum hydrocarbons, copper, lead and zinc have been found in sediment samples taken from the upstream impoundment, power canal and the Shetucket River downstream of the main tailrace at the Taftville station of the Eastern Hydroelectric System. Although the State of Connecticut has no current exceedence criteria for sediment, there is a possibility that the state could request an ecological risk assessment and clean-up of these areas. Even though much of this contamination may have come from previous mill activities at the Taftville site, we could be responsible for any clean-up. It is impossible to determine the cost of such a clean-up at the present time.

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    Air Pollution Control.  The Tunnel internal combustion unit began operating in 1969. It operates under a valid general permit that was recently renewed and expires on March 29, 2006. The general permit allows the unit to limit its potential to emit air pollutants and thus avoid any operating permit requirements under Title V of the Clean Air Act Amendments of 1990.

    Under Title I of the Clean Air Act Amendments of 1990, the unit is subject to Phase I of the nitrous oxide (NOx) Reasonably Achievable Control Technology program that was to be implemented by May 1995. Since the unit did not meet the limits imposed by this program by May 1995, the Connecticut Department of Environmental Protection issued a notice of violation and a consent order was entered into requiring the acquisition of the necessary NOxemission reduction credits for continued operation and establishing alternative limitations on nitrous oxide emission rates. Although the original consent order expired in May 1999, the Connecticut Department of Environmental Protection has extended it to May 2003.

    The Tunnel internal combustion unit is subject to a NOx allowance program. Pursuant to this program, we must purchase allowances to offset the unit's NOx emissions on a one-for-one basis each ozone season.

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MANAGEMENT

    Northeast Utilities Services Company provides us and other subsidiaries of Northeast Utilities with management services pursuant to a management and operation agreement described under "Summary of Certain Principal Agreements—Management and Operation Agreement," beginning on page 72.

    NU Enterprises, a wholly owned subsidiary of Northeast Utilities, owns all of our stock and elects our board of directors. Members of the board of directors serve at the pleasure of NU Enterprises. Our officers are appointed by the board of directors and serve at the pleasure of the board.

    The following table gives the name, age and position of each of our directors and officers as of the date of this prospectus.

Name

  Age
  Position

Bruce D. Kenyon   58   President and Director
William J. Nadeau   51   Vice President and Director
Frank P. Sabatino   52   Vice President and Director
William W. Schivley   55   Director
Michelle Gouin   40   Secretary
Jennifer F. Powers   44   Assistant Secretary

    Bruce D. Kenyon has been a director since December 29, 1998 and president since January 4, 1999. He is also president of the generation group for the Northeast Utilities system. Mr. Kenyon serves as the president and chief executive officer of Northeast Generation Services, Northeast Nuclear Energy Company, North Atlantic Energy Corporation and North Atlantic Energy Services Corporation. He worked at Northeast Utilities from 1970 to 1976 at the Millstone Nuclear Plant, but left to join Pennsylvania Power & Light Company where he remained for 14 years and served as a senior vice president of both the nuclear and division operations groups. Mr. Kenyon served as president and chief operating officer at South Carolina Electric & Gas Company from 1990 to 1996. He returned to Northeast Utilities in September 1996 as president and chief executive officer of Northeast Nuclear Energy Company.

    William J. Nadeau has served as a director and vice president since June 1, 2000. He is also vice president and the chief operating officer of Northeast Generation Services. Mr. Nadeau joined Northeast Utilities in 1980 and served in several engineering and managerial positions before joining Northeast Generation Services in January 1999. Mr. Nadeau is also a member of the Board of Directors for Connecticut Yankee Atomic Power Company.

    Frank P. Sabatino has served as a director since June 17, 1999 and vice president since June 1, 2000. He is also Senior Vice President of Power Marketing for Select Energy. Mr. Sabatino began his career with Northeast Utilities in 1970 and joined Select Energy in 1999. He also served as chairman of the executive committee of NEPOOL from 1995 to 1997.

    William W. Schivley has served as a director since March 1, 2000. Mr. Schivley is also the president of Select Energy, which he joined in 1999. Previously, Mr. Schivley founded and served as president and chief operating officer of CMS Electric and Gas Marketing Company. He has 27 years' experience in the energy industry.

    Michelle Gouin has served as Secretary since October 1, 2000. She is also counsel in the Northeast Utilities Service Company legal department.

    Jennifer F. Powers has served as Assistant Secretary since June 1, 2000. Ms. Powers is also the Executive Assistant to the president of Select Energy and has worked in various areas of Northeast Utilities for over 20 years.

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CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

    We have important contractual arrangements with certain of our affiliates as described below.

Power Purchase and Sales Agreement

    We have entered into a power purchase and sales agreement with our affiliate, Select Energy. Under the agreement we have agreed to sell to Select Energy all of our generating capacity associated with the electric energy output and ancillary services of our facilities through December 2005. See "Summary of Certain Principal Agreements," beginning on page 70.

Management and Operation Agreement

    We have entered into a management and operation agreement with our affiliate, Northeast Generation Services. Under the agreement, Northeast Generation Services has agreed to provide us with goods and services necessary for the operation of our business on a daily basis, including management, supervision operations, maintenance, administration, labor, consumables and water. See "Summary of Certain Principal Agreements."

Interconnection Agreements

    In connection with the purchase of our generating assets, we entered into interconnection agreements with our affiliates Connecticut Light & Power and Western Massachusetts Electric to provide us interconnection services where applicable and to define the continuing responsibilities and obligations of each party with respect to the other's property, assets and facilities. See "Summary of Certain Principal Agreements."

Purchase and Sale Agreements

    We purchased our generating assets pursuant to separate purchase and sale agreements with each of our affiliates, Connecticut Light & Power and Western Massachusetts Electric. Pursuant to those agreements, we generally assumed all environmental liabilities associated with the acquired assets, including:

    We did not assume any liability related to either (i) hazardous substances sent by Connecticut Light & Power and Western Massachusetts Electric to off-site disposal facilities prior to our acquisition of the assets, or (ii) criminal violations of environmental laws by Connecticut Light & Power or Western Massachusetts Electric known to either Connecticut Light & Power or Western Massachusetts Electric at the time of the acquisition.

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Tax Allocation Agreement

    We, along with other direct and indirect subsidiaries of Northeast Utilities, are parties to a tax allocation agreement among the various entities of the Northeast Utilities system. The agreement provides for the equitable sharing of individual company federal and state credits, losses and other tax attributes. See "Summary of Certain Principal Agreements."

Support Services Agreement

    We have entered into a support services agreement with our affiliate, Northeast Utilities Service Company. The agreement provides that Northeast Utilities Service Company will, on request, provide services or procure services from third parties in support of our business. See "Summary of Certain Principal Agreements."

Land Sales

    Prior to our acquisition of assets in March 2000, our affiliate, Connecticut Light & Power, was required to offer certain parcels of land included within the facilities to state and municipal governments. In fulfillment of this obligation, Connecticut Light & Power agreed to sell several parcels of land to the Connecticut Department of Environmental Protection, the City of Danbury and the Town of New Milford. Connecticut Light & Power retained title to these parcels pending their sale. The land sale to the City of Danbury was completed in July 2001. The other sales are pending, subject to the receipt of FERC approval, with no scheduled closing dates. By the terms of our purchase and sale agreement with Connecticut Light & Power, if the land is not sold, it becomes part of the assets we purchased from Connecticut Light & Power in March 2000. We currently utilize the land pursuant to licenses granted to us by Connecticut Light & Power pursuant to the purchase and sale agreement for our facilities.

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SUMMARY OF CERTAIN PRINCIPAL AGREEMENTS

    The following is a summary of certain principal agreements related to our facilities and our business, and is not a full statement of the terms of these agreements. Accordingly, the following summaries are qualified by reference to each agreement and are subject to the terms of the full text of each agreement. Unless otherwise stated, any reference in this prospectus to any agreement shall mean such agreement and all schedules, exhibits and attachments thereto, as amended, supplemented or otherwise modified and in effect as of the date of this prospectus.

Power Purchase and Sales Agreement

    Scope.  We entered into a power purchase and sales agreement with our affiliate, Select Energy, for a term that began on March 14, 2000 and ends on December 31, 2005. We are obligated to sell, and Select Energy is obligated to buy, all of the products from our facilities at prices and at times established in the agreement. Select Energy is responsible for all the costs of pumping activities at the Northfield and Rocky River pumped storage facilities and for buying and delivering to us jet fuel to run the Tunnel internal combustion unit. We are responsible for arranging and paying for the costs of transmission of our products to certain delivery points whereupon Select Energy becomes responsible for the transmission. Select Energy has sole discretion to request commitment and dispatch of products from our facilities, subject to generally recognized good utility practices. In addition, Select Energy has the sole right and responsibility for the bidding and scheduling of the products they purchase from us with ISO New England. Select Energy is also entitled to all the NEPOOL-related benefits, and bears all NEPOOL-related obligations and liabilities, associated with the dispatch of products from our facilities. We are entitled to curtail, reduce or interrupt our delivery of products to Select Energy under certain circumstances. Select Energy is responsible for communicating with ISO New England regarding bidding and scheduling of each facility. We are responsible for communications with NEPOOL regarding the hourly actual operations of each of our facilities, and for qualifying each of our facilities with ISO New England as generation resources in New England. Under the agreement we must consult with Select Energy before we make any modifications or capital additions to any of our facilities. Power prices and other terms of the agreement may be amended in the case of mutually agreed upon capital additions. We are also obligated to consult with Select Energy before we withdraw or retire a facility from service.

    Northeast Utilities Guarantee  Northeast Utilities has guaranteed Select Energy's performance obligations under this agreement. The Northeast Utilities guarantee expires on December 31, 2005.

    Indemnification and limitation of liability.  Under the agreement, Select Energy assumed the risks of interruption, failure or deficiency in quality or quantity of service to the same extent as if it were operating our facilities, employing generally recognized utility practices. We agreed to indemnify and hold Select Energy harmless for damages and other claims asserted by third parties resulting from our failure to perform under the agreement, except to the extent that such damages and claims result from Select Energy's gross negligence or willful misconduct. Select Energy also agreed to indemnify and hold us harmless for damages and other claims asserted by third parties resulting from its failure to perform under the agreement, except to the extent that such damages and claims result from our gross negligence or willful misconduct. Indemnity rights survive termination of the agreement for one year. Remedies under the agreement are generally limited to direct actual damages.

    Term and Renewal.  The agreement expires on December 31, 2005, unless sooner terminated or renewed as described below.

    We have agreed to negotiate in good faith the appropriate terms and conditions for renewal of the agreement. If not renewed prior to December 31, 2004, the agreement will terminate. The agreement may be terminated prior to December 31, 2005 in the event that any regulatory agency with jurisdiction

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over the agreement makes substantial changes to the agreement and the parties are unable to agree in good faith on how to implement the changes. In addition, either we or Select Energy may suspend performance of, or terminate, the agreement upon the occurrence of certain "events of default" with respect to either party (and in the case of Select Energy, including Northeast Utilities), except that Select Energy cannot suspend performance or terminate the agreement if we continue to produce, sell and deliver our products to Select Energy. Generally, an event of default occurs when:

    Assignment.  Neither party may assign their rights and obligations under the agreement without the written consent of the other party except in limited circumstances. Without Select Energy's consent, we may (i) transfer, sell or assign the agreement and the accounts and revenues associated with it in connection with any financing, (ii) transfer or assign the agreement to an affiliate of ours in the same holding company system as us, or (iii) transfer or assign the agreement to any party that acquires all or substantially all of our assets.

    Regulatory Changes.  If FERC or another regulatory agency with jurisdiction over the agreement makes substantial changes or modifications to any of the terms contained in the agreement, then we and Select Energy are obligated to cooperate to amend the agreement so as to provide substantially the same benefits to us and Select Energy. If we and Select Energy, acting in good faith, cannot reach agreement within thirty days of such regulatory changes, then either we or Select Energy may terminate the agreement on three days notice.

    Destruction, Damage or Condemnation.  Under the agreement, if a substantial portion of a generating unit is destroyed, damaged or condemned, and we are therefore unable to supply power from the unit, then: (i) we may elect to repair, restore or reconstruct the unit to its former character and use, or to such character and use as we may then determine is appropriate, or (ii) we may elect not to repair, restore or reconstruct the unit, and subsequently may elect to retire the unit from service. Although the responsibility and authority for making any election rests with us, we must consult with Select Energy concerning the repair, restoration or reconstruction, provided that any such consultation will not delay work on the unit or reduce our discretion in making the election.

    If the destroyed, damaged or condemned unit cannot, using normal utility practice, be repaired, restored or reconstructed to supply power, then Select Energy may suspend payment for the unit after thirty consecutive days of non-operation. When the unit returns to service, Select Energy must resume payment for the power and capacity of the unit in the first month following the resumption of service. However, if Select Energy gives us sixty days notice during a period when the unit is out of service,

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then Select Energy may permanently suspend payment for the unit if the unit does not return to service within ninety-one days after the destruction, damage or condemnation.

    Operating Committee.  We and Select Energy agreed to establish an operating committee consisting of three representatives: one from us, one from Select Energy, and one from Select Energy's operating agent, if one is designated. The operating committee may only act with both our consent and Select Energy's. The operating committee is charged with coordinating the responsibilities of the parties under the agreement, including setting the parameters for the development of the annual incentive payment scheme described below, if an incentive payment is allowed by the SEC.

    Incentive Payment.  The agreement provides for an annual incentive payment that could be made either to Select Energy or to us for meeting performance goals established by the operating committee. We would neither receive the benefit nor bear the burden of any incentive payment, however. Under our management and operation agreement with Northeast Generation Services: (i) if we receive a payment from Select Energy under the power purchase and sale agreement, then we are obligated to pay it over to Northeast Generation Services, and (ii) if we are obligated to make a payment to Select Energy under the power purchase and sale agreement, then we would be reimbursed by Northeast Generation Services. The maximum amount payable to Select Energy in any year under this agreement would be $1.25 million, while the maximum amount payable to us in any year under this agreement would be $2.5 million.

    The incentive payment provisions of the agreement with Select Energy have not been implemented because the SEC has not approved the corresponding provisions of the management and operation agreement with Northeast Generation Services that would permit us to transfer the incentive payment from Select Energy to Northeast Generation Services.

    We believe that Northeast Generation Services intends to pursue with the SEC the acceptability of the incentive payments. If this is approved by the SEC, the incentive payment provisions of the agreements with Select Energy and Northeast Generation Services would be implemented.

Management and Operation Agreement

    Scope.  We entered into a management and operation agreement with our affiliate Northeast Generation Services for a term ending March 14, 2006. Under this agreement, Northeast Generation Services manages, operates, and maintains our facilities and provides administrative services for these facilities on our behalf. Facilities management services provided include: recruiting, hiring and training personnel, vendors and subcontractors; compliance with and maintenance of standard operating procedures; preparation and maintenance of operating records and reports; procurement of goods and services; development and implementation of safety, environmental and security practices; development and maintenance of the inventory management system; supervision of personnel, vendors and subcontractors; development of operating reports and budgets; coordination with Select Energy; administration and assurance of compliance with licenses, permits, leases and contracts; community relations; and technical and engineering support. Operations services provided include: operation of conventional hydroelectric, pumped storage and internal combustion plants; coordination of transmission; operation of intakes, spillways, gateways and outlet works; compliance with environmental and health and safety regulations; maintenance of the spare parts inventory; security for the facilities; and caring for the facilities and grounds. Maintenance services provided include: routine maintenance consisting of daily repairs and general upkeep of facilities; scheduled maintenance consisting of overhauls and various services scheduled at regular intervals; forced maintenance consisting of unanticipated repairs and maintenance needs; and facilities maintenance consisting of inspection, minor maintenance and repairs of buildings and structures. Northeast Generation Services does not bear any risk of ownership of the facilities.

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    Northeast Generation Services is responsible for complying with, and assisting us in complying with certain continuing obligations to Connecticut Light & Power and Western Massachusetts Electric under the purchase and sale agreements for the facilities. We have the right to request Northeast Generation Services to incur additional capital expenditures beyond the "Approved Capital Expenditures" under the agreement, as long as we pay for such capital expenditures. Northeast Generation Services is responsible for performing capacity audits of the facilities at our request at least annually and submitting the results to ISO New England in accordance with NEPOOL procedures. Northeast Generation Services is responsible for direct communications with ISO New England with respect to the hourly actual operations of the facilities. We (or our designee) are responsible for direct communications with ISO New England regarding bidding and scheduling of each of the facilities.

    Northeast Generation Services, either directly, or through an affiliate, is solely responsible for employing the personnel who perform the services and other Northeast Generation Services obligations under this agreement. Northeast Generation Services is responsible for payment of all salaries and benefits (whether contractual or statutory) associated with our personnel including but not limited to, expense reimbursements, health insurance, workers compensation and social security. Northeast Generation Services will indemnify and hold us harmless from and against all claims, demands, costs, expenses as incurred, liabilities and losses which may result from the failure of Northeast Generation Services to comply with its responsibilities in connection with its employees.

    Payment.  We pay Northeast Generation Services for the actual total costs of the services provided, including applicable overhead, indirect costs, and reasonable compensation for necessary capital as permitted by Rule 91 of the SEC under the Public Utility Holding Company Act and as determined in accordance with the Northeast Utilities system accounting and cost allocation procedures used in service agreements between Northeast Utilities affiliates. For the twelve-month period ended September 30, 2001, Northeast Generation Services charged us approximately $15.7 million for services rendered.

    Subcontracts.  Northeast Generation Services may not subcontract services under the agreement that amount to $1.5 million or more per calendar year for a single non-affiliate subcontractor or vendor, or $5 million in total for all non-affiliate subcontractors or vendors in a calendar year. Northeast Generation Services is solely responsible to us for the management and operations of the facilities.

    Indemnification and Limitation of Liability.  We agreed to indemnify, defend and hold harmless Northeast Generation Services from and against third party claims that arise out of the performance of its obligations under the management and operation agreement, except to the extent that such a claim may be attributable to its negligence, gross negligence or willful misconduct. Northeast Generation Services agreed to indemnify, defend, and hold us harmless from and against third party claims that arise out of the performance of our obligations under the management and operation agreement, except to the extent that such a claim may be attributable to our negligence, gross negligence or willful misconduct. Under the agreement, we will not be liable to Northeast Generation Services for any indirect, consequential, incidental, punitive or exemplary damages, lost profits or other business interruption damages, and Northeast Generation Services will not be liable to us for any indirect, consequential, incidental, punitive or exemplary damages, lost profits or other business interruption damages. We also agreed to limit any damages payable by Northeast Generation Services for all events that occur in a calendar year to the amounts we pay to Northeast Generation Services for that calendar year (plus any applicable insurance proceeds), unless the damages are caused by Northeast Generation Services' gross negligence or willful misconduct, in which case it will be responsible for the full amount of damages. Likewise, Northeast Generation Services agreed to limit any damages payable by us for all events that occur in a calendar year to the amounts we pay to Northeast Generation Services for that

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calendar year (plus any applicable insurance proceeds), unless the damages are caused by our gross negligence or willful misconduct, in which case we will be responsible for the full amount of damages.

    Term.  The agreement remains in effect for an initial period of six years through March 14, 2006, and thereafter continues on a year-to-year basis unless terminated by either us or Northeast Generation Services upon one year advance written notice. Upon our sale of a particular facility, the agreement terminates as to that facility. In addition, the agreement may be unilaterally terminated by either Northeast Generation Services or us if certain events occur, such as one of the parties failing to make payments due within a certain period of time. In the event a termination notice is given by either party, the parties have agreed to cooperate to ensure a smooth transition to a new manager and operator without adversely impacting the physical condition, operations, or costs of the facilities.

    Assignment.  Neither party may assign its rights and obligations under the agreement without the written consent of the other party except in limited circumstances. Without Northeast Generation Services' consent, we may assign our rights under this agreement to an affiliate or a lender in connection with financing or refinancing of the facilities. In our sole discretion, we may withhold consent for an assignment by Northeast Generation Services. Northeast Generation Services may not unreasonably withhold consent in the case of a proposed assignment by us.

Interconnection Agreements with Connecticut Light & Power and Western Massachusetts Electric

    Scope.  We have entered into interconnection agreements with our affiliates, Connecticut Light & Power and Western Massachusetts Electric, whereby they provide us with interconnection services for the facilities we acquired from them. These agreements also define the continuing responsibilities and obligations of the parties regarding use of each other's property, assets and facilities. Connecticut Light & Power and Western Massachusetts Electric are responsible for connecting our facilities to the transmission and distribution system. We are permitted to remain interconnected to the system as long as we operate the facilities in accordance with good utility practice (as defined in the agreements). The interconnection services include the provision by Connecticut Light & Power and Western Massachusetts Electric of generating station service if we do not provide it ourselves.

    Access, Easements, Conveyances, Licenses, and Restrictions.  The parties to the interconnection agreements agreed to grant each other access to their respective facilities, properties, equipment and records as needed to maintain them in a manner consistent with good utility practices. These access rights are intended to be permanent.

    Payment.  We are obligated to pay all costs related to our use of interconnection facilities through an interconnection facilities charge. The charge applicable to Connecticut Light & Power's and Western Massachusetts Electric's transmission facilities is the Northeast Utilities System Companies Open Access Transmission Service Tariff No. 9. The charges applicable to Connecticut Light & Power's and Western Massachusetts Electric's distribution facilities are based on their respective estimated costs of providing service based on the classification of their facilities used to provide such service.

    Payment upon Removal From Service.  If we permanently remove a facility from service on which we pay an interconnection facilities charge, we may, at our option, terminate our obligation to pay these charges for the facility by paying Connecticut Light & Power or Western Massachusetts Electric a lump sum payment based on the depreciated cost of the related interconnection facility.

    Indemnification and Limitation of Liability.  Costs for physical damage or destruction of control cables owned by Connecticut Light & Power or Western Massachusetts Electric from substations to our facilities are shared equally between us and either Connecticut Light & Power or Western Massachusetts Electric, up to $25,000 per incident. Costs in excess of $25,000 per incident are borne by the party at fault. If neither we nor Connecticut Light & Power or Western Massachusetts Electric are

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at fault, the costs will be shared pro-rata based on each party's use of such cables. Each party to these agreements is liable for any physical damage, destruction of equipment, facilities or property owned by it or any claims for personal injury or death relating to such equipment, facilities or property, regardless of whether the other party caused such damage, except to the extent the event is caused by the other party's negligence, or willful or wanton acts or omissions.

    Term.  The agreements commenced on March 14, 2000, the closing date of the sale of the assets to us, and remain in effect until the parties agree to terminate the relevant agreement. However, if any of the facilities are decommissioned, the relevant agreement will terminate as to such facility upon the date of decommissioning.

    Assignment.  No party may assign its rights and obligations under the agreements without the written consent of the other party except in limited circumstances, which consent will not be unreasonably withheld. Without Connecticut Light & Power's or Western Massachusetts Electric's consent, we may assign our rights under the agreements to a trustee or lending institution in connection with financing or refinancing of the facilities.

    Amendment.  We initially entered into the agreements on July 2, 1999 and they were subsequently amended on August 26, 1999.

Tax Allocation Agreement

    Scope.  We, and the other direct and indirect subsidiaries of Northeast Utilities, are parties to the Northeast Utilities System Amended and Restated Tax Allocation Agreement, dated as of January 1, 1990, and amended by a First Amendment dated as of October 26, 1998 and by a Second Amendment dated as of March 1, 2000. The Northeast Utilities' system has adopted this agreement under Rule 45(c) of the Public Utility Holding Company Act, and it has been filed with the SEC. The agreement provides for the equitable sharing of individual company federal and state tax credits, losses and other tax attributes. Under the agreement, parent company income or loss, consolidated tax, capital gains taxes, general business credits, net operating losses, alternative minimum taxes or credits and special benefits are apportioned or allocated. Subsidiaries with net positive allocations pay the parent, while subsidiaries with a net negative allocation receive from the parent their respective obligations or entitlements, as the case may be. No subsidiary may be allocated a greater payment obligation than it would pay on a separate return basis, and Northeast Utilities (as the parent company) must distribute, and cannot be paid for, its loss.

    Payments.  Under Northeast Utilities' internal operating procedures, tax settlements pursuant to the agreement are made quarterly based on estimates, and are trued up when the final consolidated tax returns are filed. Provision is made for adjustments following tax agency redeterminations, if necessary.

    Term.  The agreement became effective on January 1, 1990 and has no specific term.

    Amendments.  The First Amendment to the agreement specifically named several new subsidiaries that had joined the Northeast Utilities system since 1990, and also effected technical amendments to the provisions dealing with apportioning parent company loss, allocation of consolidated federal income tax, allocation of general business credits, allocation of net operating loss and allocation of alternative minimum tax or credit, and adding a provision on unitary taxation. The Second Amendment updated the list of companies that are parties to the agreement.

    Administration.  The agreement is administered by Northeast Utilities Service Company and has been filed with, and is subject to periodic audit by, the SEC.

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Support Services Agreement

    Scope.  We have entered into a support services agreement dated January 4, 1999, with our affiliate Northeast Utilities Service Company, a service company subsidiary of Northeast Utilities. The agreement provides that Northeast Utilities Service Company will, on an as-requested basis, provide or procure from third parties services in support of our business. These services may include: general system management, including executive, administrative, managerial, coordinating and advisory services; office administration and corporate secretarial services; financial planning, including general treasury, banking, cash management and financing matters; accounting services, including preparation of managerial reports, internal auditing services and compliance with regulatory requirements; tax planning and preparation of administrative tax reports and returns; risk management services and procurement of insurance; information technology and data processing services; bulk power supply planning and related matters; purchasing of materials, supplies and equipment; engineering research and standardization activities; marketing and sales activities; and other general and administrative services.

    Payment.  We are required to compensate Northeast Utilities Service Company for its costs in rendering services to us, including reasonable compensation for capital costs, as required under the regulations of the SEC and as calculated in accordance with the agreement. The total amount paid to Northeast Utilities Service Company and other service providers under the service agreement was approximately $1.2 million for the twelve month period ended September 30, 2001.

    Term.  The service agreement has a term of one year and has been renewed annually since 1999. Either we or Northeast Utilities Service Company can terminate the agreement, and it terminates automatically if it comes into conflict with any rule, regulation or order of the SEC.

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DESCRIPTION OF THE EXCHANGE BONDS

    The following is a description of certain provisions of the exchange bonds. This information is not a complete description of the exchange bonds and is subject to, and qualified in its entirety by, reference to the exchange bonds, the indenture and the other documents referred to herein. Unless otherwise specified, the following description applies to all of the exchange bonds.

General

    We will issue the exchange bonds under an indenture, dated as of October 18, 2001, between us and The Bank of New York, as trustee, as supplemented by the first supplemental indenture, dated as of October 18, 2001. We refer to the indenture and the first supplemental indenture collectively as the indenture. The following is a summary of the material provisions of the indenture. It does not include all of the provisions of the indenture. We urge you to read the indenture because it defines your rights. The terms of the exchange bonds include those stated in the indenture. The exchange bonds will be our senior secured obligations and will rank senior in right of payment to all of our existing and future indebtedness that is designated as subordinate or junior in right of payment to the exchange bonds. The exchange bonds will also be secured by a pledge of all real and tangible personal property owned by us from time to time (but subject to release under certain conditions), our rights under our power purchase and sale agreement with Select Energy through December 31, 2005, which we refer to in this section as the "Initial Select Power Sales Agreement," and the Northeast Utilities guarantee of this agreement as described under "—Security for Bonds," on page 81.

    Please note that certain capitalized terms used in this section are explained under "—Certain Definitions," beginning on page 98.

Principal, Maturity and Interest

    We issued the old bonds in two series, consisting of $120,000,000 in aggregate principal amount of Series A Senior Secured Bonds and $320,000,000 in aggregate principal amount of Series B Senior Secured Bonds. We issued the old bonds in denominations of $100,000 and integral multiples of $1000. We will issue the exchange bonds in two series, which will be identical in all material respects to the old bonds, except that the transfer restrictions, registration rights and related interest rate increase provisions applicable to the old bonds are not applicable to the exchange bonds. The exchange bonds will consist of the 4.998% Series A-1 Senior Secured Bonds, which will mature on October 15, 2005, and the 8.812% Series B-1 Senior Secured Bonds, which will mature on October 15, 2026. To the extent any old bonds are not exchanged for exchange bonds, those old bonds will remain outstanding under the indenture and will rank pari passu with the exchange bonds and any other securities issued under the indenture.

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    The first payment of the principal of the exchange bonds will be made on April 15, 2002, and thereafter principal will be repaid semi-annually in accordance with the following schedule:

Principal Payment Dates

  Principal Amount
Payable on
Series A-1 Senior
Secured Bonds

  %
  Principal Amount
Payable on
Series B-1 Senior
Secured Bonds

  %
 
April 15, 2002     12,000,000   10.0 %   0   0.0 %
October 15, 2002     12,000,000   10.0 %   0   0.0 %
April 15, 2003     13,500,000   11.3 %   0   0.0 %
October 15, 2003     13,500,000   11.3 %   0   0.0 %
April 15, 2004     15,750,000   13.1 %   0   0.0 %
October 15, 2004     15,750,000   13.1 %   0   0.0 %
April 15, 2005     18,750,000   15.6 %   0   0.0 %
October 15, 2005     18,750,000   15.6 %   0   0.0 %
April 15, 2006     0         0   0.0 %
October 15, 2006     0         0   0.0 %
April 15, 2007     0         1,750,000   0.5 %
October 15, 2007     0         1,750,000   0.5 %
April 15, 2008     0         2,625,000   0.8 %
October 15, 2008     0         2,625,000   0.8 %
April 15, 2009     0         3,250,000   1.0 %
October 15, 2009     0         3,250,000   1.0 %
April 15, 2010     0         4,000,000   1.3 %
October 15, 2010     0         4,000,000   1.3 %
April 15, 2011     0         4,875,000   1.5 %
October 15, 2011     0         4,875,000   1.5 %
April 15, 2012     0         5,375,000   1.7 %
October 15, 2012     0         5,375,000   1.7 %
April 15, 2013     0         2,500,000   0.8 %
October 15, 2013     0         2,500,000   0.8 %
April 15, 2014     0         3,125,000   1.0 %
October 15, 2014     0         3,125,000   1.0 %
April 15, 2015     0         2,250,000   0.7 %
October 15, 2015     0         2,250,000   0.7 %
April 15, 2016     0         3,000,000   0.9 %
October 15, 2016     0         3,000,000   0.9 %
April 15, 2017     0         7,500,000   2.3 %
October 15, 2017     0         7,500,000   2.3 %
April 15, 2018     0         8,000,000   2.5 %
October 15, 2018     0         8,000,000   2.5 %
April 15, 2019     0         9,500,000   3.0 %
October 15, 2019     0         9,500,000   3.0 %
April 15, 2020     0         10,500,000   3.3 %
October 15, 2020     0         10,500,000   3.3 %
April 15, 2021     0         12,000,000   3.8 %
October 15, 2021     0         12,000,000   3.8 %
April 15, 2022     0         13,000,000   4.1 %
October 15, 2022     0         13,000,000   4.1 %
April 15, 2023     0         14,250,000   4.5 %
October 15, 2023     0         14,250,000   4.5 %
April 15, 2024     0         16,000,000   5.0 %
October 15, 2024     0         16,000,000   5.0 %
April 15, 2025     0         17,500,000   5.5 %
October 15, 2025     0         17,500,000   5.5 %
April 15, 2026     0         19,000,000   5.9 %
October 15, 2026     0         19,000,000   5.9 %
   
 
 
 
 
TOTAL   $ 120,000,000   100 % $ 320,000,000   100 %
   
 
 
 
 

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    Interest on the exchange bonds will accrue at the rate of 4.998% per year, with respect to the Series A-1 bonds, and 8.812% per year, with respect to the Series B-1 bonds, and will be payable semi-annually in cash on each April 15 and October 15, commencing April 15, 2002, to the persons who are registered holders at the close of business on (i) the 15th day immediately preceding the applicable interest payment date with respect to interest not in default and (ii) with respect to defaulted interest, a date between the 10th and the 15th day preceding payment thereof. Interest on the exchange bonds will accrue from the most recent date to which interest has been paid on the old bonds or, if no interest has been paid, from and including October 18, 2001. No interest will be paid in connection with the exchange. Interest will be computed on the basis of a 360-day year comprised of twelve 30-day months.

    All payments of the principal or interest due on the exchange bonds on any payment date will be made (i) at the specified place of payment, (ii) by check, or (iii) in another manner that may be provided for in the indenture. However, the final installment of principal will be payable upon presentation and surrender of the bond at the place of payment. The redemption price of the exchange bonds will be payable to the holders upon surrender of the exchange bonds at the place of payment indicated on the notice of redemption.

Additional Bonds

    We may from time to time issue additional bonds under one or more supplements to the indenture. We refer to such bonds in this prospectus as additional bonds. Any such additional bonds may, subject to the limitations described under "—Certain Covenants—Indebtedness" on page 83, rank equally with (and have equal rights with respect to the collateral for) the exchange bonds offered by this prospectus and will have such other terms and conditions as are set forth in the supplemental indenture under which such additional bonds are issued. Unless otherwise indicated, references in this prospectus to the exchange bonds do not include any additional bonds. No offering of any additional bonds is being or will be deemed to be made by this prospectus. In addition, we do not know when or whether we will issue any additional bonds or the aggregate principal amount of any such additional bonds.

Nature of Recourse

    Recourse for payment or performance of any of our obligations in respect of the exchange bonds will be limited solely to us, the collateral for the exchange bonds and our debt service reserve to the extent we are required to provide one. Neither any of our affiliates nor any of our officers, directors and stockholders or the officers, directors and stockholders of any of our affiliates will be liable for the payment of the principal of, premium, if any, or interest on the exchange bonds, and holders of the exchange bonds will have no claim against or recourse to (whether by operation of law or otherwise) such entities or persons or their affiliates.

Debt Service Reserve

    We have agreed in the indenture to maintain, under certain circumstances, a special reserve account for the payment of debt service. On the date of issuance of the old bonds, we deposited into the debt service reserve account an amount equal to the applicable debt service reserve requirement (as defined on page 6 of this prospectus). If the amount in the debt service reserve account as of the end of any fiscal quarter thereafter is less than the debt service reserve requirement at such date, we will, within 60 days following the end of such fiscal quarter, deposit into or credit to the debt service reserve account the amount necessary to cause the amount in the debt service reserve account to equal the applicable debt service reserve requirement. However, we will not be required to maintain any reserve if the rating agencies confirm that they will maintain their ratings of the exchange bonds despite the absence of a debt service reserve. If at any time we are required to maintain a debt service reserve, the

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debt service reserve amounts can take the form of cash or securities deposited with the trustee, a letter of credit from an acceptable bank delivered to the trustee, a guarantee of Northeast Utilities or other acceptable guarantor delivered to the trustee, or any combination of the above.

    If on any scheduled payment date the paying agent notifies the trustee that we have not provided sufficient funds to pay in full the total amount of principal and interest then due with respect to the exchange bonds, the trustee will transfer cash from the debt service reserve to the paying agent in order to make up the difference. If the transferred amounts are still not enough to make in full the payments then due, the trustee will then draw on any letters of credit or guarantees then on deposit with the trustee.

    Thirty days prior to the expiration of a debt service letter of credit (if such debt service letter of credit has not been extended, renewed or replaced by another letter of credit from an acceptable bank, a guarantee from an acceptable guarantor, cash or Permitted Investments), the trustee will draw either the maximum amount available under such expiring debt service letter of credit or the amount that is necessary to make up the full debt service reserve requirement, whichever is less. The trustee will deposit the amounts received from the issuer of the expiring debt service letter of credit in the debt service reserve account.

    If the issuer of a debt service letter of credit ceases to be an acceptable bank in accordance with the requirements of the indenture, we will cause any outstanding debt service letters of credit from that issuer to be replaced. Such debt service letters of credit can be replaced with a letter of credit from an acceptable bank, a guarantee from an acceptable guarantor, cash or Permitted Investments. If the debt service letter of credit is not replaced within the required period of time, the trustee will draw either the maximum amount available under such ineligible debt service letter of credit or the amount that is necessary to make up the full debt service reserve requirement, whichever is less. The trustee will then deposit those amounts in the debt service reserve account.

    If the issuer of a debt service guarantee ceases to be an acceptable guarantor in accordance with the requirements of the indenture, we will cause any guarantees from that guarantor to be replaced. Such debt service guarantees can be replaced with a letter of credit from an acceptable bank, a guarantee from an acceptable guarantor, cash or Permitted Investments. If the debt service guarantee is not replaced within the required period of time, the trustee will draw either the maximum amount available under such ineligible debt service guarantee or the amount that is necessary to make up the full debt service reserve requirement, whichever is less. The trustee will then deposit those amounts in the debt service reserve account.

    If at any time the total amount of cash and Permitted Investments on deposit with the trustee plus the amounts available to be drawn under letters of credit or guarantees exceeds the debt service reserve requirement and no event of default has occurred and is continuing, we will be entitled, upon request, to either a transfer of cash or Permitted Investments or to a reduction of the amount available to be drawn under the letters of credit or the guarantees in an amount equal to such excess.

Ranking

    The exchange bonds, together with any old bonds that are not exchanged for exchange bonds, will constitute our senior secured obligations and will rank senior in right of payment to all of our existing and future indebtedness that is designated as subordinate or junior in right of payment to the exchange bonds.

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Security for Bonds

    To secure our payment and performance obligations under the indenture and the bonds, we have entered into the following:

    Under the mortgages and security agreement, we have granted to the trustee as collateral all our rights in all our existing real and tangible personal property, including the facilities, and our rights under the Initial Select Power Sales Agreement and the Northeast Utilities guarantee of the Initial Select Power Sales Agreement. The lien may extend to additional facilities that we acquire in the future depending on the circumstances.

    Subject to restrictions and other applicable provisions of the indenture, we have the right to sell or dispose of any part of the Collateral. The trustee will release such Collateral from the lien of the Collateral Documents upon receipt of, among other things, the following:

    The Collateral may also be released on an item by item basis if required in connection with a permitted purchase money financing or a permitted renewal, replacement or refinancing of a purchase money financing and in certain other circumstances as provided in the indenture.

Redemption and Repurchase

    The bonds will be subject to mandatory redemption in whole or in part in the event we receive casualty insurance proceeds or condemnation proceeds, as applicable, in respect of any loss or damage to or condemnation or other governmental taking of any facility or any part thereof and we have either:

    If we are required to redeem the bonds in whole or in part, we will redeem the bonds in an amount equal to all casualty insurance or condemnation proceeds received in excess of $10,000,000. Any such redemption will be on a pro rata basis at a redemption price equal to 100% of the principal amount of the bonds being redeemed plus interest accrued to but excluding the date of redemption.

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    We may redeem any series of the bonds in whole or in part at our option and at any time. If we elect to redeem any series of the bonds, we will redeem the bonds of that series on a pro rata basis at a redemption price equal to:

    The "make-whole premium" will be an amount equal to the excess, if any, of (i) the present value of all interest and principal payments scheduled to become due after the date of the optional redemption by us in respect of the bonds being redeemed (such present value to be determined on the basis of a discount rate equal to the sum of (a) a treasury rate and (b) 25 basis points in the case of the Series A-1 bonds and 50 basis points in the case of the Series B-1 bonds) over (ii) the outstanding principal amount of the bonds being redeemed. "Treasury rate" means the yield to maturity at the time of computation of U.S. Treasury securities with a final maturity (as compiled and published in the most recent Federal Reserve Statistical Release H.15(519) which has become publicly available in New York at least two business days prior to the redemption date (or, if such Statistical Release is no longer published, any publicly available source or similar market data)) most nearly equal to the remaining average life on the redemption date of the bonds being redeemed, provided, however, that if the period from the redemption date to the maturity date of the series of bonds being redeemed is less than one year, the weekly average yield on actively traded U.S. Treasury securities adjusted to a constant maturity of one year will be used.

    If less than all of the bonds of any series are to be redeemed at any time, the bonds of that series will be redeemed on a pro rata basis. We will mail notice of the redemption, first-class postage prepaid, to each holder of bonds to be redeemed at the holder's registered address. Notice to the holders will be given at least 30 but not more than 60 days before the redemption date, unless a shorter period is satisfactory to the trustee. If any bond is to be redeemed in part only, the notice of redemption that relates to that bond will state the portion of the principal amount of that bond to be redeemed. In that case, we will issue a new bond in principal amount equal to the unredeemed portion of the bond in the name of its holder after we cancel the original bond. Bonds or portions of bonds to be redeemed become due on the redemption date, and interest will cease to accrue on those bonds or portions of bonds on the redemption date.

Change of Control

    If a change of control occurs, each holder may require us to repurchase all or any part of such holder's outstanding bonds at a cash price equal to 101% of the then outstanding principal amount of such bonds, plus accrued and unpaid interest to but excluding the date of payment. We must send a notice to holders of the bonds within 30 days following a change of control and must repurchase within 30 to 60 days from the mailing of the notice any bonds validly tendered pursuant to the offer.

    A change of control means:

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    However, there will be no change of control if either:

Certain Covenants

    In the indenture, we will agree that, so long as the indenture is in effect and any bonds remain outstanding, we will comply with the following obligations:

    Payment of Principal of (and Premium, if any).  We will punctually pay or cause to be paid the principal of (and premium, if any) and interest on each of the bonds at the time and place and in the manner provided in the bonds and the indenture.

    Financial Statements and Other Information.  So long as the bonds are outstanding, we will furnish to the trustee:

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    Existence; Conduct of Business.  (a) So long as any bonds are outstanding, we will do or cause to be done all things necessary to preserve, renew and keep in full force and effect our existence as a corporation organized under the laws of the United States or a political subdivision thereof and all things reasonably necessary to preserve, renew and keep in full force and effect the rights, licenses, permits, privileges and franchises material to the conduct of our business as then conducted; provided that the foregoing will not prohibit any merger, consolidation, liquidation or dissolution permitted under the "Prohibition on Fundamental Changes" covenant.

    (b) At all times we will either (i) maintain in effect with a qualified operator an operation and maintenance agreement with respect to our facilities or (ii) directly employ persons with a demonstrated ability to operate and maintain such facilities in accordance with prudent industry practice.

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    Compliance with Laws and Contractual Obligations.  We will comply with all laws, rules, regulations and orders of any governmental authority (including environmental laws and ERISA matters) and all contractual obligations applicable to us or our property, except where the failure to do so, individually or in the aggregate, could not reasonably be expected to have a Material Adverse Effect.

    Maintenance of Properties; Insurance.  We will (a) keep and maintain all property material to the conduct of our business in good working order and condition, ordinary wear and tear excepted; provided, however, that nothing in this covenant will prevent us from disposing of any asset (subject to compliance with the "Prohibition on Sale of Assets" and "Prohibition on Fundamental Changes" covenants) or from discontinuing the operation or maintenance of any of such material properties if such discontinuance is, as determined by us in good faith, desirable in the conduct of our business and could not reasonably be expected to have a Material Adverse Effect on us; and (b) maintain, with financially sound and reputable insurance companies, insurance with respect to each facility in such amounts and against such risks as are customarily maintained by companies engaged in the same or similar businesses operating in the same or similar locations. We will maintain insurance for risks customarily insured against by other enterprises having SEC registered or Rule 144A indebtedness and owning and operating facilities of like size and type as that of our facilities in accordance with prudent industry practice.

    Payment of Taxes and Claims.  We will pay our obligations, including tax liabilities, before they become delinquent or in default unless they are then the subject of a good faith contest or except where nonpayment will not have a Material Adverse Effect.

    Books and Records; Inspection Rights.  We will keep proper books of record and account in which full, true and correct entries are made of all dealings and transactions in relation to our business and activities. We will permit the trustee or its representative, upon reasonable prior notice, to visit and inspect our properties, to examine and make extracts from our books and records, and to discuss our affairs, finances and condition with our officers and independent accountants, all at such reasonable times during normal business hours and as often as reasonably requested.

    Indebtedness.  We will not create, incur or assume any Indebtedness or secured hedging agreement other than (i) the bonds, (ii) unsecured Indebtedness incurred in the ordinary course of business, (iii) purchase money Indebtedness not exceeding the cost of the property involved, (iv) renewals, replacements or refinancings (but not increases in the principal amount) of any previously incurred Indebtedness at the time and (v) hedging agreements secured solely by cash or securities not included in the Collateral, unless at the time such additional Indebtedness is incurred or such secured hedging agreement is entered into, each of the rating agencies has confirmed its then current rating on the bonds.

    Liens.  We will not create, incur, assume or permit to exist any lien on any Collateral other than Permitted Liens.

    Prohibition on Sale of Assets.  We will not sell or otherwise dispose of any assets other than (a) sales and dispositions in the ordinary course of business; (b) any sales or dispositions of surplus, obsolete or worn-out equipment; (c) any sales or dispositions required for compliance with applicable law or necessary governmental approvals; (d) any sales or dispositions of assets permitted under the "Prohibition on Fundamental Changes" covenant; and (e) any other sale or other disposition; provided, in each case, that after giving effect to such event, no Event of Default has occurred and is continuing and such event will not result in a Material Adverse Effect. Any sale or other disposition of the Northfield facility or any material portion thereof that would not be permitted by the foregoing will not be conducted unless each of the rating agencies has confirmed its then current rating of the exchange bonds.

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    Modifications of Certain Documents.  Without the prior consent of the Majority Holders, we will not agree or consent to any termination, modification, supplement, replacement or waiver of any Transaction Document, unless such termination, modification, supplement, replacement or waiver could not, individually or collectively with all other such terminations, modifications, supplements, replacements and waivers, reasonably be expected to have a Material Adverse Effect. The foregoing provision will not be construed as restricting or preventing us in any way from (i) modifying the Initial Select Power Sales Agreement so long as such modifications are not adverse to the interests of the Holders, (ii) modifying the Initial Select Power Sales Agreement in order to comply with any future rules, regulations or orders of FERC or any other governmental authority or (iii) entering into a new or modified power sales agreement with Select Energy upon the expiration of the Initial Select Power Sales Agreement on December 31, 2005.

    Prohibition on Fundamental Changes.  (a) Mergers, Consolidations, Disposal of Assets, Etc. We will not merge into or consolidate with any other person, or permit any other person to merge into or consolidate with us, or sell, transfer, lease or otherwise dispose of (in one transaction or in a series of transactions) all or substantially all of our assets (in each case, whether now owned or hereafter acquired), or liquidate or dissolve, except that we may merge with, or transfer all or substantially all of our assets to, another person if: (i) the survivor is a U.S. corporation organized under the laws of the United States, any state thereof or the District of Columbia; (ii) simultaneous with such transaction the survivor, if not us, expressly assumes all of our obligations under the indenture, the bonds and the other Transaction Documents; and (iii) after giving effect to such transaction (x) no Default or Event of Default has occurred and is continuing and (y) no Material Adverse Effect has occurred.

    (b) Lines of Business. We will not engage to any material extent in any business other than the ownership and operation of electric transmission and non-nuclear electric generating facilities and the buying, selling, and marketing of electricity.

    Restricted Payments.  (a) We will not make, or agree to pay or make, directly or indirectly, any Restricted Payment, unless, at the time of and after giving effect to such Restricted Payment (i) no Default or Event of Default would occur or be continuing; (ii) with respect to the most recently completed fiscal quarter, the debt service reserve account has been funded to the extent required in accordance with the requirements of the indenture; (iii) (x) if the Contracted Generating Capacity is at least 75%, the Debt Service Coverage Ratio for the preceding four fiscal quarters (or, if shorter, for the period from the closing date of the issuance of the old bonds until the time of such Restricted Payment) and the Projected Debt Service Coverage Ratio for the next succeeding eight fiscal quarters is equal to or greater than 1.35 to 1.0 or (y) if the Contracted Generating Capacity is less than 75% the Debt Service Coverage Ratio for the preceding four fiscal quarters (or, if shorter, for the period from the closing date of the issuance of the old bonds until the time of such Restricted Payment) and the Projected Debt Service Coverage Ratio for the next succeeding eight fiscal quarters is equal to or greater than 1.70 to 1.0; and (iv) we certify that no Material Adverse Effect with respect to us will occur as a result of such Restricted Payment.

    (b) Unless not permitted by law, payment of the principal of (and premium, if any) and interest on each of the bonds will be made prior to any payment by us under our tax allocation agreement with Northeast Utilities or any similar agreement with respect to the allocation or sharing of taxes among the members of our consolidated group for tax purposes.

    Transactions with Affiliates.  We will not sell, lease or otherwise transfer any property or assets to, or purchase, lease or otherwise acquire any property or assets from, or otherwise engage in any other transactions with, any of our affiliates, except (a) so long as the Public Utility Holding Company Act is in effect, transactions in the ordinary course of business that are permitted under such act, (b) if such act ceases to be in effect, transactions in the ordinary course of business at prices and on terms and

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conditions not less favorable to us than could be obtained on an arm's-length basis from unrelated third parties, (c) any Restricted Payment permitted by the "Restricted Payments" covenant above, and (d) transactions that are contemplated by any Transaction Document or any extensions, renewals or replacements thereof that will not have a Material Adverse Effect.

    Notwithstanding the foregoing, the restrictions set forth in this covenant will not apply to (i) reasonable and customary directors' fees, indemnification and similar arrangements, consulting fees, employee salaries, bonuses or employment agreements, compensation or employee benefit arrangements and incentive arrangements with any officer, director or employee of ours or of any of our subsidiaries entered into in the ordinary course of business, (ii) loans and advances to officers, directors and employees of ours or of any of our subsidiaries for reasonable travel, entertainment, moving and other relocation expenses, in each case made in the ordinary course of business and (iii) transactions pursuant to agreements in effect on the date of the indenture.

    Investments.  We will not make or permit to remain outstanding any Investments except:

    For purposes of this covenant, the aggregate amount of an Investment at any time will be deemed to be equal to (A) the aggregate amount of cash, together with the aggregate fair market value of property, including any securities, loaned, advanced, contributed, transferred or otherwise invested that gives rise to such Investment minus (B) the aggregate amount of dividends, distributions or other

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payments received in cash in respect of such Investment. The amount of an Investment will not in any event be reduced by reason of any write-off of such Investment nor increased by any increase in the amount of earnings retained in the person in which such Investment is made that have not been dividended, distributed or otherwise paid out.

    We will provide to the holders of the exchange bonds such periodic and other reports that we are required to file pursuant to Sections 13 or 15(d) of the Exchange Act.

Events of Default and Remedies

    Each of the following will constitute an "Event of Default" under the indenture:

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    If an Event of Default described in paragraph (1) above occurs and is continuing with respect to bonds of any series, then, unless the principal of all the bonds of such series have already become due and payable, either the trustee or the holders of not less than 331/3% in aggregate principal amount of the bonds of such series then outstanding under the indenture, or, in the event of any Event of Default described in paragraphs (2), (3), (6), (8), (9), (10), (11), (12) or (13) above, the Majority Holders of bonds of such series then outstanding by notice in a writing to us (and to the trustee if given by holders), may declare the principal amount of all the bonds of such series then outstanding and all accrued interest thereon to be due and payable immediately, and upon any such declaration the same will become immediately due and payable, notwithstanding anything to the contrary contained in the indenture or in the bonds of such series. If an Event of Default described in paragraph (4), (5) or (7) above occurs and is continuing, then the principal amount of the bonds then outstanding and all accrued interest thereon will, without any notice to us or any other act on the part of the trustee or any holder of the bonds, become and be immediately due and payable, notwithstanding anything to the contrary contained in the indenture or in the bonds.

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    At any time after a declaration of acceleration under the indenture, but before a judgment or decree for payment of the money due has been obtained by the trustee, the Majority Holders of the bonds of such series may rescind and annul such declaration and its consequences if:

    No such rescission will affect any subsequent default or impair any right consequent to any subsequent default.

    Any money collected by the trustee with respect to a series of bonds pursuant to the "Events of Default and Remedies" provisions of the indenture will be allocated in the following order of priority:

    Holders of the bonds may not enforce their rights under the bonds or the indenture except as provided in the indenture. Subject to the provisions of the indenture relating to the duties of the trustee, the trustee is under no obligation to exercise any of its rights or powers under the indenture, and may refuse to perform any duty or exercise any such rights or powers unless it shall have been offered reasonable indemnity. No holder of any bond of any series has any right to institute any proceeding with respect to the indenture or the bonds or for the appointment of a receiver or trustee, or for any other remedy under the indenture, unless:

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it being understood and intended that no one or more holders of bonds of such series has any right to affect, disturb or prejudice the rights of any other holders of bonds of such series, or to obtain priority or preference over any other such holders or to enforce any right under the indenture, except in the manner provided in the indenture and for the equal and proportionate benefit of all the holders of all bonds of such series.

    The trustee will not be entitled to exercise remedies with respect to the Collateral unless the bonds of all series then outstanding have been accelerated in accordance with the provisions of the indenture.

    The Majority Holders of any series may, on behalf of the holders of all the bonds of such series, waive any past default under the indenture with respect to such series, except a continuing default in the payment of the principal of (or premium, if any) or interest on any bond of such series, or in respect of a covenant or provision that under the indenture cannot be modified or amended without the consent of each of the holders of the outstanding bonds of such series.

    Upon any such waiver, such default will cease to exist, and any Event of Default arising therefrom will be deemed to have been cured, for every purpose of the indenture; but no such waiver will extend to any subsequent or other default or impair any right consequent thereon.

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Legal Defeasance and Covenant Defeasance

    We may, at our option and at any time, elect to have all of our obligations discharged with respect to the bonds then outstanding, which we refer to as legal defeasance. Such legal defeasance means that we will be deemed to have paid and discharged the entire indebtedness represented by the bonds, except for:

    In addition, we may, at our option and at any time, elect to have our obligations released with respect to certain covenants (not including non-payment, bankruptcy, receivership, reorganization and insolvency events) that are described in the indenture. After such a termination, which we refer to as covenant defeasance, any failure to comply with those obligations would not constitute an Event of Default with respect to the bonds.

    In order to exercise either legal defeasance or covenant defeasance:

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Satisfaction and Discharge

    Upon our request, the indenture will be discharged and will cease to be of further effect (except as expressly provided for in the indenture), and the trustee, at our expense, will execute proper instruments acknowledging satisfaction and discharge of the indenture, when:

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Amendment, Supplement and Waiver

    We and the trustee may, with the consent of the Majority Holders of bonds of all series then outstanding and affected thereby, enter into one or more supplemental indentures for the purpose of amending the indenture. However, no such supplemental indenture may, without the unanimous consent of the holders directly affected by it,

    We and the trustee may, at any time and without the consent of the holders of the bonds, enter into one or more supplemental indentures for any of the following purposes:

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Concerning the Trustee

    The indenture provides that, except during the continuance of an Event of Default, the trustee will perform only such duties as are specifically set forth in the indenture, and no implied covenants or obligations will be read into the indenture against the trustee. During the existence of an Event of Default, the trustee will exercise such rights and powers vested in it by the indenture, and use the same degree of care and skill in their exercise, as a prudent person would exercise or use under the circumstances in the conduct of the person's own affairs. Under the indenture, the Majority Holders will have the right to direct the time, method and place of conducting any proceeding for any remedy available to the trustee, subject to some exceptions.

Governing Law

    The indenture and the exchange bonds will be governed by, and construed in accordance with, the laws of the State of New York but without regard to principles of conflicts of law to the extent the application of such principles would cause the application of the laws of any other jurisdiction.

Book-Entry, Delivery and Form

    DTC will act as the initial securities depositary for the exchange bonds. The exchange bonds will be issued only as fully registered securities registered in the name of DTC's nominee. One or more fully registered global bond certificates will be issued, representing in the aggregate the total principal amount of exchange bonds, and will be deposited with DTC. Except in the limited circumstances described under "—Certificated Bonds" below, beneficial interests in the global bonds will only be

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recorded by book-entry and owners of beneficial interests in the global bonds will not be entitled to receive physical delivery of certificates representing the exchange bonds.

    The exchange bonds will be issued in the form of one or more permanent global bonds. The global bonds will be deposited with The Bank of New York, as custodian for the benefit of DTC, and registered in the name of DTC or its nominee, who will be the global bonds holder. Except as described below, the global bonds may be transferred, in whole and not in part, only to DTC or another nominee of DTC. Investors may hold their beneficial interests in the global bonds directly through DTC if they are participating organizations or "participants" in the system or indirectly through organizations that are participants in the system. No service charge will be made for any registration of transfer or exchange of the exchange bonds, but the trustee may require payment of a sum sufficient to cover any tax or other governmental charge payable in connection with that transfer or exchange.

    All interests in the global bonds, including those held through Euroclear or Clearstream, may be subject to the procedures and requirements of DTC. Those interests held through Euroclear or Clearstream may also be subject to the procedures and requirements of such systems.

    The descriptions of the operations and procedures of DTC, Euroclear and Clearstream set forth below are provided solely as a matter of convenience. These operations and procedures are solely within the control of the respective settlement systems and are subject to change by them from time to time. We do not take any responsibility for these operations or procedures, and investors are urged to contact the relevant system or its participants directly to discuss these matters.

    DTC has advised us that it is (i) a limited-purpose trust company organized under the laws of the State of New York, (ii) a "banking organization" within the meaning of the New York Banking Law, (iii) a member of the Federal Reserve System, (iv) a "clearing corporation" within the meaning of the Uniform Commercial Code, as amended, and (v) a "clearing agency" registered pursuant to Section 17A of the Exchange Act. DTC was created to hold securities for its participants and facilitates the clearance and settlement of securities transactions between participants through electronic book-entry changes to the accounts of its participants, thereby eliminating the need for physical transfer and delivery of certificates. DTC's participants include securities brokers and dealers, banks and trust companies, clearing corporations and certain other organizations. Indirect access to DTC's system is also available to indirect participants such as banks, brokers, dealers and trust companies that clear through or maintain a custodial relationship with a participant, either directly or indirectly. Investors who are not participants may beneficially own securities held by or on behalf of DTC only through participants or indirect participants.

    We expect that upon the issuance of the global bonds representing the exchange bonds, DTC or its nominee will credit, on its internal system, the respective principal amounts of the individual beneficial interests represented by those global bonds to the accounts of persons who have accounts with DTC. Ownership of beneficial interests in a global bond will be limited to persons who have accounts with DTC ("participants") or persons who hold interests through participants. Ownership of beneficial interests in the global bonds will be shown on, and the transfer of that ownership will be effected only through, records maintained by DTC or its nominee (with respect to interests of participants) and the records of agent members (with respect to interests of persons other than participants). Beneficial owners will not receive written confirmation from DTC of their purchases, but beneficial owners are expected to receive written confirmations providing details of the transactions, as well as periodic statements of their holdings, from the direct or indirect participants through which the beneficial owners purchased exchange bonds.

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    The laws of some jurisdictions may require that certain purchasers of securities take physical delivery of such securities in definitive form. Accordingly, the ability to transfer interests in the bonds represented by a global bond to such persons may be limited. In addition, because DTC can act only on behalf of its participants, who in turn act on behalf of persons who hold interests through participants, the ability of a person having an interest in bonds represented by a global bond to pledge or transfer such interest to persons or entities that do not participate in DTC's system, or to otherwise take actions in respect of such interest, may be affected by the lack of a physical definitive security in respect of such interest.

    So long as DTC or its nominee is the registered owner of a global bond, DTC or such nominee, as the case may be, will be considered the sole owner or holder of the bonds represented by the global bond for all purposes under the indenture. Except as provided below, owners of beneficial interests in a global bond will not be entitled to have bonds represented by such global bond registered in their names, will not receive or be entitled to receive physical delivery of certificated bonds, and will not be considered the owners or holders thereof under the indenture for any purpose, including with respect to the giving of any direction, instruction or approval to the trustee thereunder. Accordingly, each holder of the bonds owning a beneficial interest in a global bond must rely on the procedures of DTC and, if such holder of the bonds is not a participant or an indirect participant, on the procedures of the participant through which such holder of the bonds owns its interest, to exercise any rights of a holder of the bonds under the indenture or such global bond. We understand that under existing industry practice, in the event that we request any action of holders of bonds, or a holder of the bonds that is an owner of a beneficial interest in a global bond desires to take any action that DTC, as the holder of such global bond, is entitled to take, DTC would authorize the participants to take such action and the participants would authorize holders of the bonds owning through such participants to take such action or would otherwise act upon the instruction of such holders of the bonds. Neither we nor the trustee will have any responsibility or liability for any aspect of the records relating to or payments made on account of bonds by DTC, or for maintaining, supervising or reviewing any records of DTC relating to such bonds.

    Payments with respect to the principal of, and premium, if any, and interest on, any bonds represented by a global bond registered in the name of DTC or its nominee on the applicable record date will be payable by the trustee to or at the direction of DTC or its nominee in its capacity as the registered holder of the global bond representing such bonds under the indenture. Under the terms of the indenture, we and the trustee may treat the persons in whose names the bonds, including the global bonds, are registered as the owners thereof for the purpose of receiving payment thereon and for any and all other purposes whatsoever. Accordingly, neither we nor the trustee has or will have any responsibility or liability for the payment of such amounts to owners of beneficial interests in a global bond (including principal, premium, if any, and interest). Payments by the participants and the indirect participants to the owners of beneficial interests in a global bond will be governed by standing instructions and customary industry practice and will be the responsibility of the participants or the indirect participants and DTC.

    Transfers between participants in DTC will be effected in accordance with DTC's procedures, and will be settled in same-day funds. Transfers between participants in Euroclear or Clearstream will be effected in the ordinary way in accordance with their respective rules and operating procedures.

    Subject to compliance with the transfer restrictions applicable to the bonds, cross-market transfers between the participants in DTC, on the one hand, and Euroclear or Clearstream participants, on the other hand, will be effected through DTC in accordance with DTC's rules on behalf of Euroclear or Clearstream, as the case may be, by its respective depositary; however, such cross-market transactions will require delivery of instructions to Euroclear or Clearstream, as the case may be, by the counterparty in such system in accordance with the rules and procedures and within the established deadlines (Brussels time) of such system. Euroclear or Clearstream, as the case may be, will, if the

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transaction meets its settlement requirements, deliver instructions to its respective depositary to take action to effect final settlement on its behalf by delivering or receiving interests in the relevant global bonds in DTC, and making or receiving payment in accordance with normal procedures for same-day funds settlement applicable to DTC. Euroclear participants and Clearstream participants may not deliver instructions directly to the depositories for Euroclear or Clearstream.

    Because of time zone differences, the securities account of a Euroclear or Clearstream participant purchasing an interest in a global bond from a participant in DTC will be credited, and any such crediting will be reported to the relevant Euroclear or Clearstream participant, during the securities settlement processing day (which must be a business day for Euroclear and Clearstream) immediately following the settlement date of DTC. Cash received in Euroclear or Clearstream as a result of sales of interest in a global security by or through a Euroclear or Clearstream participant to a participant in DTC will be received with value on the settlement date of DTC but will be available in the relevant Euroclear or Clearstream cash account only as of the business day for Euroclear or Clearstream following DTC's settlement date.

    Although DTC, Euroclear and Clearstream have agreed to the foregoing procedures to facilitate transfers of interests in the global bonds among participants in DTC, Euroclear and Clearstream, they are under no obligation to perform or to continue to perform such procedures, and such procedures may be discontinued at any time. Neither we nor the trustee will have any responsibility for the performance by DTC, Euroclear or Clearstream or their respective participants or indirect participants of their respective obligations under the rules and procedures governing their operations.

    If (i) we notify the trustee in writing that DTC is no longer willing or able to act as a depositary or DTC ceases to be registered as a clearing agency under the Exchange Act and a successor depositary is not appointed within 90 days of such notice or cessation, (ii) we, at our option, notify the trustee in writing that we elect to cause the issuance of bonds in definitive form under the indenture or (iii) upon the occurrence of certain other events as provided in the indenture, then, upon surrender by DTC of the global bonds, certificated bonds will be issued to each person that DTC identifies as the beneficial owner of the bonds represented by the global bonds. Upon any such issuance, the trustee is required to register such certificated bonds in the name of such person or persons (or the nominee of any thereof) and cause the same to be delivered thereto.

    Neither we nor the trustee will be liable for any delay by DTC or any participant or indirect participant in identifying the beneficial owners of the related bonds and each such person may conclusively rely on, and will be protected in relying on, instructions from DTC for all purposes (including with respect to the registration and delivery, and the respective principal amounts, of the bonds to be issued).

Certain Definitions

    Certain defined terms used above and in the indenture are explained below. You should refer to the indenture for a full disclosure of all those terms, as well as any other capitalized terms used in this description for which no definition is provided.

    "Collateral" means all property and interests in property now owned or hereafter acquired in or upon which a lien has been or is purported or intended to have been granted to the trustee pursuant to the Collateral Documents.

    "Collateral Documents" means the security agreement, the mortgages and the other instruments granting or purporting to grant a lien on Collateral securing the bonds.

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    "Contracted Generating Capacity" means, as of any date of determination, the percentage of the rated generating capacity of all of our facilities which is contracted for pursuant to a fixed or minimum price take-or-pay (if the plant is available) power sales agreement (including energy and capacity) with a remaining term of two years or longer from the date of determination with (i) Select Energy or any other affiliate of Northeast Utilities or (ii) a third party that complies with our Electricity Contracting Policies.

    "Debt Service Coverage Ratio" for any period means the ratio of, (x) all Revenues less Operating Expenses (other than nonrecurring expenses in connection with the issuance of Indebtedness), less all capital expenditures (unless funded with Indebtedness), to (y) the aggregate of principal, interest and fees payable on or in respect of the old bonds plus payments required to be made under any interest rate agreements, less payments to be received under any interest rate agreement for such period.

    "Default" means an event or condition that, with the giving of notice, lapse of time or failure to satisfy certain specified conditions, or any combination thereof, could become an Event of Default under the indenture if not cured or remedied.

    "Electricity Contracting Policies" means the customary credit and other policies followed by us in connection with our power sales agreements, which may be the credit and other policies followed by a third party we have appointed such third party as our agent for marketing and entering into power sales agreements.

    "ERISA" means the Employee Retirement Income Security Act of 1974, as amended and in effect from time to time.

    "Financing Documents" means the indenture, any series supplemental indenture, the bonds, the Collateral Documents and the registration rights agreement.

    "Fitch" means Fitch, Inc. or any successor thereto.

    "Indebtedness" of any person means, without duplication, (a) all obligations of such person for borrowed money or with respect to deposits or advances of any kind, (b) all obligations of such person evidenced by bonds, debentures, notes or similar instruments, (c) all obligations of such person under conditional sale or other title retention agreements relating to property acquired by such person, (d) all obligations of such person upon which interest charges are customarily paid, (e) all obligations of such person in respect of the deferred purchase price of property or services (excluding trade and other accounts payable incurred in the ordinary course of business so long as such trade accounts payable are payable and paid within 90 days of the date the respective goods are delivered or the respective services rendered or invoiced), (f) all Indebtedness of others secured by (or for which the holder of such Indebtedness has an existing right, contingent or otherwise, to be secured by) any lien on property owned or acquired by such person, whether or not the Indebtedness secured thereby has been assumed, (g) all Indebtedness of any other person guaranteed by such person or for which such person will otherwise (including payments pursuant to any keep-well, make-well or similar arrangement) become directly or indirectly liable, (h) all capital lease obligations of such person, (i) all obligations, contingent or otherwise, of such person as an account party or issuer in respect of letters of credit or the like and (j) all obligations, contingent or otherwise, of such person in respect of bankers' acceptances. The Indebtedness of any person includes the Indebtedness of any other entity (including any partnership in which such person is a general partner) to the extent such person is liable therefor as a result of such person's ownership interest in or other relationship with such entity, except to the extent the terms of such Indebtedness provide that such person is not liable therefor.

    "Initial Select Power Sales Agreement" means the power purchase and sales agreement dated December 27, 1999 between us and Select Energy.

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    "Investment" means, for any person: (i) the acquisition (whether for cash, property of such person, services or securities or otherwise) of capital stock, bonds, notes, debentures or other ownership interests or other securities of any other person or any agreement to make any such acquisition (including, without limitation, any "short sale" or any sale of any securities at a time when such securities are not owned by the person entering into such short sale), (ii) the making of any deposit with, or advance, loan or other extension of credit to, any other person (including the purchase of property from another person subject to an understanding or agreement, contingent or otherwise, to resell such property to such person, but excluding any such advance, loan or extension of credit arising in connection with the sale of inventory or supplies by such person in the ordinary course of business), (iii) the entering into of any guarantee of, or any other contingent obligation with respect to, Indebtedness or other liability of any other person and (without duplication) any amount committed to be advanced, lent or extended to such person or (iv) the entering into of any hedging agreement.

    "Investment Grade Rating" means a long-term senior debt rating of Baa3 (or the equivalent) or higher in the case of Moody's, BBB-(or the equivalent) or higher in the case of S&P or BBB- (or the equivalent) or higher in the case of Fitch.

    "Junior Lien" means any lien that is junior in priority to the lien created pursuant to the Collateral Documents; provided that (i) the junior lien is subject and subordinate to the liens in favor of the trustee pursuant to the Collateral Documents, (ii) so long as any of the bonds are outstanding, the holder of the junior lien expressly agrees not to exercise remedies against the Collateral without the consent of the trustee, (iii) the holder of the junior lien agrees to remit any proceeds from the exercise of remedies to the trustee for application to the payment of the bonds until the bonds have been paid in full and (iv) we have delivered an opinion or opinions of counsel to the trustee as to compliance with the requirements of this definition.

    "Majority Holders" means the holders of more than 50% in aggregate principal amount of (i) the bonds then outstanding or (ii) the outstanding bonds of the applicable series, as the case may be.

    "Material Adverse Effect" means a material adverse effect on (a) our business, assets, operations, prospects or condition, financial or otherwise, (b) our ability to perform any of our obligations under any Transaction Document to which we are a party, which obligations are material to us or (c) the material rights available to the holders or the trustee, as representative of the holders.

    "Moody's" means Moody's Investors Service, Inc. or any successor thereto.

    "Operating Expenses" means for any period, the sum, computed without duplication, of all costs and expenses, including taxes, incurred by us during such period (or, in the case of any future period, projected to be paid or payable during such period) in connection with the operation, maintenance and administration of the facilities.

    "Permitted Investments" means investments in securities or other instruments that are: (i) direct obligations of the United States, or any agency thereof; (ii) obligations fully guaranteed by the United States or any agency thereof; (iii) certificates of deposit issued by commercial banks under the laws of the United States or any political subdivision thereof or under the laws of Canada, Japan or any country that is a member of the European Economic Union having a combined capital and surplus of at least $500,000,000 and having long-term unsecured, unguaranteed debt securities rated "A" or better by S&P and "A2" or better by Moody's (but at the time of investment not more than $25,000,000 may be invested in such certificates of deposit from any one bank); (iv) repurchase obligations for underlying securities of the types described in clauses (i) and (ii) above, entered into with any commercial bank meeting the qualifications specified in clause (iii) above or any other financial institution having long-term unsecured, unguaranteed debt securities rated "A" or better by S&P and "A2" or better by Moody's in connection with which such underlying securities are held in trust or by a third-party custodian; (v) open market commercial paper of any corporation incorporated or doing

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business under the laws of the United States or of any political subdivision thereof having a rating of at least "A-1" from S&P and "P-1" from Moody's (but at the time of investment not more than $25,000,000 may be invested in such commercial paper from any one company); (vi) investments in money market funds having a rating assigned by each of the rating agencies equal to the highest rating assigned thereby to money market funds or money market mutual funds sponsored by any securities broker dealer of recognized national standing (or an affiliate thereof), having an investment policy that requires substantially all the invested assets of such fund to be invested in investments described in any one or more of the foregoing clauses and having a rating of "A" or better by S&P and "A2" or better by Moody's (including money market funds or money market mutual funds for which the trustee in its individual capacity or any of its affiliates is investment manager or adviser); or (vii) a deposit of any bank (including the trustee), trust company or financial institution authorized to engage in the banking business having a combined capital and surplus of at least US$500,000,000, whose long-term, unsecured, unguaranteed debt is rated "A" or higher by S&P and "A2" of higher by Moody's.

    "Permitted Liens" means:

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    "Projected Debt Service Coverage Ratio" means, at any time of determination thereof, a projection of the Debt Service Coverage Ratio over the period specified, prepared by us in good faith based upon assumptions consistent in all material respects with historical operating results, if any, and our good faith projections of future Revenues and Operating Expenses in light of the then existing or reasonably expected regulatory and market environments in the markets in which the facilities are or will be operated and upon the assumption that no early redemption or prepayment of the bonds of any series will be made prior to the stated maturity of such series of bonds. Whenever the indenture provides for the determination of a Projected Debt Service Coverage Ratio, the Projected Debt Service Coverage Ratio will be set forth in an officer's certificate filed with the trustee stating that, based upon reasonable investigation and review, the Projected Debt Service Coverage Ratio is based on the criteria set forth in the preceding sentence.

    "Restricted Payments" means (i) shareholder distributions by or distributions in respect of any equity interest in us (in cash, securities, property or obligations) on, or (ii) any payments or distributions on account of, payments of interest on or the setting apart of money for a sinking or other analogous fund for, or the purchase, redemption, retirement or other acquisition of, (a) Subordinated Indebtedness or (b) any portion of any shareholder interest or equity interest in us or of any warrants, options or other rights to acquire any such shareholder interest or equity interest (or to make any payments to any person, such as "phantom stock" payments, where the amount thereof is calculated with reference to our fair market or equity value).

    "Revenues" means, for any period, the sum of all of our revenues in respect of our operations under any contract or agreement or otherwise including amounts received pursuant to hedging agreements (other than interest rate agreements).

    "S&P" means Standard & Poor's Ratings Services or any successor thereto.

    "Select Power Sales Agreement" means the Initial Select Power Sales Agreement and any amendment, extension or renewal thereof.

    "Senior Debt" means our Indebtedness under the bonds or any other Indebtedness (whether secured or unsecured) that ranks pari passuwith the bonds.

    "Subordinated Indebtedness" means any of our Indebtedness that is fully subordinated in all rights and remedies to Senior Debt on terms substantially similar to the subordination provisions set forth in the indenture.

    "Transaction Documents" means the Financing Documents, the Initial Select Power Sales Agreement and the Northeast Utilities guarantee of the Initial Select Power Sales Agreement.

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FEDERAL INCOME TAX CONSIDERATIONS

General

    The acceptance of the exchange offer by bondholders and the related exchange of their old bonds for exchange bonds will not be a taxable event for U.S. federal income tax purposes. The exchange bonds will be treated as a continuation of the old bonds. Bondholders will have the same tax basis and holding period in the exchange bonds as they had in the old bonds immediately before the exchange.

    The following is a summary of the material federal income tax considerations to bondholders of acquiring, holding and disposing of exchange bonds This discussion is based on current provisions of the Internal Revenue Code of 1986, as amended, currently applicable Treasury regulations, and judicial and administrative rulings and decisions. Legislative, judicial or administrative changes could alter or modify the statements and conclusions in this discussion. Any legislative, judicial or administrative changes or new interpretations may be retroactive and could affect tax consequences to bondholders.

    This discussion applies to bondholders who acquire the exchange bonds at original issue in exchange for their old bonds, which were acquired at their original issue, and who hold the exchange bonds as capital assets. This discussion does not address all of the tax consequences relevant to a particular bondholder in light of that bondholder's circumstances, and some bondholders may be subject to special tax rules and limitations not discussed below (e.g., life insurance companies, tax-exempt organizations, financial institutions, dealers in securities, S corporations, taxpayers subject to the alternative minimum tax provisions of the Internal Revenue Code, broker-dealers, and persons who hold the bonds as part of a hedge, straddle, "synthetic security", or other integrated investment, risk reduction or constructive sale transaction). This discussion also does not address the tax consequences to nonresident aliens, foreign corporations, foreign partnerships or foreign trusts that are subject to U.S. federal income tax on a net basis on income with respect to an exchange bond because that income is effectively connected with the conduct of a U.S. trade or business. Those holders generally are taxed in a manner similar to U.S. Bondholders (as defined below); however, special rules not applicable to U.S. Bondholders may apply. In addition, except as described below, this discussion does not address any tax consequences under state, local or foreign tax laws or the consequences under any tax treaties. Consequently, you are urged to consult your tax adviser to determine the federal, state, local and foreign income and any other tax consequences of the purchase, ownership and disposition of the exchange bonds.

    We use the term "U.S. Bondholders" to mean a "U.S. Person" who is the beneficial owner of an exchange bond. A "U.S. Person" is:

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    In addition, as provided in Treasury regulations, some trusts in existence on August 20, 1996, and treated as U.S. Persons prior to that date, may elect to continue to be treated for federal income tax purposes as U.S. Persons.

    This discussion assumes that each exchange bond is issued in registered form.

Treatment of the Exchange Bonds

    Based on the assumptions and subject to the qualifications stated herein, the material federal income tax considerations to bondholders are generally as follows:

Taxation of U.S. Bondholders

    Payments of Interest.  Stated interest on the exchange bonds will be taxable as ordinary interest income when received or accrued by U.S. Bondholders under their method of accounting. Generally, interest on the exchange bonds will constitute "investment income" for purposes of Internal Revenue Code limitations on the deductibility of investment interest expense.

    Original Issue Discount.  This discussion assumes that any original issue discount on the exchange bonds (i.e., any excess of the stated redemption price at maturity of the bond over its issue price) is less than a statutory minimum amount (equal to 0.25 percent of its stated redemption price at maturity multiplied by the exchange bond's weighted average maturity) as provided in the Treasury's original issue discount regulations. Accordingly, unless a special election is made to treat all interest on an exchange bond as original issue discount, any original issue discount generally will be taken into income by a U.S. Bondholder as gain from the retirement of a bond (as described below under "—Sale or Other Taxable Disposition of Bonds") ratably as principal payments are made on the exchange bonds.

    Market Discount and Premium.  If a U.S. Bondholder purchases (including a purchase at original issuance for a price less than the issue price) an exchange bond for an amount that is less than the principal balance of the exchange bond, the difference will be treated as "market discount" unless it is less than a statutory minimum amount. Market discount will generally be treated as accruing ratably on the exchange bond during the period from the date of acquisition to the maturity date of the exchange bond, unless the U.S. Bondholder makes an election to accrue the market discount on a constant yield to maturity basis. The U.S. Bondholder will be required to treat any principal payment on, or any gain realized on the sale, exchange, retirement or other disposition of the exchange bonds as ordinary income to the extent of the lesser of:

    In addition, a U.S. Bondholder may be required to defer the deduction of all or a portion of the interest paid or accrued on any indebtedness incurred or maintained to purchase or carry an exchange bond with market discount, until the maturity of the exchange bond or its earlier disposition in a taxable transaction.

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    In the alternative, a U.S. Bondholder may elect to include market discount in income currently as it accrues on either a ratable or quarterly compounding basis, in which case the rules described above will not apply. The election to include market discount in income as it accrues will apply to all market discount instruments acquired by the U.S. Bondholder on or after the first day of the taxable year to which the election applies and may not be revoked without the consent of the Internal Revenue Service. Generally, currently included market discount is treated as ordinary interest for United States federal income tax purposes.

    A purchaser who acquires an exchange bond at a premium (i.e., at a purchase price greater than the principal balance) may elect to offset the premium against interest income on the exchange bond on a constant yield to maturity basis. Any amortized premium will reduce the adjusted basis of the exchange bond. If the exchange bond is redeemed before maturity for a price less than the adjusted basis of the exchange bond, a U.S. Bondholder will be allowed an ordinary loss deduction for the unamortized premium. An election to amortize bond premium applies to all exchange bonds acquired by a U.S. Bondholder on or after the first day of the taxable year to which the election applies and can be revoked only with the consent of the Internal Revenue Service.

Sale or Other Taxable Disposition of Exchange Bonds

    If there is a sale, exchange, redemption, retirement or other taxable disposition of an exchange bond, a U.S. Bondholder generally will recognize gain or loss equal to the difference between (a) the amount of cash and the fair market value of any other property received (other than amounts attributable to, and taxable as, accrued stated interest) and (b) the U.S. Bondholder's adjusted tax basis in the exchange bond. The adjusted tax basis in the exchange bond generally will equal its cost, increased by any original issue discount or market discount included in income with respect to the bond prior to its disposition and reduced by any payments reflecting principal or original issue discount previously received with respect to the exchange bond and any amortized premium. Although the market discount rules may apply, gain or loss generally will be capital gain or loss if the exchange bond was held as a capital asset.

Non-U.S. Bondholders

    In general, a non-U.S. Bondholder will not be subject to U.S. federal income or withholding tax on interest (including original issue discount) on an exchange bond unless:

    In order for interest payments to qualify for the exemption from U.S. taxation described above, the last person or entity in the United States in the chain of interest payments to the non-U.S. Bondholder (the "Withholding Agent") must have received (in the year in which a payment of interest or principal occurs or in either of the two preceding years) a statement that complies with Internal Revenue Service informational requirements and:

105


    The statement may be made on a Form W-8BEN, and the non-U.S. Bondholder must inform the Withholding Agent of any change in the information on the statement within 30 days of the change. If an exchange bond is held through a securities clearing organization or other financial institution, the organization or institution may provide a signed statement to the Withholding Agent certifying under penalties of perjury that the Form W-8BEN has been received by it from the bondholder or from another qualifying financial institution. However, in that case, the signed statement must be accompanied by a copy of the Form W-8BEN provided by the non-U.S. Bondholder to the organization or institution holding the bond on behalf of the non-U.S. Bondholder. The Treasury regulations also provide an informational reporting option under which an authorized agent of a U.S. Withholding Agent is permitted to act on behalf of the U.S. Withholding Agent, provided certain requirements are met.

    In addition, the Treasury regulations permit the shifting of primary responsibility for withholding to "qualified intermediaries" (as defined below) acting on behalf of beneficial owners. Under this option, the Withholding Agent is allowed to rely on a Form W-8IMY furnished by a "qualified intermediary" on behalf of one or more holders (or other intermediaries) without having to obtain the W-8BEN from the beneficial owner. "Qualified intermediaries" include: (i) foreign financial institutions or foreign clearing organizations (other than a U.S. branch or U.S. office of such institution or organization) or (ii) foreign branches or offices of U.S. financial institutions or foreign branches of offices of U.S. clearing organizations, which, as to both (i) and (ii), have entered into withholding agreements with the I.R.S. In addition to certain other requirements, qualified intermediaries must obtain withholding certificates, such as Form W-8BEN, from each holder. We urge non-U.S. bondholders to consult a tax advisor about the specific methods to satisfy Internal Revenue Service informational reporting requirements.

    Generally, any gain or income realized by a non-U.S. Bondholder from the sale, exchange, redemption, retirement or other disposition of an exchange bond (other than gain attributable to accrued interest or original issue discount, which is addressed above) will not incur U.S. federal income tax liability, provided, in the case of a bondholder who is an individual, that the bondholder is not present in the United States for 183 or more days during the taxable year in which a disposition of an exchange bond occurs. Exceptions may be applicable, and non-U.S. Bondholders should consult a tax adviser regarding the tax consequences of a disposition of an exchange bond.

Information Reporting and Backup Withholding

    Some bondholders may be subject to backup withholding at rates as high as 30.5% on interest (including original issue discount) and proceeds received from the disposition of an exchange bond. Generally, backup withholding will apply if the bondholder fails to provide identifying information (such as the payee's taxpayer identification number) in the manner required, or if the payee has failed to report properly the receipt of reportable interest or dividend payments and the Internal Revenue Service has notified us that backup withholding is required. Some bondholders (including, among others, corporations and some tax-exempt organizations) generally are not subject to backup withholding.

    Backup withholding and information reporting generally will not apply to an exchange bond that is beneficially owned by a non-U.S. Bondholder if the certification of non-U.S. status is provided to the Withholding Agent as described above in "—Non-U.S. Bondholders," as long as we do not have actual knowledge that the bondholder is a U.S. Person. The Withholding Agent may be required to report annually to the Internal Revenue Service and to each non-U.S. Bondholder the amount of interest paid to, and the tax withheld, if any, for each non-U.S. Bondholder.

    If payments of principal and interest are made to the beneficial owner of an exchange bond by or through the foreign office of a custodian, nominee or other agent of that beneficial owner, or if the

106


proceeds of the sale of exchange bonds are made to the beneficial owner of an exchange bond through a foreign office of a "broker" (as defined in the pertinent Treasury regulations), the proceeds will not be subject to backup withholding (absent actual knowledge that the payee is a U.S. Person). Information reporting (but not backup withholding) will apply, however, to a payment by a foreign office of a custodian, nominee, agent or broker that:

    Payment through the U.S. office of a custodian, nominee, agent or broker is subject to both backup withholding at rates as high as 30.5% and information reporting, unless the bondholder certifies that it is a non-U.S. Person under penalties of perjury or otherwise establishes an exemption.

    Any amounts withheld under the backup withholding rules from a payment to a bondholder would be allowed as a refund or a credit against that bondholder's U.S. federal income tax, provided that the required information is furnished to the Internal Revenue Service.


ERISA CONSIDERATIONS

    Any person who intends to use plan assets (as discussed below) to purchase exchange bonds should consult with its counsel with respect to the potential consequences of such investment under the fiduciary responsibility provisions of the Employee Retirement Income Security Act of 1974 ("ERISA"), and the prohibited transaction provisions of ERISA and the Internal Revenue Code.

    ERISA and the Internal Revenue Code impose certain requirements on employee benefit plans, certain other retirement plans and arrangements, including individual retirement accounts and annuities, and any entity holding the assets of any such plan, account, or annuity (such as a bank collective investment fund or an insurance company general or separate account) (collectively, "plans"). Generally, a person who exercises discretionary authority or control with respect to the assets of a plan will be considered a fiduciary of the plan under ERISA. Before investing in the exchange bonds, a plan fiduciary should determine whether such investment is permitted under the plan document and the instruments governing the plan and is appropriate for the plan in view of its overall investment policy and the composition and diversification of its portfolio, taking into account the limited liquidity of the bonds.

    In addition, ERISA and the Internal Revenue Code describe a wide range of prohibited transactions involving the assets of a plan and persons who have certain specified relationships to the plan ("parties in interest" within the meaning of ERISA or "disqualified persons" within the meaning of the Internal Revenue Code). Thus, a plan fiduciary considering an investment in the bonds should also consider whether such investment might constitute or give rise to a prohibited transaction under ERISA or the Internal Revenue Code for which no exemption (as discussed below) is available.

    The initial purchasers of the old bonds, Northeast Generation, Northeast Utilities or the holders of the debt that was repaid using the net proceeds from the old bonds may be a party in interest or a disqualified person with respect to the plan acquiring, holding or disposing of the exchange bonds, in which case such acquisition, holding or disposition would give rise to a direct or indirect prohibited transaction.

107


    A prohibited transaction could be treated as exempt under ERISA and the Internal Revenue Code if the exchange bonds were acquired, held or disposed of pursuant to and in accordance with one or more statutory or administrative exemptions. Among the administrative exemptions (each, a "Prohibited Transaction Class Exemption" or "PTCE") are PTCE 75-1 (an exemption for certain transactions involving employee benefit plans and registered broker dealers (such as the initial purchasers), reporting dealers and banks), PTCE 84-14 (an exemption for certain transactions determined by an independent qualified professional asset manager), PTCE 90-1 (an exemption for certain transactions involving insurance company pooled separate accounts), PTCE 91-38 (an exemption for certain transactions involving bank collective investment funds), PTCE 95-60 (an exemption for certain transactions involving insurance company general accounts), and PTCE 96-23 (an exemption for certain transactions determined by a qualified in-house asset manager). Certain of the exemptions, however, do not afford relief from the prohibitions on self-dealing contained in Section 406(b) of ERISA and Section 4975(c)(1)(E)-(F) of the Internal Revenue Code. In addition, there can be no assurance that any of these administrative exemptions will be available with respect to any particular transaction involving the exchange bonds. Thus, a plan fiduciary considering an investment in the bonds should consider whether the acquisition, the continued holding, or the disposition of the exchange bonds might constitute or give rise to a nonexempt prohibited transaction.

    Governmental plans and certain church plans, while not subject to the fiduciary responsibility provisions or the prohibited transactions provisions of ERISA or the Internal Revenue Code, may nevertheless be subject to state or other federal laws that are substantially similar to the foregoing provisions of ERISA and the Internal Revenue Code. Fiduciaries of any such plans should consult with their counsel before purchasing bonds.

    Each person who acquires or accepts exchange bonds will be deemed by such acquisition or acceptance to have represented and warranted that either: (i) no plan assets have been used to acquire such bonds; or (ii) the acquisition and holding of such bonds are exempt from the prohibited transaction restrictions of ERISA and the Internal Revenue Code pursuant to one or more Prohibited Transaction Class Exemptions or do not constitute a prohibited transaction under ERISA and the Internal Revenue Code.

    A plan fiduciary (and each fiduciary for a governmental or church plan subject to rules similar to those imposed on plans under ERISA) considering the purchase of certificates should consult its tax and/or legal advisors regarding the availability, if any, of exemptive relief from any potential prohibited transaction and other fiduciary issues and their potential consequences.


PLAN OF DISTRIBUTION

    Each broker-dealer that receives exchange bonds for its own account in the exchange offer must acknowledge that it will deliver a prospectus in connection with any resale of the exchange bonds. This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of exchange bonds received in exchange for old bonds that were acquired as a result of market-making activities or other trading activities. We have agreed to make this prospectus, as amended or supplemented, available to any broker-dealer for use in connection with any resale for such period of time as is necessary to comply with applicable law in connection with any resale of the exchange bonds. In addition, until [  ], 2002, all dealers effecting transactions in the exchange bonds may be required to deliver a prospectus.

    Neither we nor any of our affiliates will receive any proceeds from any sale of exchange bonds by broker-dealers. Exchange bonds received by broker-dealers for their own account in the exchange offer may be sold from time to time in one or more transactions in the over-the-counter market, in negotiated transactions, through the writing of options on the bonds or a combination of these methods of resale, at market prices prevailing at the time of resale, at prices related to such prevailing market

108


prices or at negotiated prices. Any resale may be made directly to purchasers or to or through brokers or dealers who may receive compensation in the form of commissions or concessions from any broker-dealer or the purchasers of any of the exchange bonds. Any broker-dealer that resells exchange bonds that were received by it for its own account in the exchange offer and any broker or dealer that participates in a distribution of exchange bonds

    (1) may be deemed to be an "underwriter" within the meaning of the Securities Act and

    (2) must acknowledge that it must comply with the registration and prospectus delivery requirements of the Securities Act in connection with the resale transaction, including the delivery of a prospectus that contains information with respect to any selling holder required by the Securities Act in connection with any resale transaction.

    Profit on any resale of the exchange bonds and any commission or concessions received by any such broker-dealer may be deemed to be underwriting compensation under the Securities Act. The letter of transmittal states that, by acknowledging that it will deliver and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an "underwriter" within the meaning of the Securities Act.

    We have agreed that for so long as may be legally required in connection with any resale of exchange bonds by a broker-dealer who acquired such exchange bonds in exchange for bonds acquired for its own account (but not directly from us) as a result of market-making or other trading activities, we will promptly send additional copies of this prospectus and any amendment or supplement to this prospective to any broker-dealer that requests such documents in the letter of transmittal.

    Any broker-dealer that acquired any of its old bonds directly from us:

    We have also agreed to bear all expenses in connection with the performance of our obligations in connection with the exchange offer and will reimburse Salomon Smith Barney Inc., Barclays Capital Inc. and TD Securities (USA) Inc. as the initial purchasers of the old bonds for the reasonable fees and disbursements of one counsel acting in connection with this registration statement. Except to the extent provided above, each holder will be responsible for its own expenses, fees, underwriting discounts and commissions and transfer taxes, if any, relating to the sale or disposition of such holder's bonds. We have agreed to indemnify holders of the bonds (including any broker-dealers) against certain liabilities, including liabilities under the Securities Act. We note, however, that in the opinion of the SEC, indemnification against liabilities arising under the federal securities laws is against public policy and may be unenforceable.


RATINGS

    The old bonds are rated, and the exchange bonds are expected to be rated, "Baa2" by Moody's and "BBB-" by Fitch and S&P.

    A security rating is not a recommendation to buy, sell or hold securities and may be subject to revision or withdrawal at any time by the assigning rating agency. No person is obligated to maintain any rating on the bonds, and accordingly, there can be no assurance that the ratings assigned to the bonds upon the initial issuance will not be revised or withdrawn by a rating agency at any time thereafter. If a rating of the bonds is revised or withdrawn, the liquidity of the bonds may be adversely

109


affected. In general, ratings address credit risk and do not represent any assessment of any particular rate of principal payments on the bonds other than the payment in full of the bonds at maturity.


INDEPENDENT CONSULTANTS

    The independent technical consultant's report included as Appendix A to this prospectus has been prepared by S&W Consultants, Inc., and is included herein in reliance upon its conclusions and experience in the review of the operation of generating facilities and the preparation of financial projections with respect to revenues from the operation of generating facilities. The independent power market consultant's report included as Appendix B to this prospectus has been prepared by PA Consulting Services, Inc. (formerly PHB Hagler Bailly, Inc.), and is included herein in reliance on its conclusions and its experience in energy market policy, price forecasting and economic analysis. Prospective investors should read the appended reports in their entireties and note the assumptions and qualifications stated in them.


LEGAL MATTERS

    Certain legal matters will be passed upon for us by Day, Berry & Howard LLP, Stamford, Connecticut.


INDEPENDENT PUBLIC ACCOUNTANTS

    The balance sheets of Northeast Generation as of December 31, 2000 and 1999 and the related statements of income, stockholder's equity and cash flows for the years then ended included in this prospectus have been audited by Arthur Andersen LLP, independent public accountants, as indicated in their reports with respect thereto and are included herein in reliance upon the authority of said firm as experts in accounting and auditing in giving said reports.


WHERE YOU CAN FIND MORE INFORMATION

    We have filed with the SEC a registration statement on Form S-4 under the Securities Act with respect to the exchange bonds offered in this prospectus. This prospectus, which forms part of the registration statement, does not contain all of the information that is included in the registration statement. You will find additional information about our company and the exchange bonds in the registration statement. Any statements made in this prospectus concerning the provisions of legal documents are not necessarily complete and you should read the documents that are filed as exhibits to the registration statement for a more complete understanding of the document or matter.

    After the registration statement becomes effective, we will be subject to the informational requirements of the Exchange Act, and will file periodic reports and other information with the SEC. Additionally, Northeast Utilities files annual, quarterly and periodic reports, proxy statements and other information with the SEC. You may read and copy the registration statement and any of the other documents we file, or that Northeast Utilities files, with the SEC at the public reference facilities maintained by the SEC at Room 1024, Judiciary Plaza, 450 Fifth Street, N.W., Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for more information on the public reference room. Reports and other filings are also available to the public on the SEC's web site at http://www.sec.gov. Northeast Utilities' SEC filings are also available at the offices of the New York Stock Exchange. For further information on obtaining copies of Northeast Utilities' public filings at the New York Stock Exchange, you should call (212) 656-5060.

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INDEX TO FINANCIAL STATEMENTS

 
  Page
Northeast Generation Company    
 
Report of Independent Public Accountants

 

F-2
 
Balance Sheets as of September 30, 2001 (unaudited) and December 31, 2000 and 1999

 

F-3
 
Statements of Income for the nine months ended September 30, 2001 and 2000 (unaudited) and for the years ended December 31, 2000 and 1999

 

F-4
 
Statements of Stockholder's Equity for the nine months ended September 30, 2001 (unaudited) and for the years ended December 31, 2000 and 1999

 

F-5
 
Statements of Cash Flows for the nine months ended September 30, 2001 and 2000 (unaudited) and for the years ended December 31, 2000 and 1999

 

F-6
 
Notes to Financial Statements

 

F-7

F–1



REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To Northeast Generation Company:

    We have audited the accompanying balance sheets of Northeast Generation Company (a Connecticut corporation and wholly owned indirect subsidiary of Northeast Utilities) as of December 31, 2000 and 1999, and the related statements of income, stockholder's equity and cash flows for the years then ended. These financial statements are the responsibility of Northeast Generation Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

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

    In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Northeast Generation Company as of December 31, 2000 and 1999, and the results of its operations and its cash flows for the years then ended in conformity with accounting principles generally accepted in the United States.

Hartford, Connecticut
April 9, 2001

F–2


NORTHEAST GENERATION COMPANY

BALANCE SHEETS

 
  September 30,
2001
(Unaudited)

  December 31,
2000

  December 31,
1999

 
 
  (Thousands of Dollars)

 
ASSETS  
Plant, at Original Cost:                    
  Electric   $ 265,309   $ 264,855   $  
    Less: Accumulated provision for depreciation     149,559     147,216      
   
 
 
 
      115,750     117,639      
Construction work in progress     15,951     8,094     5  
   
 
 
 
    Total net plant     131,701     125,733     5  
   
 
 
 
Current Assets:                    
  Cash     26,477     37,177      
  Accounts receivable from affiliated companies     10,225     11,419      
  Materials and supplies, at average cost     1,909     1,935      
  Prepayments and other     1,001     1,626     621  
   
 
 
 
      39,612     52,157     621  
   
 
 
 
Deferred Charges:                    
  Accumulated deferred income taxes     262,463     278,320     1,530  
  Unamortized debt expense     5,491     4,828     6,384  
  Other     24     23      
   
 
 
 
      267,978     283,171     7,914  
   
 
 
 
    Total Assets   $ 439,291   $ 461,061   $ 8,540  
   
 
 
 
CAPITALIZATION AND LIABILITIES  
Capitalization:                    
  Common stock, $1 par value—100 shares authorized and outstanding in 2001, 2000 and 1999   $   $   $  
  Capital surplus, paid in     22,647     24,375     6,510  
  Retained earnings/(deficit)     56,961     23,260     (3,156 )
   
 
 
 
    Total capitalization     79,608     47,635     3,354  
   
 
 
 
Current Liabilities:                    
  Notes payable to banks     346,500     402,377      
  Accounts payable     9,248     1,771     1,745  
  Accounts payable to affiliated companies     464     732     1,538  
  Accrued taxes     1,993     5,840     1,899  
  Accrued interest     271     1,893      
  Other     1,207     813     4  
   
 
 
 
      359,683     413,426     5,186  
   
 
 
 
Commitments and Contingencies (Note 7)                    
    Total Capitalization and Liabilities   $ 439,291   $ 461,061   $ 8,540  
   
 
 
 

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

F–3


NORTHEAST GENERATION COMPANY

STATEMENTS OF INCOME

 
  Nine Months
Ended
September 30,
2001
(Unaudited)

  Nine Months
Ended
September 30,
2000
(Unaudited)

  Years Ended December 31,
 
 
  2000
  1999
 
 
  (Thousands of Dollars)

 
Operating Revenues   $ 99,400   $ 75,589   $ 108,473   $  
   
 
 
 
 
Operating Expenses:                          
  Operation and maintenance     16,594     16,271     20,947     5,232  
  Depreciation     2,282     1,654     2,417      
  Federal and state income taxes     22,749     12,144     17,522     (2,151 )
  Taxes other than income taxes     5,573     2,692     5,690     74  
   
 
 
 
 
    Total operating expenses     47,198     32,761     46,576     3,155  
   
 
 
 
 
Operating Income/(Loss)     52,202     42,828     61,897     (3,155 )
Other Income, Net     1,036     614     1,061      
Interest Expense     19,537     25,131     36,542     1  
   
 
 
 
 
Net Income/(Loss)   $ 33,701   $ 18,311   $ 26,416   $ (3,156 )
   
 
 
 
 

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

F–4


NORTHEAST GENERATION COMPANY

STATEMENT OF STOCKHOLDER'S EQUITY

 
  Common
Stock

  Capital
Surplus,
Paid In

  Retained
(Deficit)/
Earnings

  Total
 
 
  (Thousands of Dollars)

 
Balance as of January 1, 1999   $   $   $   $  
Net loss for 1999             (3,156 )   (3,156 )
Capital contribution         6,500         6,500  
Other         10         10  
   
 
 
 
 

Balance as of December 31, 1999

 

 


 

 

6,510

 

 

(3,156

)

 

3,354

 
Net income for 2000             26,416     26,416  
Capital contribution         463,000         463,000  
Excess paid over carrying value of assets transferred (Note 5)         (445,135 )       (445,135 )
   
 
 
 
 

Balance as of December 31, 2000

 

 


 

 

24,375

 

 

23,260

 

 

47,635

 
Net income for the nine months ended September 30, 2001 (unaudited)             33,701     33,701  
Other         (1,728 )       (1,728 )
   
 
 
 
 

Balance as of September 30, 2001 (unaudited)

 

$


 

$

22,647

 

$

56,961

 

$

79,608

 
   
 
 
 
 

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

F–5


NORTHEAST GENERATION COMPANY

STATEMENTS OF CASH FLOWS

 
  Nine Months
Ended
September 30,
2001
(Unaudited)

  Nine Months
Ended
September 30,
2000
(Unaudited)

   
   
 
 
  Years Ended December 31,
 
 
  2000
  1999
 
 
  (Thousands of Dollars)

 
Operating Activities:                          
Net income/(loss)   $ 33,701   $ 18,311   $ 26,416   $ (3,156 )
Adjustments to reconcile to net cash flows provided by/(used in) operating activities:                          
    Depreciation     2,282     1,654     2,417      
    Deferred income taxes     17,024     12,797     19,245     (1,530 )
    Net other (uses)/sources of cash     (3,499 )   1,791     1,533     (6,379 )
Changes in working capital:                          
  Accounts receivable from affiliated companies     1,194     (12,806 )   (11,419 )    
  Materials and supplies     26     7     (62 )    
  Accounts payable     7,209     188     (780 )   3,283  
  Accrued taxes     (3,847 )   1,787     5,840     1,899  
  Prepayments and other     625     (3,639 )   (1,626 )    
  Other working capital (excludes cash)     (1,228 )   (844 )   1,424     (617 )
   
 
 
 
 
Net cash flows provided by/(used in) operating activities     53,487     19,246     42,988     (6,500 )
   
 
 
 
 
Investing Activities:                          
  Investments in plant     (8,310 )   (554 )   (1,394 )    
  Net cash payment for transfer of assets         (869,794 )   (869,794 )    
   
 
 
 
 
Net cash flows used in investing activities     (8,310 )   (870,348 )   (871,188 )    
   
 
 
 
 
Financing Activities:                          
  Issuance of short-term debt         865,500     865,500      
  Repayments of short-term debt     (55,877 )   (449,162 )   (463,123 )    
  Capital contributions         463,000     463,000     6,500  
   
 
 
 
 
Net cash flows (used in)/provided by financing activities     (55,877 )   879,338     865,377     6,500  
   
 
 
 
 
Net (decrease)/increase in cash     (10,700 )   28,236     37,177      
Cash—beginning of period     37,177              
   
 
 
 
 
Cash—end of period   $ 26,477   $ 28,236   $ 37,177   $  
   
 
 
 
 
Supplemental Cash Flow Information:                          
Cash paid/(refunded) during the year for:                          
  Interest, net of amounts capitalized   $ 21,515   $ 20,216   $ 29,286   $ (1,899 )
   
 
 
 
 
  Income taxes   $ 8,887   $ (4,236 ) $ (7,725 ) $  
   
 
 
 
 

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

F–6


NORTHEAST GENERATION COMPANY

NOTES TO FINANCIAL STATEMENTS

Nine Months Ended September 30, 2001 (Unaudited)
Years Ended December 31, 2000 And 1999

1.  Summary of Significant Accounting Policies

    Northeast Generation Company (Northeast Generation) is a subsidiary of NU Enterprises, Inc., a wholly owned subsidiary of Northeast Utilities. Northeast Generation is a competitive business affiliate formed to acquire and manage generation facilities.

    In March 2000, Northeast Generation acquired 1,289 megawatts (MW) of primarily hydroelectric generation assets in Connecticut and Massachusetts from The Connecticut Light & Power Company (Connecticut Light & Power) and Western Massachusetts Electric Company (Western Massachusetts Electric), two affiliated companies. The acquisition was completed through an independent auction overseen by the Connecticut Department of Public Utility Control and an independent investment banking firm.

    Northeast Generation has entered into cost sharing arrangements with Northeast Utilities Service Company (NUSCO) for certain services. Northeast Generation has no employees.

    Northeast Generation has contracted with Select Energy, Inc. (Select Energy), its competitive energy marketing affiliate, to purchase and market all of the energy and capacity of Northeast Generation's 1,289 MW of generation assets. Additionally, Northeast Generation has contracted with Northeast Generation Services Company (NGS), another affiliate, to operate, manage and maintain its generation assets.

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

    The accompanying financial statements contain, in the opinion of management, all adjustments necessary to present fairly Northeast Generation's financial position as of September 30, 2001, and the results of operations and cash flows for the nine-month periods ended September 30, 2001 and 2000. All adjustments are of a normal, recurring nature.

    Plant is being depreciated over the estimated useful lives of the assets, primarily 40 years, using the straight-line method.

    Northeast Generation's revenues are recognized when the energy is delivered regardless of the period in which billed. Revenues are primarily in the form of pre-determined fixed monthly payments based on the capacity of the generation assets. Other revenues are in the form of monthly payments at pre-determined rates per unit of actual energy output.

F–7


    The tax effect of temporary differences (differences between the periods in which transactions affect income in the financial statements and the periods in which they affect the determination of taxable income) is accounted for in accordance with Statement of Financial Accounting Standards (SFAS) No. 109, "Accounting for Income Taxes." The tax effect of temporary differences that give rise to the accumulated deferred tax asset is as follows:

 
  At December 31,
 
  2000
  1999

Basis step-up depreciation

 

$

280,450

 

$


Property taxes

 

 

(1,234

)

 


Other depreciation

 

 

(911

)

 


Deferred financing costs

 

 

15

 

 

1,530

 

 



 



Deferred income taxes, net

 

$

278,320

 

$

1,530

 

 



 


2.  Generation Asset Transfer

    In March 2000, Northeast Generation acquired 1,289 MW of primarily hydroelectric generation assets in Connecticut and Massachusetts from Connecticut Light & Power and Western Massachusetts Electric for approximately $865.5 million, subject to certain adjustments. These assets include seven hydroelectric facilities along the Housatonic River system, the three facilities comprising the Eastern Connecticut System, including one turbine, the Northfield Mountain pumped storage station, and the Cabot and Turners Falls No. 1 hydroelectric stations located in Massachusetts. In connection with this transfer, Northeast Generation generally assumed all environmental liabilities associated with the acquired assets. In December 1999, Northeast Generation contracted with Select Energy to purchase and market all of the energy and capacity of Northeast Generation's 1,289 MW of generation assets for approximately a six-year period beginning in March, 2000. For further information see Note 5, "Business Segment Reporting."

3.  Credit Agreement

    To finance the aforementioned transfer, on March 9, 2000, Northeast Generation entered into a short-term credit agreement with a total commitment amount of $865.5 million with several financial institutions, collateralized by the generation assets transferred. Under the short-term credit agreement, $435.5 million of the commitment matured on March 14, 2000, and was repaid. This credit agreement, with an original maturity date of December 29, 2000, was extended from its original maturity date to November 27, 2001. Northeast Generation expects to replace the short-term credit agreement with up to $440 million of long-term financing in the second half of 2001. At December 31, 2000, there were $402.4 million in borrowings under the credit agreement.

F–8


    Under the aforementioned credit agreement, Northeast Generation may borrow at variable rates plus a 2 percent margin. This rate equaled 8.64 percent at December 31, 2000.

    The credit agreement provides that Northeast Generation must comply with certain financial and nonfinancial covenants as are customarily included in such agreements, including, but not limited to, a common equity ratio. Northeast Generation currently is in compliance and expects to remain in compliance with these covenants.

4.  Related Party Transactions

    NUSCO:  Northeast Generation has entered into cost sharing arrangements with NUSCO for certain services including centralized accounting, administrative, engineering, financial, information resources, legal, operational, planning, purchasing, and other services billed at cost. Under these arrangements, Northeast Generation incurred expenses of $1.1 million and $1.2 million for the years ended December 31, 2000 and 1999, respectively.

    Select Energy:  In order to support and complement its growing wholesale and retail business, Select Energy contracted in December 1999 with Northeast Generation, to purchase and market all of the energy and capacity of Northeast Generation's 1,289 MW of generation assets for a period ending December 31, 2005.

    NGS:  Northeast Generation has contracted with NGS to operate, manage and maintain Northeast Generation's generation assets for a six-year period beginning in March 2000. Northeast Generation's expenses under this contract amounted to $13.8 million for the year ended December 31, 2000.

    Connecticut Light & Power and Western Massachusetts Electric:  In connection with the acquisition of the generation assets, Northeast Generation entered into an interconnection agreement with Connecticut Light & Power and Western Massachusetts Electric to provide interconnection services, where applicable, and to define the continuing responsibilities and obligations of each party with respect to the other's property, assets and facilities. Under this agreement, Northeast Generation is obligated to pay all costs related to the use of these interconnection facilities through an interconnection facilities charge.

    Other:  Northeast Generation has receivables from and payables to affiliated companies at December 31, 2000 and 1999 as follows (thousands of dollars):

 
  2000
  1999

Accounts receivable from affiliated companies

 

$

11,419

 

$


 

 



 



Accounts payable to affiliated companies

 

$

732

 

$

1,538

 

 



 


F–9


5.  Business Segment Reporting

    The following business segment balance sheets and statements of income have been presented to comply with SFAS No. 131, "Disclosures about Segments of an Enterprise and Related Information." The business segment balance sheets and statements of income are utilized by management to make decisions about Northeast Generation's operating matters and allocating resources. Northeast Generation operates in one business segment, the sale of electricity and capacity.

    In accordance with accounting principles generally accepted in the United States, since Northeast Generation, Connecticut Light & Power and Western Massachusetts Electric are all wholly owned by Northeast Utilities, the assets have been recorded in the accompanying financial statements at Connecticut Light & Power's and Western Massachusetts Electric's book value just prior to the transfer. However, management, in evaluating operating results, believes reflecting the assets at Northeast Generation's purchase price is more meaningful. The following business segment information represents Northeast Generation's balance sheets at September 30, 2001 and December 31, 2000, and statements of income for the nine-month period ended September 30, 2001 and year ended December 31, 2000, respectively, as if the assets had been valued at Northeast Generation's purchase price rather than Connecticut Light & Power's and Western Massachusetts Electric's book value (thousands of dollars):

F–10


NORTHEAST GENERATION COMPANY

NOTES TO FINANCIAL STATEMENTS (Continued)

Nine Months Ended September 30, 2001 (Unaudited)
Years Ended December 31, 2000 And 1999

5.  Business Segment Reporting (Continued)


SEGMENT INFORMATION
BALANCE SHEETS
AT SEPTEMBER 30, 2001 (UNAUDITED) AND DECEMBER 31, 2000

 
  September 30,
2001

  December 31,
2000

ASSETS

Electric plant   $ 1,006,479   $ 1,006,025
  Less: Accumulated provision for depreciation     178,267     161,958
   
 
      828,212     844,067
Construction work in progress     15,951     8,094
   
 
  Total Net Plant     844,163     852,161
   
 

Current Assets:

 

 

 

 

 

 
  Cash     26,477     37,177
  Accounts receivable from affiliated companies     10,225     11,419
  Materials and supplies, at average cost     1,909     1,935
  Prepayments and other     1,001     1,626
   
 
    Total Current Assets     39,612     52,157
   
 

Deferred Charges:

 

 

 

 

 

 
  Accumulated deferred income taxes     10,117     3,748
  Unamortized debt expense     5,491     4,828
  Other     24     23
   
 
    Total Deferred Charges     15,632     8,599
   
 
Total Assets   $ 899,407   $ 912,917
   
 
CAPITALIZATION AND LIABILITIES

Capitalization:            
  Common stock   $   $
  Capital surplus, paid in     467,782     469,510
  Retained earnings     71,942     29,981
   
 
    Total Capitalization     539,724     499,491
   
 

Current Liabilities:

 

 

 

 

 

 
  Notes payable to banks     346,500     402,377
  Accounts payable     9,248     1,771
  Accounts payable to affiliated companies     464     732
  Accrued taxes     1,993     5,840
  Accrued interest     271     1,893
  Other     1,207     813
    Total Current Liabilities     359,683     413,426
   
 
Total Capitalization and Liabilities   $ 899,407   $ 912,917
   
 

F–11


NORTHEAST GENERATION COMPANY

NOTES TO FINANCIAL STATEMENTS (Continued)

Nine Months Ended September 30, 2001 (Unaudited)
Years Ended December 31, 2000 And 1999

5.  Business Segment Reporting (Continued)


SEGMENT INFORMATION

STATEMENTS OF INCOME

 
  Nine Months Ended
September 30, 2001

  Year Ended
December 31, 2000

 
  (Unaudited)

   
Operating Revenues   $ 99,400   $ 108,473
   
 
Operating Expenses:            
  Operation and maintenance     16,594     20,947
  Depreciation     16,247     17,159
  Federal and state income taxes     17,122     11,644
  Taxes other than income taxes     5,573     5,690
   
 
    Total operating expenses     55,536     55,440
   
 
Operating Income     43,864     53,033
   
 
Other Income, Net     1,036     1,061
Interest Expense     19,537     36,542
   
 
Net Income   $ 25,363   $ 17,552
   
 

6. Income Tax Provision/(Benefit)

    The components of the federal and state income tax provision/(benefit) are as follows (thousands of dollars):

 
  For the Years
Ended December 31,

 
 
  2000
  1999
 
Current income taxes:              
  Federal   $ (1,361 ) $ (491 )
  State     (362 )   (130 )
   
 
 
    Total current     (1,723 )   (621 )
   
 
 
Deferred income taxes, net:              
  Federal     15,586     (1,209 )
  State     3,659     (321 )
   
 
 
    Total deferred     19,245     (1,530 )
   
 
 
Total income tax provision/(benefit)   $ 17,522   $ (2,151 )
   
 
 

F–12


    Deferred income taxes are comprised of the tax effects of temporary differences as follows (thousands of dollars):

 
  For the Years
Ended December 31,

 
 
  2000
  1999
 
Depreciation   $ 16,496   $  
Deferred financing costs     1,515     (1,530 )
Property taxes     1,234      
   
 
 
Deferred income taxes, net   $ 19,245   $ (1,530 )
   
 
 

    A reconciliation between the income tax provision/(benefit) and the expected income tax provision/(benefit) at the statutory rate is as follows (thousands of dollars):

 
  For the Years
Ended December 31,

 
 
  2000
  1999
 
Expected federal income tax provision/(benefit)   $ 15,378   $ (1,858 )
Tax effect of differences:              
  State income taxes, net of federal benefit     2,144     (293 )
   
 
 
Total income tax provision/(benefit)   $ 17,522   $ (2,151 )
   
 
 

    Northeast Generation, as a wholly owned subsidiary of Northeast Utilities, is included in Northeast Utilities' consolidated tax return.

7. Commitments and Contingencies

    Northeast Generation is involved in various lawsuits incidental to its business. Northeast Generation believes that these proceedings, in the aggregate, will not have a material adverse effect on Northeast Generation's financial position, results of operations or cash flows.

    The Connecticut Department of Revenue Services has challenged the computation of real estate conveyance taxes due in connection with Northeast Generation's acquisition of facilities from Connecticut Light & Power in March 2000. The issue relates to how much of the acquisition price was attributable to real estate as opposed to other assets. The deficiency claimed by the Connecticut Department of Revenue Services is approximately $0.6 million. Northeast Generation is currently unable to predict the outcome of this dispute.

F–13


APPENDIX A

Independent Technical Review for
Northeast Generation Company

CONFIDENTIAL

October 11, 2001
FINAL REPORT



LEGAL NOTICE

    This report was prepared by S&W Consultants ("S&W Consultants"), expressly for Northeast Generation Company ("NGC") on behalf of Salomon Smith Barney Inc. ("Salomon"). Neither S&W Consultants nor NGC, nor Salomon nor any person acting on their behalf: (a) makes any warranty, express or implied, with respect to the use of any information or methods disclosed in this report; or (b) assumes any liability with respect to the use of any information or methods disclosed in this report.

    S&W Consultants understands that this report will be used by prospective investors in evaluating the technical, environmental and economic aspects to support the bond financing to refinance generating assets purchased by NGC from The Connecticut Light and Power Company and Western Massachusetts Electric Company. Further, S&W Consultants understands that the Final Report may be included in the document relating to the refinancing of these certain assets.


ELECTRONIC MAIL NOTICE

    Electronic mail copies of this report are not official unless authenticated and signed by S&W Consultants and are not to be modified in any manner without S&W Consultants' express written consent.

A–ii



Independent Technical Review for Northeast Generation Company

Table of Contents

 
   
  Page
1   EXECUTIVE SUMMARY   A-1

 

 

   1.1   
BACKGROUND

 

A-2
       1.2   SCOPE OF SERVICES   A-2
       1.3   CONDITION ASSESSMENT   A-2
       1.4   HISTORICAL AND PROJECTED PERFORMANCE   A-3
       1.5   REVIEW OF O&M PLANS AND BUDGETS   A-3
       1.6   REVIEW OF ENVIRONMENTAL ASSESSMENT   A-4
       1.7   REVIEW OF REGIONAL HYDROLOGIC ISSUES   A-5
       1.8   FINANCIAL PROJECTIONS   A-5

2

 

INTRODUCTION

 

A-5

 

 

   2.1   
BACKGROUND

 

A-5
       2.2   SCOPE OF SERVICES   A-7
           2.2.1   Condition Assessment   A-7
           2.2.2   Historical and Projected Performance   A-8
           2.2.3   Review of O&M Plans and Budgets   A-8
           2.2.4   Review of Environmental Assessment   A-8
           2.2.5   Review of Regional Hydrologic Issues   A-9
           2.2.6   Financial Projections   A-9

3

 

NORTHFIELD MOUNTAIN SYSTEM

 

A-9

 

 

   3.1   
DESCRIPTION OF ASSETS

 

A-10
           3.1.1   Northfield Mountain   A-10
           3.1.2   Turners Falls Project (includes Cabot Station)   A-15
           3.1.3   Turners Falls Dam   A-23
           3.1.4   Remaining Life   A-23
       3.2   OPERATIONS AND MAINTENANCE   A-24
           3.2.1   General   A-24
           3.2.2   Northfield Mountain System   A-24
       3.3   ENVIRONMENTAL/LICENSING   A-26
           3.3.1   Northfield Mountain Pumped Storage Project   A-26
           3.3.2   Cabot Hydro Station   A-27
           3.3.3   Turners Falls No. 1 Hydro   A-28

4

 

HOUSATONIC HYDRO SYSTEM

 

A-29

 

 

   4.1   
DESCRIPTION OF ASSETS

 

A-30
           4.1.1   Falls Village   A-30
           4.1.2   Bulls Bridge   A-35
           4.1.3   Rocky River   A-39
           4.1.4   Shepaug   A-43
           4.1.5   Stevenson   A-46
           4.1.6   Robertsville   A-50
           4.1.7   Bantam   A-51
           4.1.8   Remaining Life   A-54
       4.2   OPERATIONS & MAINTENANCE   A-54
           4.2.1   System Staffing Levels   A-54
           4.2.2   Operation and Maintenance Expenses   A-55
           4.2.3   Overhaul Schedule   A-55
           4.2.4   Capital and O&M Project Expense Forecast   A-55
           4.2.5   Maintenance Management and Spare Parts   A-56

A–iii


       4.3   ENVIRONMENTAL/LICENSING   A-56
           4.3.1   Falls Village   A-57
           4.3.2   Bulls Bridge   A-57
           4.3.3   Rocky River   A-59
           4.3.4   Shepaug   A-59
           4.3.5   Stevenson   A-60
           4.3.6   Bantam   A-61
           4.3.7   Robertsville   A-61

5

 

EASTERN HYDRO SYSTEM

 

A-61

 

 

   5.1   
DESCRIPTION OF ASSETS

 

A-62
           5.1.1   Scotland   A-62
           5.1.2   Tunnel   A-64
           5.1.3   Taftville   A-67
           5.1.4   Remaining Life   A-69
       5.2   OPERATIONS AND MAINTENANCE   A-69
           5.2.1   Staffing Levels   A-70
           5.2.2   Operation and Maintenance Expenses   A-70
           5.2.3   Overhaul Schedule   A-70
           5.2.4   Capital and O&M Project Expense Forecast   A-71
           5.2.5   Maintenance Management and Spare Parts   A-71
       5.3   ENVIRONMENTAL/LICENSING   A-71
           5.3.1   Scotland   A-71
           5.3.2   Tunnel Hydro Station   A-73
           5.3.3   Tunnel ICU   A-73
           5.3.4   Taftville   A-75

6

 

FLOW STUDIES

 

A-76

 

 

   6.1   
VARIATION OF GENERATION AS A FUNCTION OF RIVER FLOW:
   NORTHFIELD MOUNTAIN

 

A-76
       6.2   IMPACT OF DROUGHT ON NORTHFIELD MOUNTAIN STATION OPERATION   A-77
       6.3   HIGH FLOW EVENTS   A-78
       6.4   VARIATION OF GENERATION AS A FUNCTION OF RIVER FLOW: CABOT STATION   A-79
       6.5   VARIATION OF GENERATION AS A FUNCTION OF RIVER FLOW:
   ADDITIONAL STATIONS
  A-80

7

 

PROJECT AGREEMENTS

 

A-80

 

 

   7.1   
POWER PURCHASE AND SALES AGREEMENT

 

A-80
       7.2   MANAGEMENT AND OPERATION AGREEMENT   A-81
           7.2.1   CUO   A-83

8

 

FINANCIAL PROJECTIONS

 

A-83

 

 

   8.1   
MODEL OVERVIEW

 

A-83
           8.1.1   General Assumptions   A-85
       8.2   TECHNICAL ASSUMPTIONS   A-86
       8.3   REVENUES   A-86
       8.4   EXPENSES   A-87
           8.4.1   O&M Expenses   A-87
           8.4.2   Capital Projects Expenses   A-87
           8.4.3   Fuel and Purchased Energy Expenses   A-87
       8.5   RESULTS   A-87

A–iv


1 EXECUTIVE SUMMARY

    Northeast Generation Company (NGC) provided S&W Consultants with a revised financial model and updated availability and capacity factor data, and requested S&W Consultants to review the model and reissue the report with all appropriate changes to the previous December 2000 Report. The revisions to the latest financial model consist primarily of minor working capital changes, 2005 revenue changes, 2016-2019 revenue escalation rates, fixed O&M and capital changes, and financing term changes (The latter was provided by Salomon Smith Barney). The resulting Report alterations consist of updates to graphs and charts to reflect the changes associated with the latest model and the new availability and capacity data.

    The hydroelectric assets (including one combustion turbine in the Eastern Hydro System) were divided into three separate bundles for purchase, with purchase options including any bundle individually or any combination of bundles. The hydroelectric bundles have a combined electric generating capacity of approximately 1,289 MW, and are as follows:

•  Northfield Mountain System:   1,139 MW
•  Housatonic Hydro System:   123 MW
•  Eastern Hydro System:   27 MW

    At the request of NGC, S&W Consultants performed a re-evaluation of the Northfield Mountain, Housatonic Hydro, and Eastern Hydro Systems' assets to determine if any changes have occurred since the earlier 1999 and 2000 reviews that could affect operations and project value. This report presents the updated findings.

    The assets include pumped storage and conventional peaking and "run-of-river" hydroelectric generating facilities, and one combustion turbine unit. General station characteristics are summarized on Table 1-1. Current refinancing is for all three bundles in combination. To facilitate this current review, the assets have been kept in the separate bundles for the technical reviews, as they were presented in the original report. In looking at overall financial issues and potential risk, however, a cumulative review has been performed of the combined projects.


Table 1-1. Station Characteristics

System

  Description
  Capacity
(MW, 2000)

  Year
Commissioned

  Projected
Remaining
Economic Life (yrs)

Northfield Mountain System                
  Northfield Mountain   Pumped storage   1080   1972   40
  Cabot   Conventional Hydro   53   1916   40
  Turners Falls No. 1   Conventional Hydro   6.25   1905   40
Housatonic Hydro System                
  Falls Village   Conventional Hydro   11   1913   40
  Bulls Bridge   Conventional Hydro   8.4   1903   40
  Rocky River   Pumped storage   29.9   1929   40
  Shepaug   Conventional Hydro   43.4   1955   40
  Stevenson   Conventional Hydro   28.9   1919   40
  Robertsville   Conventional Hydro   0.62   1914   20
  Bantam   Conventional Hydro   0.32   1905   20
Eastern Hydro System                
  Scotland   Conventional Hydro   2.2   1909   20
  Tunnel   Conventional Hydro   2.1   1919   20
  Tunnel ICU   Combustion Turbine   20.8   1969   20
  Taftville   Conventional Hydro   2.0   1906   20

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1.1 Background

    The Connecticut Light & Power Company (CL&P), an operating subsidiary of Northeast Utilities, sold, through an auction process, all of its non-nuclear generation facilities. CL&P's affiliates were permitted to bid on the CL&P plants. The Northfield Mountain System assets were partially owned by Western Massachusetts Electric Company (WMECO), another operating subsidiary of Northeast Utilities, and these assets were included in the CL&P sale process. NGC, an unregulated affiliate, was the successful bidder for the CL&P and WMECO assets shown above. In March, 2000, NGC purchased CL&P's hydro generation facilities, and one internal combustion unit. S&W Consultants performed the independent technical review supporting the transaction, updated the report in December 2000, and is now updating that report to reflect recently provided data.

    NGC sells capacity, associated energy output and ancillary services associated with the assets to Select Energy, Inc. (Select) through a Power Purchase Agreement. Northeast Generation Services Company (NGS), through a Management and Operations Agreement, manages, operates and maintains the facilities. Both Select and NGS are affiliates of NGC.

1.2 Scope of Services

    This Report presents the findings and conclusions of S&W Consultants' independent technical review regarding the following:

    S&W Consultants' findings in these areas are summarized below.

1.3 Condition Assessment

    S&W Consultants' conclusions are based on the brief visual inspections conducted during site visits, review of reports and documents, interviews with Owner and NGS personnel, and its experience with plants of similar vintage and design. Our conclusions are specific to the operating plans and associated capital, operating and maintenance budgets envisioned by NGC. This means we did not evaluate the potential life of these units beyond the expected life utilization by NGC. NGC projects the remaining economic lives for the assets as 40 years for the Northfield Mountain System, 40 years for the Housatonic Hydro System (with the exception of 20 years for Robertsville and Bantam), and 20 years for the Eastern Hydro System.

    Overall, the plants appeared to be in good condition given their age and operational history. In general, we found the power plants to be in adequate condition for the intended utilization, projected economic lives and O&M plan. Most of the stations have upgraded control systems to permit an

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increase in automation and a reduction of operating and maintenance personnel, all of which is reflected in the operating and maintenance budgets for the hydroelectric plants.

1.4 Historical and Projected Performance

    Projected performance statistics during the expected life for each of the assets are generally consistent with historical performance and considered reasonable. Availability and capacity factor data is summarized in Table 1-2.


Table 1-2. Station Performance Statistics (Average, %)

System

  Historical Availability,
1996-2000

  Historical Capacity
Factor, 1996-2000

  Projected Capacity
Factor, 2001-2009*

Northfield Mountain System            
  Northfield Mountain   92.6   11.5   17.5
  Cabot   97.9   59.4   57.1
  Turners Falls No. 1   96.7   32.0   27.3

Housatonic Hydro System

 

 

 

 

 

 
  Falls Village   97.6   48.4   42.4
  Bulls Bridge   89.2   59.5   61.0
  Rocky River   98.5   5.2   5.9
  Shepaug   96.8   36.3   31.7
  Stevenson   97.9   43.2   40.5
  Robertsville   100.0   12.2   24.7
  Bantam   98.9   37.2   50.0

Eastern Hydro System

 

 

 

 

 

 
  Scotland   90.4   35.1   41.5
  Tunnel   98.4   48.6   51.8
  Tunnel ICU   97.0   0.7   1.0
  Taftville   91.8   40.6   36.3

*
The projected capacity factor at the conventional hydroelectric stations would be based on statistical patterns of river flow. Predictions of river flow for individual years would not be valid.

1.5 Review of O&M Plans and Budgets

    S&W Consultants reviewed historical O&M performance and cost data contained in various documents that were made available for the sale of the assets. S&W Consultants also interviewed management personnel and reviewed station records during our site visits. The assessment of O&M projections focused largely on the Continued Unit Operation (CUO) studies prepared by NGS for NGC.

    Under the terms of the Management and Operations Agreement, NGS manages, maintains and operates the facilities on behalf of NGC. NGS, in turn, contracted for labor and services with Northeast Utilities Service Company (NUSCo) through a Service Contract. NGS was able to access the experienced station management, operations and maintenance staff (whether employed pre-sale by CL&P, WMECo or another affiliated entity) for continuing operation of the assets. Access to former CL&P and WMECO station personnel was considered critical to continued safe and reliable operation and effective maintenance of the assets after the transfer of ownership to NGC.

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    S&W Consultants reviewed the projected staffing levels and composition, O&M expenses, O&M and capital projects expenses, maintenance and overhaul schedules and spare parts inventories. Each of these components of the going-forward O&M plan was generally considered reasonable for the intended utilization of the facilities.

1.6 Review of Environmental Assessment

    S&W Consultants' environmental review task focuses on those environmental issues that have the potential to result in significant mitigation or compliance expenditures or operating constraints.

    S&W Consultants' environmental personnel participated in site visits in 1999, and reviewed permit-related documentation that was then available. At that time, all of the hydroelectric plants were in compliance with existing permits and licenses. This report has been updated to reflect new environmental commitments and licensing requirements that have been developed since the 1999 review. This evaluation included a review of previous issues and concerns, discussions with NGC and NGS personnel, and a review of pertinent documents and correspondence occurring since the previous review.

    Certain stations are undergoing FERC license renewals, which could affect the future utilization of these facilities. Fish passage, minimum flow requirements and impoundment level fluctuations are issues facing just about all the hydroelectric plants in New England, including those evaluated. The status of the licenses is summarized below:

    S&W Consultants reviewed the environmental reports (Phase I Environmental Site Assessment and Phase II Environmental Field Investigation reports) prepared by Metcalf & Eddy (Environmental Consultant) for each of the stations. The reports pointed to several potential areas of contamination. Remediation of these areas may be needed, but the costs are very difficult to estimate without a more detailed analysis of the quantity of materials that need to be removed and the nature of the remediation activity. However, the probability of the costs exceeding $2 million is low.

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    In general, all the hydroelectric plants have been operated judiciously from an environmental point of view. Identified environmental issues have been taken into account in the operational plans for these power plants. Future environmental issues which could affect the operation of these stations are very difficult to predict and thus, impossible to plan for or budget with certainty. Our conclusion is that the projected utilization of these power plants by NGC is based on sound environmental principles and the existing body of regulatory knowledge.

1.7 Review of Regional Hydrologic Issues

    S&W Consultants reviewed the relationship between historical gross annual generation and river flows to examine, qualitatively, the potential impact of fluctuations in the hydrologic cycle on operation of the assets. This review included an assessment of:

    As part of the analysis, S&W Consultants plotted the average annual flow versus total generation data, sorted by increasing flow rates, to depict the relationship between generation and river flow. The general trend for Northfield Mountain is that annual generation increases slightly as average annual river flow decreases. Conversely and as anticipated, the data indicated that the conventional run-of-river plants generate less energy at lower average annual flows. The results of the flow studies analyses, while approximate, also indicate that Northfield Mountain generation has not been significantly affected by historical flow variations, either high or low (i.e., flood or drought). These combined results tend to reduce the overall sensitivity of the assets to fluctuations in the hydrologic cycle.

1.8 Financial Projections

    S&W Consultants developed an independent pro forma financial model that reflects the terms of the NGC-Select Power Purchase and Sales Agreement and the NGC-NGS Management and Operation Agreement, and incorporates the capacity and energy pricing forecasts prepared by the Market Consultant and the assumed financing terms provided by Salomon. The financing structure consists of a two tranche $440 million bond issue. The $120 million Tranche A has a four year tenor at a 4.998% coupon rate with a scheduled amortization as shown in section 8.1. The $320 million Tranche B has a 25 year tenor, an 8.812% coupon rate, a grace period for principal payments of 5 years and a scheduled amortization during years 6 through 25 as shown in section 8.1. The financial projections show an average debt service coverage ratio of 3.05x with a minimum debt service coverage ratio of 1.54x for the life of the systems. It should be noted that the underlying cash flow assumptions have not changed since the model's inception, and the only changes in the revised financial model consist of minor, non-material revisions in fixed O&M and capital costs, and a correction in misstated revenue in 2005 and revenue escalation rates in 2016-2019.

2 INTRODUCTION

2.1 Background

    The Connecticut Light & Power Company (CL&P), an operating subsidiary of Northeast Utilities, sold through an auction process, all of its non-nuclear generation facilities. CL&P's affiliates were permitted to bid on the CL&P plants. The Northfield Mountain System was partially owned by Western Massachusetts Electric Company (WMECO), another operating subsidiary of Northeast Utilities, and

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these assets were included in the CL&P sale process. Northeast Generation Company (NGC), an unregulated affiliate, was the successful bidder for the CL&P and WMECO assets shown below.

System

  Description
  Installed
Capacity (MW)(1)

Northfield Mountain System        
  Northfield Mountain(2)   Pumped storage   1,080.0
  Cabot(3)   Conventional Hydro   53.0
  Turners Falls No. 1(3)   Conventional Hydro   6.25
       
Subtotal   1,139.25

Housatonic Hydro System

 

 

 

 
  Falls Village   Conventional Hydro   11.0
Bulls Bridge   Conventional Hydro   8.4
Rocky River   Pumped Storage   29.9
  Shepaug   Conventional Hydro   43.4
  Stevenson   Conventional Hydro   28.9
  Robertsville   Conventional Hydro   0.62
  Bantam   Conventional Hydro   0.32
       
Subtotal   122.54

Eastern Hydro System

 

 

 

 
  Scotland   Conventional Hydro   2.2
  Tunnel   Conventional Hydro   2.1
  Tunnel ICU   Combustion Turbine   20.8
  Taftville   Conventional Hydro   2.03
       
Subtotal   27.13
Total   1,288.92

Notes:

(1)
All ratings represent maximum winter claimed capacity (net)

(2)
Prior ownership 81% CL&P, 19% WMECO

(3)
Prior ownership 100% WMECO. All other units 100% CL&P

    S&W Consultants prepared this independent technical review (Report) of these assets on behalf of Salomon, in connection with NGC's bond issue. The completion of the refinancing of these assets is expected to occur during year 2001.

    This Report, including the observations and conclusions presented herein, is based on our previous reviews of the available technical, performance and cost data, visits to each facility, interviews with Owner personnel and the recent data provided by NGC. The Report presents our findings and conclusions regarding the following:

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    The principal considerations and assumptions used by S&W Consultants in completing this Report include:

2.2 Scope of Services

    S&W Consultants was retained to prepare an independent technical review for the bond refinancing being pursued by NGC. Our services for this current assignment are summarized below.

2.2.1 Condition Assessment

    Our assessment of the condition of the assets included an assessment of the apparent condition and operability of the major civil, mechanical and electrical components of each station. In addition, S&W Consultants commented on the reasonableness of NGC's remaining economic life assumptions, considering the expected service duty and projected operating plan. The results of our condition assessment, summarized in this Report, are based on the following:

    S&W Consultants performed walk-through visits of the facility sites per the following schedule:

System

  Site Visit
Housatonic Hydro System    
  Falls Village   Thursday, April 29, 1999 (five stations)
  Bulls Bridge    
  Rocky River    
  Shepaug    
  Stevenson    
  Robertsville   Wednesday, August 18, 1999 (two stations)
  Bantam    

Eastern Hydro System

 

Saturday, May 1, 1999
  Scotland    
  Tunnel    
  Tunnel ICU    
  Taftville    

Northfield Mountain System

 

Friday, April 30, 1999
  Northfield Mountain    
  Cabot    
  Turners Falls No. 1    

    Non-destructive Examination ("NDE") and Non-destructive Testing ("NDT") examinations of equipment and structures were not included in the scope of this review.

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    The safety of the dams under assessment comes under the jurisdiction of either the Federal Energy Regulatory Commission (FERC) or the Connecticut Department of Environmental Protection (CT DEP). The NGC projects that are licensed by the FERC are Falls Village, Bulls Bridge, Rocky River, Shepaug, and Stevenson, Scotland, Northfield, and Turners Falls. The remaining projects, Bantam, Robertsville, Taftville, and Tunnel, are not licensed by the FERC and as a result, the dam safety of these projects comes under the jurisdiction of the CT DEP.

    Each of the FERC projects must conform to the FERC dam safety guidelines with respect to structural stability, spillway adequacy and operations and maintenance. Each project is inspected annually by the FERC and on a five-year basis by an Independent Consultant approved by the FERC. The Independent Consultant evaluates the stability, spillway adequacy and condition of the project on an on-going basis.

    The four projects under CT DEP jurisdiction are designated as classification Significant "B" defined by the potential damage resulting from the failure of the dam. Significant "B" dams have the potential to cause the following damage if failure were to occur: possible loss of life, minor damage to habitable structures, damage to or interruption of utilities, damage to primary roadways and significant economic loss. Significant "B" projects are required to be inspected by the CT DEP every five years at a minimum. According to the CT DEP Dam Safety Regulations, each periodic inspection includes a visual inspection of the project facilities; a review of the data on design, construction, and maintenance of the structures; a review of downstream hazard potential; and an evaluation on the hydraulic capacity and structural stability.

    A summary of the findings from the most recent inspections as well as any findings related to project stability and spillway adequacy are provided for each project as applicable.

2.2.2 Historical and Projected Performance

    S&W Consultants reviewed the available historical performance (availability, capacity) data to evaluate the reasonableness of the projected performance of the units. The impact of planned capital projects on performance was incorporated as part of this review.

2.2.3 Review of O&M Plans and Budgets

    The assessment included a review of the operation and maintenance projections to determine their adequacy for continued safe and reliable operation, based on both historical data for the units and on comparison with data for similar plants. For each of the assets, S&W Consultants reviewed the projected staffing levels, the O&M budgets, the overhaul schedules, and the capital projects expense data provided by NGC. In addition, we reviewed the maintenance management practices and the spare parts inventories for adequacy.

2.2.4 Review of Environmental Assessment

    S&W Consultants evaluated environmental and permit conditions that could affect the future operation of the hydro and combustion turbine units. Comments are included in this report to identify and discuss FERC relicensing and site contamination issues, based on the Phase I and II Environmental Reports and additional documentation provided, for the hydroelectric stations. We reviewed and commented on NGC's plans for maintaining the Plants in compliance with their permits and the costs associated with maintaining environmental compliance over the potential term of the financing.

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2.2.5 Review of Regional Hydrologic Issues

    S&W Consultants conducted a qualitative review of historical hydrologic data pertaining to issues potentially affecting continued operation of the plants. This review included an assessment of:

2.2.6 Financial Projections

    S&W Consultants developed the original pro forma financial model that reflects the terms of the NGC-Select Power Purchase and Sales Agreement and the NGC-NGS Management and Operation Agreement, and incorporates the capacity and energy pricing forecasts prepared by the Market Consultant and financing terms assumptions provided by Salomon. The pro forma financial projections show cash flows available to support the repayment of debt, under "base case," "low fuel," and "capacity overbuild" pricing scenarios. It should be noted that despite recent revisions and changes to the layout of the original model, the underlying cash flow assumptions/drivers have not changed since the model's inception. The only changes in the current financial model consist of minor, non-material revisions in fixed O&M and capital costs, and a correction in a previously misstated revenue in 2005.

3 NORTHFIELD MOUNTAIN SYSTEM

    The Northfield Mountain System consists of the Northfield Mountain Project and the Turners Falls Project (which includes the Cabot and Turners Falls No. 1 stations and the Turners Falls Dam). This system includes one major pumped storage station and two conventional hydro stations. All of these stations are intertwined operationally because they all use the portion of the Connecticut River between Vernon and Turners Falls. This portion of the river forms the lower reservoir for the Northfield Mountain Pumped Storage station and it also feeds the canal that serves the Turners Falls No. 1 station and the Cabot station.

    Basic data for these three stations are given in the Table 3-1.


Table 3-1: Basic Unit Data

Plant Data

  Northfield
  Turners Falls No.1
  Cabot
Commissioning Date   1972   1905   1915
Operational Cycle   Weekly   Daily   Daily
Total Capacity (MW)   1,080   6.25   53.0
Total Turbine Flow (cfs)   20,000   2,000   13,000
Conventional Units       5   6
Pump-Turbines   4        
Max Operating Pond (ft)   1000.5       173.26
Nominal Tailwater (ft)   176.0 Min
185.0 Max.
      113.26 Normal
Gross Head (ft)   829.5 Normal
753.0 Min
  43.7 Max   64 Max
60 Normal
Unit Data (Conventional Units)            
Shaft Orientation   Vertical   Horizontal   Vertical
Turbine Type   Francis P-T   Francis   Francis
Runners per Unit   1:all   1: Units 1, 2   1: all
        2: Units 3, 5, 7    

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3.1 Description of Assets

3.1.1 Northfield Mountain

    The Northfield Mountain Project was originally constructed in 1972 and is located in the towns of Northfield, Erving, Montague and Gill, Massachusetts; Hinsdale, New Hampshire; and Vernon, Vermont. It currently has a claimed capacity of 1080 MW. The Northfield Mountain Project consists of an underground powerhouse, a man-made upper reservoir and the Turners Falls pond serving as the lower reservoir. An underground penstock, draft tube, and tailrace tunnel connect the upper and lower reservoirs.

    The Northfield Mountain Pumped Storage Station is one of the most responsive pumped storage projects in the world. It can be used to transform off-peak energy into on-peak energy, and one of its most positive attributes is its ability to provide rapid and flexible response to short-term events on the transmission and distribution system. The present condition of this plant reflects the meticulous long-term attention that has been given to the maintenance program. The consistently high unit availabilities suggest that the maintenance activities and overhauls have been appropriately timed and expeditiously executed. Continued attention at this level is absolutely necessary at a plant that experiences such frequent mode changing.

3.1.1.1 Civil and Mechanical Equipment and Systems

    The first unit at this station was placed in operation in 1972. The station has a man-made upper reservoir on the top of Northfield Mountain, a powerhouse cavern deep within the mountain below this reservoir, and a series of penstocks and tunnels that serve as water conduits and access tunnels. The tailrace tunnel is over a mile long and is served by a surge tank that was formed from vertical shafts combined with portions of the access tunnels that were used during construction.

    The station has four reversible pump-turbine/generator-motor units. Step-up from the 13.8 kV generator voltage to 345 kV is performed by two transformers located in vaults within the cavern. There is one transformer for each pair of units. The high voltage connection with the switchyard is by means of oil filled pipe type cables. Pump starting is accomplished with the use of a starting motor and a tailwater depression air system.

    No units were operating at the time of the site visit and Unit 2 was out of service for a "mini- overhaul". The equivalent availability factor has been consistently in the upper 90s. The reasons for this excellent performance—and its economical achievement—were clearly evident during the site visit. There were 16 millwrights on site for the mini overhaul, thereby providing for an extensive effort in a short time, to control the outage time. Activity was also in progress in other areas to make the most of this outage. The most recent overhaul of Unit 3 included the addition of digital governing equipment; this equipment improved the ability to fine-tune the station's contribution to system frequency control. Digital governing equipment was being installed on Unit 2 as part of the mini overhaul. The pump-turbines and generator-motors are original equipment—there have been no rewinds.

    At the upper reservoir it was noted that the water level was at elevation 980 ft. The operating limits are presently 1,000.5-ft maximum and 938-ft minimum. The design provides for an additional 4 ft of storage, to elevation 1004.5 ft. That additional storage capacity was intended to serve a water diversion facility that would have diverted water from the Connecticut River to the Quabbin Reservoir, which provides drinking water to greater Boston. The intake structure for that diversion was included in the initial construction but the diversion system was never developed. The additional 4-ft of storage could potentially be converted to power production use by obtaining a FERC license amendment. On June 1, 2001, in response to a request by Northeast Generation Company, the FERC granted a temporary amendment to the FERC license for the Northfield Mountain Pumped Storage Project authorizing a temporary change in the water surface elevation limits of the project's upper reservoir,

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for the purpose of allowing the generation of additional energy. Effective from June 1, 2001 through April 30, 2002, NGC is authorized to generate no more than 8,475 MWh of energy per day on each of no more than 20 days during a declared ISO-New England OP-4 Operating Procedure. This was granted by FERC because a "temporary change in project operations will alleviate projected shortages in energy in the Northeast in the summer of 2001...."

    The site visit included the tailrace area at the Connecticut River. This is the point where water is discharged to the river during generation and withdrawn from the river during pumping. At the time of the visit, there was a fish guidance net extending from the north side of the tailrace channel about halfway to the south side of the channel. The yellow floats identified the position of the net. The net extends 10 feet below the surface and was intended to guide the downstream migrants past the tailrace structure so that they would not be drawn in during pumping operation. The bypass effectiveness was said to be 97%.

    Another active issue on the Connecticut River is the reported erosion of the riverbanks in some areas. This erosion has been partially attributed to the rise and fall of the water level during the pumped storage operation. Despite the fact that natural river processes might have caused some of this erosion, the FERC has directed the Project to provide for bank stabilization in the affected areas, and yearly allowances have been included in the budgets.

    The maintenance buildings were included in the sale, along with the diesel generator house (575 kW), the pumping plant for the pipe type cable and the two pad mounted transformers. The boundary with the transmission and distribution system is at the motor operated disconnect ("MOD")'s at the end of the pipe type cable. It was noted that the French King feeder was not included in the sale.

    The transfer of off-peak energy to on-peak energy is accomplished with a pumping to generating energy ratio that ranges from 1.33 to 1.39 MWh of pumping input for each MWh of generating output. This is equivalent to a round trip efficiency of 72% to 75%, which compares very favorably with new or upgraded pumped storage plants elsewhere. This round trip efficiency also compares very favorably with the 76% value that was obtained in the early testing with only two units in operation. Station personnel have been continuously optimizing the operation through the use of acoustic flow meters combined with the normal station instruments. This optimization process has produced significant benefits.

    Another important feature of this station is its ability to respond rapidly to system emergencies. The combination of a short pressure conduit, downstream surge galleries and fast acting design of the equipment provides the opportunity for very responsive starting and loading in the generating mode. The Descriptive Memorandum associated with the original sale states that Northfield can achieve full plant output in three minutes from a shut down condition and turnaround from full pumping to full output generating in about fifteen minutes. We believe that these response times are conservatively understated. Furthermore, in the pumping mode, Northfield can deliver its full capacity to the system, instantly, by tripping the pumps. We understand that the standard of reference for fast response has historically been much slower than this and, consequently, this rapid response capability did not command a premium economic value over plants that would respond more slowly. The deregulated market might take a different approach and if so, there might be some flexibility for even further improvements in response time.

    In summary, the Northfield Mountain Station appears to be well maintained and in excellent condition.

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Dam Safety and Stability: Northfield Mountain

    The Fifth Safety Inspection by an Independent Consultant (Kleinschmidt Associates, Consulting Engineers) was performed in May 1998. The Independent Consultant's inspection of the Northfield project found the principal structures to be in good to excellent condition. Visual observations indicated that the project structures were being well maintained and operated in a prudent manner. No conditions requiring immediate repair or further investigation were reported other than renewing monitoring at a weir on the east side of the upper reservoir.

    The Independent Consultant also recommended that the results of a planned inspection of the powerhouse access tunnel be reviewed during the next five-year inspection. The access tunnel was inspected and a report, issued in August 1998, included recommendations to install rock bolts, mine straps, or crack monitors to 33 areas in the access tunnel. FERC responded that the results of the inspection be addressed in a Supplement to the Fifth Safety Inspection Report and the Independent Consultant issued a Supplement in February 1999 concurring with the recommendations of the report. The recommended modifications are scheduled to be completed in 2003.

    The Independent Consultant found the development's stability and spillway capacity to be adequate.

3.1.1.2 Electrical Equipment and Systems

    The station went into service in 1972. Nearly all of the generation and electrical equipment was reported to be original. The station appeared to be very well maintained and in good condition.

    The station configuration consists of four generator/motors. Unit 1 and Unit 2 generators feed power at 13.8 kV through individual circuit breakers to separate windings of a three winding step-up transformer. The high voltage side of the transformer is 345 kV and feeds a substation. There is a tap off between the generator circuit breaker and one of the low voltage windings of the step-up transformer that powers a station service transformer. The station service transformer supplies the station switchgear at 4160 V. This same configuration is applicable to Units 3 and 4. Two 4,160/480 V dry type transformers provide the station low voltage supply.

Generators

    The Northfield Mountain Station has four vertically mounted reversible General Electric generator/synchronous motor machines rated at 235 MVA/291,000 Hp each. The equipment was reported to be original, and it is understood that the motor/generators have never been rewound.

    GE Amplidyne machines excite the generators. The rotor fields are controlled by a GE designed liquid resistor system containing a water/sodium bicarbonate solution. This allows the pumping motors to be started with minimal electrical and mechanical stress. Operation of the liquid resistor system was reported as reliable and easily maintained. Operators were very satisfied.

    The number 2 and number 3 machines were recently overhauled (1998 and 2000, respectively). There was no obvious indication of damage or deterioration. Outage reports for the generators showed that generator 1 was mini overhauled and given the required inspections and testing in March 1994, May 1996 and May 1998. Unit 2 had the same type of inspections and testing in March 1992 and October 1996. Unit 3 reports indicated that the inspections and testing were done in May 1995 and May 1997. For unit 4, the dates are June 1993 and November 1995. The operators indicated that generator operation had been trouble free throughout their history. The working space adjacent to the generators appeared to be sufficient to permit any expected maintenance activities and equipment replacement when required. The generators were reported to be inspected and cleaned on a regular schedule.

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Medium-voltage switchgear

    The motor/generator starting and output circuit breakers are 13.8 kV, GE air circuit breakers. Station personnel advised that the chutes get replaced regularly. The arc chutes and breaker contacts are rebuilt on site. No major maintenance problems were reported.

    The 4,160 V ITE switchgear uses air-quenched circuit breakers. These breakers have been upgraded with solid state trips. Operation is reported to have been satisfactory.

Generator step-up and station service transformers

    The station has two 13.8 kV/345 kV, 3-phase oil cooled generator output transformers each rated at 500 MVA. The transformer oil is cooled in water to oil heat exchanger. The PCB content of the oil is placarded as less than 50 ppm. A minor oil seep from the 1X transformer system at the 1X pipe cable pothead has been repaired. There is a minor oil leak from the 3X transformer system at the 3X pipe cable pothead. This leak is scheduled for repair during a planned Fall 2001 transformer bank outage.

    The station has two 13.8 kV/4,160 V, 3-phase oil cooled station service transformers. The transformer oil is cooled in water-to-oil heat exchanger. The PCB content of the oil is placarded as less than 50 ppm. There were no signs of corrosion and the transformers appear to be in good condition.

    The bus ducts between the transformers and the generators appeared to be in good condition. Testing reports up through the early 1990's indicated that the isolated phase busses, transformers, and their connections received maintenance attention.

    The two low voltage dry type transformers are installed in two rooms inside the station. The rooms are protected from fire by a four-ton Cardox carbon dioxide fire protection system.

Controls

    A digital Woodward Electrohydraulic wicket controller was installed on the Unit 3 generator in 1998 and on Unit 2 in 1999, replacing the original analog Woodward Electro Hydraulic controller. Identical units are to be installed on Unit 4 in 2002 and Unit 1 in 2003.

    The analog instrumentation is typical of the late 1960's and early 1970's but has been progressively updated to digital instruments over time. The controls in the control room have largely been replaced with a "touch screen" computerized control system. Automated SCADA systems are being installed and upgraded. Station operation and dispatch is largely automated. The automation software is reported to be from Wonderware automation systems. Plant personnel indicated that the control system operation is very satisfactory. Panel wiring is being incrementally upgraded as instrument and control systems are modernized.

    Additional electrical equipment and systems observations include:

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    The Northfield Mountain station is only 28 years old and appeared to be operating acceptably. The original design of the equipment appears to be conservative.

3.1.1.3 Performance

    Northfield Mountain currently has a net rated capacity of 1080 MW, which is equally divided among four generating units. Northfield has the ability to quickly deliver reserve power on demand and has been a major supplier of "spinning reserves" for the New England Market. The operational cycle is weekly, and in the interim, the plant provides peaking and emergency reserve capacity by releasing water from the upper reservoir back to the river.

    A station audit was performed on February 21, 1989 with all four units operating together for two hours at a combined output of 1080 MW (4 × 270 MW). Additionally, each of the four units was audited in 1997, operating alone or together with other units, for two hours at 280 MW. The station capacity was given as 1120 MW (4 × 280 MW) on NEPOOL Form NX-12, effective 4/1/99. This capacity has since been reduced to 1080 MW (4 × 270 MW), effective 11/1/99. This is the capacity assumption currently included in the financial projections. A planned upgrade commencing in 2013 is expected to increase the rated capacity of each unit by 10 MW.

    Figure 3-1 shows the historical equivalent availability factors for Northfield Mountain, which are consistently in the 90's with the exception of Unit 3 in 1998, when an overhaul was being performed on this unit, and Unit 2 in 1999 and 2000 associated with scheduled maintenance and an overhaul of that

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unit. Historical capacity factors, which average 12% for all units over the period 1990-1998, are shown in Figure 3-2.


Figure 3-1.

     LOGO


Figure 3-2.

     LOGO

    The projected future capacity factor of 17.5%, determined by the Market Consultant, is slightly higher than the historical average and considered achievable over the anticipated economic life of the station. Some of the increase is expected because these pumped storage units are expected to be operated more aggressively in the deregulated market.

    The transfer of off-peak energy to on-peak energy is accomplished with a reported pumping to generating energy ratio that ranges from 1.33 to 1.39 MWh of pumping input for each MWh of generating output. This is equivalent to a round trip efficiency of 72% to 75%, which compares very favorably with new or upgraded pumped storage plants.

    Additional station performance information is provided in Section 6: Flow Studies.

3.1.2 Turners Falls Project (includes Cabot Station)

    The Turners Falls Project is located on the Connecticut River in the towns of Greenfield, Northfield, Erving, Montague and Gill, Massachusetts; Hinsdale, New Hampshire; and Vernon, Vermont. This project operates under a single FERC license and consists of two stations that are operated in coordination, Cabot Station (53 MW) and Turners Falls No. 1 Station (6.25 MW), and the Turners Falls Dam, as well as a two-mile power canal, a headgate house facility and three fish ladders. Northfield is authorized in its FERC license to utilize the Turners Falls Pond as a source of water for

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its operation. The capacity of the Turners Falls Pond is approximately 21,500 acre-feet of water. The reservoir has a drainage area of approximately 7,163 square miles.

3.1.2.1 Cabot Station

    Cabot Station, located in the town of Montague, is the largest conventional hydro station in this portfolio. Cabot Station operates six units with a rated capacity of 53 MW. The station structure has been operational since 1916 (NGC has indicated that the units were installed in 1915, 1916, and 1917) and is licensed by FERC to operate until April 30, 2018.

Civil and Mechanical Equipment and Systems

    The Cabot station is served by a power canal that receives its water from the Turners Falls dam. At its downstream end, the Cabot power canal widens into a forebay that serves the Cabot powerhouse on the left-bank side and the spillway section on the right-bank side. There are several bridges over the canal. The IP Bridge and the Strathmore Foot Bridge belong to Turners Falls and the 5th Street and 6th Street bridges belong to the state.

    The Cabot Station powerhouse has six vertical-shaft Francis-type turbine-generator units. All six of these units were operating at the time of the site visit and all of these units appeared to be operating smoothly, as viewed from the generator floor and from the turbine pits. There was no vortexing at any of the intakes. The plate over the door indicated that this station had begun its operation on February 26, 1916.

    The spillway has eight gates of 1,200-cfs capacity each. Six of these gates have new operators. The other two gate operators have been scheduled for replacement. Two of the spillway bay gates are equipped with trash racks and are used to provide fishway attraction water flow during the season of upstream fish migration. There is also a log sluice, which at the time of the site visit was passing about 400 cfs for downstream fish passage.

    A major upgrade of this station taking place during the years 2001 through 2003 was begun on June 1, 2001.This upgrade is expected to increase the station capacity from 53 MW to 62 MW and will be accomplished by replacing the turbine runners and wicket gates, rewinding the generators, replacing other major electrical items and performing additional restoration work. NGC has advised that the proposed upgrade at Cabot will have the same hydraulic capacity as the existing station. This is a conservative approach that would maintain the flow in the canal at its present value.

Electrical Equipment and Systems

    Much of the generation and electrical equipment is reported to be original. Some of the equipment has been rebuilt. The station has been modified to allow fully automated operation. The station has a 100 kW-diesel generator that is tested weekly and is reported to be problem free. Considering the age of the station it appeared to be reasonably well maintained and in generally good condition.

    The present Cabot Station configuration consists of six generators that feed power at 6.9 kV through circuit breakers to disconnect switches. Each disconnect switch position can either be open or closed to either of two 6900 V busses. From the 6900 V busses, feeds go to four sets of single-phase main step-up transformers that provide power to Montague substation. One feed off each of the two 6900 V bus goes to one of two main transformers. These then provide power to a 69 kV bus. The other two step-up transformers are provided power from a single feed off each of the 6900 V busses, and feed directly to a 115 kV-ring bus. From the 69 kV bus, an autotransformer connects to the 115 kV-ring bus.

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    The Cabot Station future arrangement will consist of the original six generators rewound to 13.8 kV. Three generators each will provide feeds through generator breakers to a new separate 15 kV bus. A circuit breaker off each the two 15 kV busses will tie to one new three-phase step-up 75 MVA transformer, that will provide power to a 115 kV-ring bus. Also off one of the new 15 kV busses, a fused disconnect switch will supply a new 13.8 kV to 575 V station service transformer.

Generators

    The station has six vertically mounted General Electric self-excited generators rated at 8.5 MW each. The equipment is reported to be original. All the generators have been rewound, the oldest being in 1956 and the most recent in 1963. There was no obvious indication of damage or deterioration. At the time of the site visit all of the generators were operating. The generators appeared to be running smoothly and no unusual noise or vibration was observed. Maintenance records indicate that unit 1 was inspected and overhauled in 1994. Unit 2 received armature, field and stator cable testing in 1994. Following a non-discernible noise coming from the unit 3 in 1998, the stator and field were inspected and insulation tested, and found to be acceptable. Unit 4 armature and field were tested in 1998. In 1990 and 1993 the generator field and stator was tested for unit 5. Unit 6 had its stator and field tested in 1991. Station personnel indicated that generator operation had been trouble free in the recent past. The working space adjacent to the generators is sufficient to permit any expected maintenance activities and equipment replacement when required.

Medium-voltage Switchgear

    The generator output circuit breakers and disconnect switches are installed in open face concrete cubicles which are covered with panels made of an unidentified material, possibly Transite. Transite is an asbestos bearing material. The cubicles are placarded with warnings about drilling into that material due to an asbestos hazard. The switchgear is reported to be the original GE supplied equipment. The cubicles are also placarded with PCB warnings. The equipment source of the PCB was not known. Exposed bus runs through the cubicles and throughout the station. The scheduled upgrade for 2001 through 2003 is to include the replacement of all main breakers with new 13.8 kV metal clad switchgear.

Generator step-up transformers and Autotransformer

    Of the four generator output transformers, two are GE and two are Westinghouse manufactured. All are single phase and water-cooled transformers in individual open front concrete cubicles inside the station. The transformers were said to be original equipment but some of the station personnel thought that the transformers might have been replaced circa 1930 but were not sure on this point. Due to the exposed buss bar and somewhat confined spaces visual inspection was somewhat limited. Transformer 6X received testing in 1990 and 5X in 1994. Transformer 1X was tested in 1990 and 2X in 1989. The scheduled upgrade for 2001 through 2003 is to include the replacement of 6 single phase 6.6 kV-69 kV and 6 single phase 6.6 kV-115 kV transformers and 1 three phase 69 kV-115 kV step-up transformer with 1 three phase 13.8 kV-115 kV GSU transformer.

    The PCB content of the oil is placarded as less than 50 ppm. There was very minor oil seepage around the top of several transformers. There were no signs of past major oil leaks and no oil stains on the floor. There is light corrosion around most of the transformers. The transformers are mounted on steel rails to permit withdrawal from the cubicle enclosure.

    The output of the 6.6-69 kV step-up transformers goes to a station autotransformer in the switchyard. This is a 69 kV/115 kV oil cooled transformer. The oil content of the transformer is placarded as containing less than 50 ppm PCB. There were no obvious leaks and the paint is in fair condition with only light rust visible.

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High Voltage Switchgear

    The 69 kV circuit breakers are an oil-quenched circuit breaker. The oil content of the breaker is placarded as containing less than 50 ppm PCB. There were no obvious leaks and the paint is in fair condition with only light rust visible.

Controls

    The instrument and control systems are a mix of the original Thompson-GE instruments and control devices along with newer instrument and control devices. Modern analog instruments have been installed and some digital instrumentation has been installed. A new SCADA system has been installed which allows the station to be operated and dispatched automatically. Dispatch information is provided by networked computer system. Station personnel indicate that the control system operation is satisfactory.

    Several of the panel boards are the original two-inch thick slate or marble panel boards. Panel wiring has been incrementally upgraded as instrument and control systems have been modernized but there is still old wiring in the panel boards. The insulation on this wiring is probably brittle and will tolerate little manipulation without cracking and spalling. Such wiring must be replaced when making changes to these circuits and will make rewiring and modification work more difficult. Some of the panel board wiring may contain asbestos in the insulation.

    Additional electrical equipment and systems observations include:

    The Cabot station is 83 years old and appears to be operating acceptably. The original design of the equipment was conservative and robust.

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Performance

    Cabot has a generating capacity of 53 MW. The six Cabot units are generally operated on a run-of-river basis and on a daily pond and release cycle. Figure 3-3 shows the historical equivalent availability factor for each unit, which is generally in the low to mid 90s.


Figure 3-3.

     LOGO

    Figure 3-4 shows the historical capacity factor as determined from monthly generation data. These capacity factors are somewhat higher than are typical for a run-of-river hydroelectric plant. The proposed upgrade of the Cabot Station would further utilize this potential.


Figure 3-4

     LOGO

    The future projected capacity factor of 57.1%, determined by the Market Consultant, is consistent with the historical capacity factor average, and is considered achievable over the projected economic life of the station.

3.1.2.2 Turners Falls No. 1 Station

    The Turners Falls Station No. 1 (6.25 MW) is located in the town of Montague. The indicated construction date is 1903. The first generating unit (Unit 5) went into service in 1905, followed by Unit 7 in 1908, Unit 3 in 1910 and Units 1 and 2 in 1913. The station originally had seven horizontal shaft

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double runner Francis type turbine-generator units. Unit 6 has been out of service for the past ten years. Unit 4 was originally an exciter unit and has been retired. This leaves five presently operable units. The available gross head is less than at Cabot. Furthermore, the generating units are of an older design. Turners Falls No.1 Station is therefore understood to operate only when the Cabot Station is fully loaded. The station is also used for spinning reserve. These units are started locally and then controlled from Northfield. Spinning reserve appears to be a motoring operation.

    At the time of the site visit, none of the units at Turners Falls No.1 were operating but there was leakage evident from the turbines to the tailrace. This is considered to be minor in nature and is addressed by regular annual maintenance of the station.

Dam Safety and Stability

    The Turners Falls project is licensed by the FERC, with the most recent FERC annual inspection performed in May 1998. Based upon observations during the inspection, the FERC inspector found all visible structures to be in good condition and well maintained. Bascule Gate No. 2 was not operational but repairs were scheduled and on November 13, 1998 following the repair, Bascule Gate No. 2 was returned to service. The inspector identified one action item, the provision of a modified public access path, to replace a vandalized wooden stairway in the Cabot Woods recreation site. The stairway has since been replaced with a wood chip foot path satisfying FERC. The inspector identified no items related to dam safety that would require follow-up action.

    The project structures are all classified as having a low hazard potential, and the project is exempted from the requirement to perform and file a Five-Year Safety Inspection. In 1993, prior to the reclassification, the Licensee submitted the Sixth Five-Year Safety Inspection Report that identified that all but two structures met the FERC required safety factors for a significant hazard structure. Two structures were determined to be unstable for the Probable Maximum Flood loading condition. Based on a determination that the failure of the two structures would cause insignificant incremental inundation in the downstream areas and would not present a hazard to life and property, FERC reclassified the two structures as low hazard and accepted the Sixth Five-Year Safety Inspection Report and development's stability and spillway capacity to be adequate considering the hazard classification of the project.

3.1.2.3 Electrical Equipment and Systems

    The station went into service on or about 1905. The station was deactivated at one point and reactivated in 1983. All of the generators were extensively rebuilt for the reactivation project. Most of the rest of the electrical equipment is reported to be original. The station is capable of semi-automatic operation but the generators require manual synchronization to the grid. Considering the age of the station it appeared to be reasonably well maintained and in generally good condition.

    The station configuration consists of five generators that parallel through circuit breakers and disconnect switches to a 2300 V bus. The 2300 V bus is connected through a disconnect switch to a 4.8 MVA step-up transformer that converts the voltage to feed 13.8 kV lines. Three 25 kVA transformers also are supplied from this line and provide feeds to Station Service panels at 240-120 V.

Generators

    The station has five active generators and two inactive generators that have been abandoned in place. The generators are horizontally mounted open frame machines. Allis Chalmers originally supplied four of the active machines. The remaining machines were originally supplied by Bullock Electric. In 1988, a new static exciter was installed which replaced the original hydraulic turbine driven exciters. Plant personnel reported that all the generators were extensively rebuilt in 1983. The generator windings were re-designed and rewound for increased capacity. At the time of the site visit

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none of the generators were operating. The operators indicated that generator operation had been trouble free in the recent past. There was no obvious indication of damage or deterioration. The working space adjacent to the generators is sufficient to permit any expected maintenance activities and equipment replacement when required. Due to the age of these generators, finding replacement parts may be problematic. Outage reports indicate that all five units were tested in 1990. The tests included stator and field windings as well as potential transformers, and stator cables. At this time relay calibration was also performed. All five units had acceptable test results with the following exceptions. For generators 3 and 5, pole drop readings lower than expected were uncovered. Also, on Unit 5 some poles had blistered and cracked insulation that exposed copper.

Generator

  Unit 1
  Unit 2
  Unit 3
  Unit 5
  Unit 7
Rated kW   1380   365   1276   1276   1276
Volts (kV)   2.3   2.3   2.3   2.3   2.3
PF   0.8   0.8   0.8   1.0   0.8
rpm   200   257   200   200   200

Medium-voltage switchgear

    The generator output circuit breakers are oil quenched devices and was reported to be the original GE supplied devices. The circuit breakers and disconnect switches are installed in open face concrete cubicles. The 2,400 volt bus work connected to the circuit breakers and disconnects is exposed. There was evidence of past oil leakage from the circuit breakers. The PCB content of the oil is placarded as less than 50 ppm. There were no reported operational problems with the circuit breakers.

Generator step-up transformers

    Westinghouse manufactured the 3 phase step-up transformer. The transformer is rated at 4.8/6 MVA was replaced in 1981. Access to the transformers was limited and visual inspection was not conducted. The PCB content of the oil was reported as less than 50 ppm. Tests and maintenance were made on this transformer in 1993 after an infrared scan showed a "hot" bushing connection. The testing was the standard Doble test that includes insulation ratio, resistance, turns ratio and power factor.

Controls

    The instrument and control systems were largely upgraded during the reactivation but there are a few of the original instruments and control devices that are still in service. Some of the panel boards are the original two-inch thick slate or marble. Panel wiring was almost completely rehabilitated during the reactivation and most of the wiring is modern. There may still be some old wiring in the panel boards, which should be replaced when making changes to these circuits. The old panel board wiring may contain asbestos insulation. Additional electrical equipment and systems observations include:

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    The Turners Falls station is 90 years old and appears to be operating acceptably. The original design of the equipment was conservative and robust.

3.1.2.4 Performance

    Turners Falls has a generating capacity of 6.25 MW. The station is operated for peak power and for spinning reserve. Historical equivalent availability factors are shown on Figure 3-5.


Figure 3-5

     LOGO

    Figure 3-6 shows the historical capacity factors as determined from monthly generation data. The relatively low capacity factors reflect the fact that this station is only dispatched when Cabot station is at full load.


Figure 3-6

     LOGO

    The projected capacity factor of 27.3% is comparable to the recent historical average and considered achievable over the projected economic life of the station.

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3.1.3 Turners Falls Dam

    The Turners Falls dam includes three Tainter gates on the right bank side, four Bascule gates toward the left bank side and the Turners Falls Gatehouse at the left abutment. There is also a fishway that operates between mid-May and July. The attraction water for this fishway was flowing at the time of the site visit.

    Careful regulation of the Turners Falls pond provides for the rise and fall of the reservoir in response to Northfield Mountain's pumped storage operation, while still providing for the passage of the natural flow in the Connecticut River. The cyclic variation in the Turners Falls pond level is maintained, to some extent, even when Turners Falls Dam is spilling water. The Bascule gates and Tainter gates were all added to the old Turners Falls dam to perform this function. The objective is to eliminate or minimize the effect of operation of Northfield on water flow downstream from Turners Falls. Because of the continual fluctuations in the Turners Falls pond, the Turners Falls gatehouse, which controls the water flow to the Cabot power canal, almost always has a continually changing variation in the differential head across its headgates. Continual adjustment is therefore required to provide a constant flow to the canal.

    In addition, the headgates in the Turners Falls Gatehouse must also close in the event of a major load rejection at the Cabot Station. The Cabot Station is provided with its own spillway gates that can deal with the excess inflow following a load rejection. These spillway gates cannot, however, completely deal with the surge wave caused by a six-unit load rejection, because this wave would already be on its way upstream before the spillway gates could respond. Immediate closure of the headgates will generate a negative wave that will move downstream and interact with the positive wave moving upstream. Backup power is provided for the headgate operators in the form of two separate incoming lines plus an emergency generator. The generator is tested weekly by interrupting the external power supplies and confirming that the emergency generator takes over.

3.1.4 Remaining Life

    Hydroelectric stations are generally assumed to have very long useful lives because, much of their asset value is represented in the dams and other civil structures. Many of the dams in New England have already experienced useful lives dating back to the early days of European settlement. Dam safety requirements dictate the continued periodic inspection of these facilities, with timely remedial action, if required.

    Obsolescence and deterioration of the power station equipment items are dealt with in periodic overhauls, upgrades and replacements in kind. However, with appropriate maintenance, many of these components can be operated for many decades. In many circumstances, larger capacity or more efficient replacement turbines might be installed in an existing powerhouse structure even if the existing turbines are still operating satisfactorily.

    The Northfield Mountain System includes one major pumped storage station and two conventional hydroelectric stations. The indicated construction dates, capacities and projected remaining economic lives are as follows:

Station

  Start-Up
Date

  Nominal
Capacity(MW)

  Projected Remaining
Economic Life (Yrs)

Northfield Mountain   1972   1080   40
Cabot   1916   53.0   40
Turners Falls No. 1   1905   6.25   40

    The major asset of this system is the Northfield Mountain Pumped Storage Station, which, by hydro standards, is relatively new. Assuming that station O&M is implemented per the NGC operating plan, the projected 40-year remaining economic life appears to be conservative.

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    Turners Falls No. 1 Station is another one of those stations approaching the century mark, and it is served by a dam that is even older. Turners Falls Dam also provides the impoundment for the Cabot Station and the lower reservoir water storage for Northfield. The dam experienced considerable upgrade and modification in the process of developing Northfield and should continue to receive appropriate maintenance because of its continuing importance to Northfield. A major upgrade is planned for Cabot during the years 2001 through 2003. The proposed upgrades, projected operating levels and the importance to Northfield make the projected 40 year remaining economic life appear to be reasonable for the Cabot and Turners Falls Stations.

3.2 Operations and Maintenance

3.2.1 General

    S&W Consultants reviewed historic O&M performance and cost data contained in various documents that were made available. S&W Consultants also interviewed management personnel and reviewed station records during its site visit. The assessment of O&M projections focused largely on the Continued Unit Operation (CUO) studies prepared by NGS for NGC.

    Under the terms of the Management and Operations Agreement (Section 7.2), NGS manages, maintains and operates the facilities on behalf of NGC. NGS, in turn, has contracted for labor and services with Northeast Utilities Service Company (NUSCo) through a Service Contract. NGS has been able to access the experienced station management, operations, maintenance, testing & calibration, etc., staff (whether employed pre-sale by CL&P, WMECo or an affiliated entity) for continuing operation of the assets. Access to former CL&P and WMECO station personnel was considered critical to continued safe and reliable operation and effective maintenance of the assets after the transfer of ownership to NGC. S&W Consultants assumes that the stations will continue to be operated, whether by NGS or NUSCo personnel, in a manner that is consistent with the plans presented in the CUO's.

3.2.2 Northfield Mountain System

3.2.2.1 Northfield Mountain System Staffing Levels

    The staffing level for the Northfield Mountain System is currently 47 people at Northfield Mountain station and 15 people at the Cabot and Turners Falls Stations. The NERC (Northfield Environmental and Recreation Center) employs 6 people. NGS plans to keep approximately the same staffing level. This staffing level is considered adequate for the operation of these units. The numbers are typical of those found in similarly configured Stations that S&W Consultants has reviewed.

3.2.2.2 Operation and Maintenance Expenses

    NGS's projected O&M expenses are summarized in the table below, shown as an annual average of the projected expenses from 2001 through 2039 for all units.


Northfield Mountain System O&M Expenses
(All Values in Nominal $000)

 
  Cabot and Turners Falls
  Northfield Mountain
2001-2009   $ 2,657   $ 9,907
2010-2019   $ 5,665   $ 16,154
2020-2029   $ 4,839   $ 17,940
2030-2039   $ 8,993   $ 21,814

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    The increasing O&M expenses reflect upgrades and major overhauls appropriate for the age of the equipment. The O&M expenses generally appear to be adequate based on the staffing level, projected operating level, historical experience and level of detail provided.

3.2.2.3 Overhaul Schedule

    S&W Consultants reviewed NGS's planned overhaul and maintenance schedule. The Turners Falls Station is projected to have no overhauls and no rewinds through the life of the station, which is reasonable considering its limited utilization. The Cabot Station is projected to have extensive overhauls and rewinds of all six units between 2001 and 2003 with subsequent overhauls planned and budgeted. The Northfield Mountain units will be overhauled approximately every fourteen years with Unit No.2 in 2000, 2014, and 2028 with a rewind in 2014, Unit No.1 in 2003, 2016, and 2030 with a rewind in 2016, Unit No.3 (which was overhauled in 1998) in 2013 and 2027 with a rewind in 2013, and Unit No.4 in 2002, 2015, and 2029 with a rewind in 2015.

    Given the projected capacity factors and the overhauls and rewinds that are to be performed, the plan appears to be adequate assuming that long-range maintenance planning is used effectively and that appropriate condition-monitoring programs are implemented, maintained and updated periodically.

3.2.2.4 Capital and O&M Project Expense Forecast

    NGS provided S&W Consultants with capital and O&M project expense forecasts, summarized in the following table. These projections were evaluated based on the condition of the Northfield Mountain System stations and the expected remaining operating life of the units.


Northfield Mountain System Capital & O&M Project Expenses
(Nominal $000's)

 
  Northfield Mountain
  Cabot & Turners Falls
 
  Capital
  O&M Projects
  Capital
  O&M Projects
2001-2004   $ 6,058   $ 9,173   $ 25,998   $ 1,287
2005-2009   $ 3,531   $ 2,924   $ 3,372   $ 891
2010-2014   $ 4,225   $ 16,992   $ 1,601   $ 871
2015-2019   $ 7,539   $ 18,565   $ 3,401   $ 16,970
2020-2024   $ 6,433   $ 1,962   $ 5,094   $ 4,626
2025-2029   $ 5,604   $ 18,451   $ 1,930   $ 1,249
2030-2034   $ 6,503   $ 8,348   $ 2,238   $ 18,848
2035-2039   $ 5,929   $ 2,410   $ 2,044   $ 7,134
   
 
 
 
  Total   $ 45,922   $ 78,825   $ 45,678   $ 51,879
   
 
 
 

    The forecast is considered reasonable given the age and condition of the stations. Major budgeted projects include major overhauls, river bank erosion control at Northfield, fish maintenance and FERC relicensing. The level of capital and O&M project expenses included is considered reasonable to keep the stations operating reliably through 2039.

3.2.2.5 Maintenance Management and Spare Parts

    NGS will continue to use a power plant Preventive Maintenance Management System (PMMS) to control maintenance information. NU currently uses the Passport system for spare parts and accounting. A PMMS developed by NU is fully integrated into the Passport system and its functionality is considered good.

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    S&W Consultants reviewed the current spare parts inventory summary for the Northfield Mountain System Stations. The spare parts inventory is valued at approximately $1.5 million. This appears to be sufficient and adequate to support operations and maintenance activities and reduces the probability of extended forced outages.

3.2.2.6 Maintenance Access

    This section addresses the adequacy of access for removal and return of major equipment at Northfield Mountain, if this should become necessary in the future. All major equipment must be transported in and out through the access tunnel. This was a design criterion for the characteristics of this tunnel because the equipment had to be moved in during construction. The largest item was a main transformer, which had to be transported in one piece. The pump-turbine runner was also transported in one piece. The generator stators came in sections. All of this equipment was successfully transported through the access tunnel into the powerhouse cavern. There was also a construction event that required the removal, reconditioning and reinstallation of major equipment in 1972, prior to start-up. We therefore believe that the access for future removal and reinstallation of major equipment will prove to be adequate.

3.3 Environmental / Licensing

    S&W Consultants' environmental review of the assets being refinanced by NGC focused on environmental issues that have the potential to result in significant mitigation expenditures or operating constraints. The assessment addresses, as applicable, air quality, water related concerns, licensing, site remediation and hazardous wastes. The observations and conclusions provided are based on the following:

3.3.1 Northfield Mountain Pumped Storage Project

    Northfield operates under FERC License No. 2485 issued May 14, 1968. The plant draws water from the ponded stretch of the Connecticut River between Turners Falls Dam, 51/2 miles downstream, and Vernon Dam upstream. Based on available information, there are no known amendments to license pending that would change the plant features or operation. At the same time, fish protection at the intake has been the subject of studies and continued dialogue with resource Agencies. Recent reports summarize testing of several technologies, but the greatest success is with offshore nets to divert downstream migrant smolt past the intake. Diversion results of above 90% were reported.

    FERC relicensing will be required in 2018. Based on current operations and concerns, future environmental compliance issues may include:

    In the meantime, it seems unlikely that major changes will be undertaken in the near future, and no significant additional costs are foreseen.

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3.3.1.1 Water Supply and Treatment

    The site's NPDES permit expired in September, 2000. In anticipation of this, NGC applied for a renewal to its NPDES permit on March 31, 2000. The application for Northfield has been judged complete by the state prior to processing. As is common practice, the station will continue to operate under its previous permit until the new permit is issued. The station uses a Best Management Practices program and has a limited wastewater treatment system compared to fossil-fueled plants. In addition, the plant discharge does not affect river water temperature. While new conditions pertaining to any of these items could be developed during reissuance, there is no indication of such changes. Also, despite the recent tendency of states to include more diverse concerns as the subject of conditions, it is unlikely that significant annual expenditures would be required to comply.

    While water quality and temperature do not appear to be issues, riverbank erosion requires control measures. Reports indicate bio-engineering work at five sites so far. Results are not clear as yet and the baseline program will continue for several more years. In year 2000, $700,000 was expended under the Erosion Control Plan, with $250,000 to $650,000 budgeted annually thereafter. Continuing erosion control efforts are likely to be needed as long as current operations continue.

3.3.1.2 Licensing

    Regular permit renewals are unlikely to result in major changes to the project or significant costs. FERC relicensing, however, opens a wide array of issues and examines numerous alternatives. Fish passage issues will continue unless ongoing studies of behavioral exclusion techniques, including use of large nets, yield consistently good results for downstream migrants and deal effectively with increases in upstream migrants. Previous studies have indicated that approach velocities during operation are so high that the exclusion devices cannot operate as designed. If no suitable alternatives are found in the interim, the focus of relicensing could be on reducing intake velocity. This could potentially require extensive shoreline excavation and reconstruction of the intake in a larger design, but the likelihood of this occurring is small.

    Another mitigation measure that may be considered is limitation of pool fluctuations or some base flow requirement in the river. For example, the Franklin County Commission has suggested a one to three foot fluctuation compared to the existing seven to nine foot. Such restrictions or requirements would have the effect of limiting when the storage reservoir could be filled and how quickly. This could both limit generation and change generation from peak to off-peak. However, it is impossible to know at this time whether such requirements will be considered or imposed in 2018.

3.3.1.3 Site Remediation

    Based on the Environmental Consultant's reports (Phase I and II), NGC is considering minor remediation work needed. Further sampling demonstrated that average levels of contamination were below Massachusetts 21e thresholds and therefore the three areas at Northfield/Turners Falls have been closed out with no additional site remediation required.

3.3.2 Cabot Hydro Station

    The Cabot Hydro Station has six units that operate for baseload and peaking capacity. The units draw water from the Turners Falls canal and release the water into the Connecticut River at the base of a bypass reach extending over 2.8 miles from the Turners Falls Dam. This reach is wide, includes several islands, has an irregular rocky bottom and alternates deeper pools and exposed rock when drawn down. Fishways are found at both Cabot and upstream in the reach just below the dam. Downstream fish passage is provided at the dam and through the canal. Minimum flow releases are specified throughout the year to support fish passage, primarily of salmon, shad and short-nosed sturgeon.

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    Operation of the station is tied closely to other elements of the Turners Falls Project as well as to the Northfield Pumped Storage Project upstream. In fact, Cabot is operated remotely from Northfield. The station operates under FERC License No. 1889 which was issued in April 30, 1968 and expires on April 30, 2018, together with Northfield and Turners Falls No. 1. The station was previously relicensed in 1980.

3.3.2.1 Water Supply and Treatment

    There is an active NPDES permit for minor station discharges and an application for a new permit has been submitted and judged complete. No major changes are anticipated in the near future.

    Because of the interdependence of the system facilities and the ongoing concerns with fish passage, water supply issues could result in changes in operation. Structural changes are also likely when these can enhance fish passage efficiency. Studies previously agreed to, particularly with the Connecticut River Atlantic Salmon Commission, are largely completed with moderate bypass efficiency having been achieved. While planned studies will decrease over the next few years, the focus on new target species or the desire for higher efficiencies for previously tested species could lead to further negotiated studies. Fish project budgets includes approximately $4m in 2004 and another $2m in 2006. This amount would account for the current target species for passage. Eel are a concern in some areas and including them on the list for Cabot might require additional mitigation measures.

    Increased flow diversion to enhance passage efficiency is being considered by resource agencies. For example, a release of no less than 5000 cfs is being considered by the CT Watershed Council for evaluation during relicensing in 2018.

3.3.2.2 Licensing

    Minor permit renewals and renegotiation with resource agencies are not expected to result in significant costs. The existence of upstream and downstream passage at Cabot and the ongoing discussions suggest this issue will be resolved over time prior to relicensing without the requirements for major changes in passage facilities during that process.

    One item that is likely to be considered is habitat enhancement in the bypass reach. This is commonly considered during FERC relicensing and is normally achieved by requiring additional flow to the bypass. This flow is no longer available for generation and, because of the shallow nature of the bypass, would have to be large enough to show an observable difference.

3.3.2.3 Site Remediation

    The Environmental Consultant's reports (Phase I and II) indicated one location with elevated PAH, but further sampling showed the average concentrations to be below reportable levels. Significant costs for follow-up are not indicated.

3.3.2.4 Hazardous Materials

    Asbestos has been observed in the facility but none in friable condition. Steps have been taken to limit access and abatement is stated to be unnecessary at present.

3.3.3 Turners Falls No. 1 Hydro

    The Turners Falls No. 1 facility operates under the same FERC license as Cabot Station with expiration scheduled for 2018. FERC relicensing is considered unlikely to result in significant cost factors as the focus of mitigation and enhancement measures would continue to be at Cabot or at the dam.

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3.3.3.1 Water Supply and Treatment

    The project operates without an NPDES permit.

    Given the small size of the plant and the relatively infrequent operation there are no fishways or related mitigation measures located at this site. Upstream and downstream passage are accounted for upstream at the dam and/or downstream at Cabot. There is no basis at present for major changes.

    The Town of Montague has raised concerns over levels of seepage in, and the stability of, the left embankment of the power canal. FERC has become involved and has required a reconnaissance level investigation. The recently released report of the consultant that performed the reconnaissance investigation notes, "There is no reason to conclude that seepage from the canal embankment has increased this year or anytime in the recent past. There is no evidence of higher flow rates, nor is there any indication of apparent disturbance of the soils comprising the embankment or its foundation, which affect the seepage rate. Since there is no indication of the seepage rate having changed, there is not felt to be any need to attempt to monitor seepage flows." At the same time, two boils were noted just beyond the downstream toe of the embankment. The consultant recommended further investigation and monitoring to ensure continued safe conditions.

3.3.3.2 Site Remediation

    The Environmental Consultant's reports (Phase I and II) indicated elevated PAH in soil. Further sampling showed the average concentration to be below reportable levels. Significant costs for follow-up are not needed.

3.3.3.3 Hazardous Materials

    Minor concerns associated with periodic oil sheens are attributed to other sources. The concern can be addressed at limited cost. There is some concern with other industry along the canal creating sediment contamination problems in the canal, but no conclusions can be made at this time.

4 HOUSATONIC HYDRO SYSTEM

    The Housatonic Hydro System is an integrated system of hydro plants located on and near the Housatonic River and its tributaries. The Housatonic Hydro System includes the following assets:

    There are six conventional hydro stations and one combined hydro and pumped storage station in this System. Basic data for the larger stations are shown in Table 4-1 (Robertson and Bantam have a combined capacity of less than 1 MW).

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Table 4-1. Housatonic Hydro System

Plant Data

  Falls Village
  Bulls Bridge
  Rocky River
  Shepaug
  Stevenson
FERC Project Number   2597*   2576   2576   2576   2576
Construction Date   1913   1903   1929   1955   1919
Operational Cycle   Run-of-river   Run-of-river   Daily&Seasonal   Weekly   Weekly
Total Capacity (MW)   11.0   8.4   29.9   43.4   28.9
Total Turbine Flow (cfs)   1700   1250   2080   6200   6230
Total Pump Flow (cfs)           460        
Conventional Units   3   6   1   1   4
Pump-Turbines           2        
Max Operating Pond (ft)   633.2   356.0   430   200   103
Nominal Tailwater (ft)   532.0   246.0   200   103   34
Nominal Gross Head at max pond (ft)   101.2   110.0   230   97   69
Summer Drawdown                    
  (ft) max   0   0   3   4.5   2.5
  (Acre-ft)   0   0   2,650   7,510   2,650
  Hours at Total Turbine/PumpFlow   0   0   15.4/69.7   14.7   9.7
Winter Drawdown                    
  (ft) max   0   0   11.5   4.5   5
  (Acre-ft)   0   0   63,570   7,510   5,000
  Hours at Total Turbine/Pump Flow   0   0   369.8 / 1672.7   14.7   9.7

Unit Data (Conventional Units)

 

 

 

 

 

 

 

 

 

 
Shaft Orientation   Horizontal   Horizontal   Vertical   Vertical   Vertical
Turbine Type   Francis   Francis   Francis   Fixed Blade   Francis
Runners per Unit   2   2   1   1   1
Speed (rpm)   300       200   138.5   150
Flow per Unit (cfs)   567   208       6200    
Net Head (ft)   90   103   226   96   70
Runner Dia. (inches)   48   35   101   195   3 of 82
1 of 86
Centerline Elev.   547.6   257.9   204   92   47

*
The current relicensing process is expected ultimately to combine Falls Village with the other Housatonic stations to form the Housatonic River Project.

    Site visits for five of the seven stations in the Housatonic System were conducted on April 29, 1999. Robertsville and Bantam were visited on August 18, 1999.

4.1 Description of Assets

4.1.1 Falls Village

    The Falls Village Station is an 11 MW conventional hydroelectric facility located on the Housatonic River in the northwest corner of Connecticut, in the towns of Canaan, North Canaan, and Salisbury. The Station has a drainage area of 634 square miles, and consists of an impoundment created by a concrete dam, a canal intake structure which supplies water to the power canal, a powerhouse intake structure which supplies water to five penstocks, and the powerhouse. Falls Village was constructed in 1913.

4.1.1.1 Civil and Mechanical Equipment and Systems

    The station has a canal that leads from the headgate house to a forebay that serves the five penstocks. Three of the penstocks are for the three main turbines. The fourth penstock was provided to serve two exciter units. The fifth penstock was provided to serve a fourth main turbine, which was never installed.

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    The outboard wall of the canal was breached about 10 years ago when a lightning storm tripped the generating units and the power to the headgates. With the headgates open and an upstream water level that is 10 ft higher than the normal canal water level, the canal wall was overtopped and a 300 ft section was washed out midway between the headgate structure and the powerhouse. The canal wall has since been repaired with a substantial concrete section. The electrical system was revised to ensure closure of the headgates in case of another power failure.

    The powerhouse has three double-runner horizontal shaft Francis type turbine-generator units. This type of turbine was in wide use in the early years of this century. They are typically of very rugged construction and there are many of these turbines in service today. The motive for replacement is generally the potential for increased capacity and efficiency with a modern design, rather than equipment failure. The original construction included a bay for a fourth unit, which was never installed. The powerhouse crane was recently upgraded.

    Two units were operating at about 3 MW each at the time of the site visit, and both units appeared to be operating smoothly. Unit 2 was at 58% gate and Unit 3 was at 69% gate. The difference in gate opening was attributed to possible differences between the two units. This difference of over 10% gate opening for the same power on "identical" units suggests the possibility of poor efficiency on one or both units, with the potential for improvement through an upgrade. These are the original runners and shafts.

    A program is in place to provide for semi-automation at this station by the end of 2001. With semi-automation, the units will be started manually and then controlled remotely. There will remain a need to manually remove ice from the canal whenever the units are started after a sufficiently long shutdown in cold weather.

Dam Safety and Stability

    The Falls Village project is licensed by the FERC, with the most recent FERC annual inspection performed in September 1998. Based upon observations during the inspection, the FERC inspector found the project in good condition with no findings related to dam safety or operation and maintenance that would require follow-up action.

    The dam is classified as having a significant hazard potential, with the canal classified as a low hazard potential. The project is exempted from the requirement to perform and file a Five-Year Safety Inspection Report. The Licensee submitted a report in 1992 concluding that the project's stability and spillway capacity were adequate. This report was approved by the FERC in 1994.

4.1.1.2 Electrical Equipment and Systems

    Much of the generation and electrical equipment is reported to be original. Some of the equipment has been rebuilt and some of the original equipment has been replaced with modern equipment. Considering the age of the station it appeared to be reasonably well maintained and in generally good condition.

    The station configuration consists of three 3750 kVA generators that parallel through 15 kV 1200 amp circuit breakers and a bus disconnect switch to a 6600 V bus. The 6600 V bus is divided into a North and South section with a disconnect switch between the two sections. Generators 1 and 2 feed the North section and generator 3 the South. The North and South sections also each connect through circuit breakers to step-up transformers rated at 7500 kVA each which convert the bus voltage of 6.6 kV to 66 kV and feed the switchyard. There is an another transformer, rated at 500 kVA fed off a North bus circuit breaker that supplies power at 480 V to the unit 1, 2 and 3 exciters as well as some house loads. The 480 V bus also has a 60 kVA generator as an emergency supply.

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Generators

    The station has three horizontally mounted open frame Allis Chalmers generators rated at 3750 kVA, 6.6 kV, 0.8 PF and 300 rpm each. A static exciter excites the generators. This exciter is a new machine, which replaced the original hydraulic turbine driven exciters. Installation and testing data indicate that the new static exciters were installed in 1998. At that time new generator panels and new protective relays were also installed. The generators are reported to be original. The operators of the Housatonic River system reported that they are inspecting the generators on a two-year cycle. Station personnel reported that all the generators have been rewound. Outage reports for the units indicate that Unit 1 and Unit 2 generator stators were rewound in 1987, and Unit 3 stator in 1988. During the unit outages the generator field, lightning arresters, PT's and switchgear were tested. The generator cables on Units 2 and 3 were tested, found to be bad, and were replaced. On Units 1 and 3 similar tests were done on the generators and components. On Unit 1 the generator cables tested acceptable and were not changed. These are the original cables. In 1992 the original governors were replaced with Sorensen actuators on all three units. In 1996 the generators' potential transformers were replaced with a new GE type. The generators showed no obvious indication of damage or deterioration. At the time of the site visit one of the generators was operating. The generator appeared to be running smoothly and no unusual noise or vibration was observed. The operators indicated that generator operation had been trouble free in the recent past. The working space adjacent to the generators is sufficient to permit any expected maintenance activities and equipment replacement when required. The generators are old and the manufacturer is no longer active in this market. Replacement parts will be problematic.

    The basic design and construction of the generators appears to be conservative and it may be possible to redesign the generator windings to increase the capacity of the generator, depending on the capability of the runner and water supply. The generator cables on Unit 1 should be replaced.

Medium-voltage switchgear

    The original generator output circuit breakers were removed and replaced with modern metal clad vacuum breakers installed in the existing individual concrete cubicles about 20 years ago. There were no reported problems with the circuit breakers.

Generator step-up transformers

    The generator output transformers are Allis Chalmers, 2,500 kVA single-phase water-cooled and possibly the original transformers. Visual inspection was very difficult and limited. The transformers are installed in enclosed transformer cubicles inside of the station and there is little extra room inside the enclosure. There is no bus duct so the busses of the transformers are exposed. The front panel of the enclosure can be removed. Transformer mounting is on steel rails to permit withdrawal from the cubicle enclosure. The manufacturer of the transformer is no longer active in this market, and repair services may be problematic. Maintenance records through 1989 indicate that the six single-phase transformers had received the standard Doble insulation tests that included power factor, turns ratio and meggering. In 1996 the step-up transformers' low side (6.6 kV) potential transformers were replaced with new GE types.

    There were no obvious oil leaks and only minor corrosion noticed. The PCB content of the oil is placarded as less than 50 ppm. A transformer closed-loop cooling system is budgeted for installation in 2001 to prevent oil leaks to the river.

Controls

    The instrument and control systems are a mix of the original Thompson-GE instruments and control devices along with newer instrument and control devices. Several of the panel boards are the original two-inch thick slate panel boards; this is typical of many of the Housatonic Hydro System

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stations. Panel wiring has been incrementally upgraded as instrument and control systems have been modernized but there is still old wiring in the panel boards. The insulation on this wiring is probably brittle and will tolerate little manipulation without cracking and spalling. Such wiring must be replaced when making changes to these circuits, which will make rewiring and modification work more difficult. Some of the panel board wiring may contain asbestos insulation.

    The station has been upgraded with some digital instruments. Modifications are underway, including installation of a SCADA system, which will allow the station to be operated semi automatically. Operational data is digitally telemetered via telephone line to the Rocky River Operations Center and dispatch information is provided by the networked computer system. Station personnel indicate that the control system operation is satisfactory. Further upgrades of the control system will require significant work in the panel boards as the old instruments will not easily adapt, or will not adapt at all, to digital signal processing and control instruments.

    Additional observations, consistent through many of the System stations, include:

    With regard to electrical equipment and systems, the Falls Village station is 85 years old and appears to be operating acceptably. The original design of the equipment was conservative and robust.

4.1.1.3 Performance

    Falls Village has three units and a total capacity of 11.0 MW. During the high river flows in the spring months it is operated as a run-of-river plant. At other times it is dispatched on a daily basis when a portion of the river flow is stored during off peak then released at peak periods. It has had a consistently good availability, typically in the upper 90's, as shown in Figure 4-1.

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Figure 4-1

     LOGO

    Figure 4-2 shows the historical capacity factor as determined from monthly generation data. The indicated capacity factor of about 40% is typical of run-of-river hydroelectric stations.


Figure 4-2

     LOGO

    The projected capacity factor of 42.4%, as determined by the Market Consultant, is consistent with historical performance, and considered achievable over the projected economic life.

    On December 4, 2000, S&W Consultants had a discussion with Mr. Robert Gates of NGC concerning the conditions stipulated in the new WQC issued by the State of Connecticut. When the new license to operate is issued by the FERC, the FERC license will incorporate by reference the conditions of the state issued WQC. One of the WQC conditions requires the Falls Village and Bulls Bridge developments to operate in a run-of-the-river condition. This provision eliminates the current practice of daily and weekend pooling of water to refill the impoundment and requires that outflow below each of these two developments equal inflow to each of the respective the impoundments on an instantaneous basis. Mr. Gates reports that prior to 1999, NU expected to lose about $80,000/year in revenue if required to operate in this mode. Based on current operating restrictions related to both voluntary and FERC commitments for recreation and fisheries enhancements, Mr. Gates does not believe the project revenues will be affected significantly. Although there will be a shift of some generation from on-peak to off-peak periods, the amount of generation affected during periods of high value (summertime extreme peak periods) is small. This is due to two factors: a) the current operable volume of storage is very limited; and b) the time when peak loads occur normally coincides with extreme temperatures, times when the river's flow is limited. Therefore the revenue statements made in section 8.1 of this report are still considered an accurate representation of future operating revenues for this development.

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4.1.2 Bulls Bridge

    The 8.4 MW conventional hydroelectric Bulls Bridge Station dams, reservoir and canal intake gates are located in Kent, CT, but the powerhouse and its intake structure are located in New Milford, CT. Bulls Bridge has a drainage area of 784 square miles, and consists of an impoundment created by two dams, a canal overflow and intake structure leading to an 8,300 foot long power canal, a powerhouse intake and trashrack structure, two steel penstocks and a powerhouse. The station was constructed in 1903.

4.1.2.1 Civil and Mechanical Equipment and Systems

    Bulls Bridge has an 8300-ft long power canal. This is a much longer canal than at Falls Village. The reservoir is formed by two dams, one on each side of Bulls Bridge Island. The Spooner Dam is on the right-bank side and the Bulls Bridge Dam is on the left-bank side. At the time of the site visit, there was no spillage at the Spooner Dam but at the Bulls Bridge Dam the bypass flow was being released to the riverbed through a sluicegate. The headgate structure that feeds the canal is at the Bulls Bridge Dam. It was stated by station personnel that there had never been any overtopping of the canal walls and that the stability of these walls had been verified.

    At the end of the canal, the forebay has intakes for two riveted steel penstocks, each of which serves three turbines through a system of manifolds and branch pipes. Each penstock also has one vertical surge pipe that is stabilized by guy wires attached to the top of the pipe. There is one surge pipe at each of the two downstream corners of the powerhouse. This piping system appeared to be in fair condition. There have been no failures in this piping system, and wall thickness measurements have been made but were inconclusive. The age of this manifold system and surge pipe arrangement, combined with its multiple section changes and multiple direction changes, presents a challenging situation for continuing inspection and maintenance.

    The powerhouse has six double-runner horizontal shaft Francis type turbine-generator units. Station personnel explained that the original turbine runners were in place but that Units 1 and 5 had required remedial work due to problems with their shafts. At the time of the site visit, Units 1 through 4 were generating at about 1.1 MW each, Unit 5 was out of service for maintenance and Unit 6 was shut down. The four operating units appeared to be operating smoothly and all had the same gate opening, within 3 per cent. There was considerable aeration in the flow that was entering the tailrace.

    The powerhouse crane has been upgraded.

Dam Safety and Stability

    The most recent annual FERC inspection was performed in September 1998 and the developments were found to be in good condition with no safety issues noted. The operations were considered by the inspector to be efficient and diligent and the project was found to be in compliance with its license.

    The most recent Safety Inspection by an Independent Consultant was performed in July 1998. The Bulls Bridge and Spooner Dams and the canal spillway were being overtopped by high flows during the inspection and the condition could not be assessed. There were no disturbances in the flow to indicate any serious deterioration or concern for the underlying structures. The canal was in fair condition and the remaining structures appeared to be in good condition.

    Monitoring at Bulls Bridge includes a number of weirs and a discharge pipe to monitor canal leakage. The Independent Consultant recommends that monitoring of one weir and the discharge pipe be discontinued because they are either dry or not representative of the leakage. The Independent Consultant found the development's stability and spillway capacity to be adequate.

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4.1.2.2 Electrical Equipment and Systems

    The station went into service on or about 1904. Much of the generation and electrical equipment is reported to be original. Some of the equipment has been rebuilt. A new onsite emergency diesel generator has recently been installed. Considering the age of the station it appeared to be reasonably well maintained and in generally good condition.

    The station configuration consists of two sets of three 1500 kVA generators that parallel through circuit breakers and disconnect switches to a 1150 V bus. One set of the three generators feeds the North bus and the other the South bus. Connected directly off each of the two busses are 4000 kVA step-up transformers that convert the 1150 V-bus voltage to 27.6 kV. After the transformers, the lines pass through phase reactors. The lines are then tied together to form one line to supply the substation.

Generators

    The station has six horizontally mounted open frame General Electric generators rated at 1500 kVA, 1150 V, 0.8 PF, 400 rpm each. The generators are self-excited by belt driven exciters. The equipment is reported to be original. The operators of the Housatonic River system reported that they are inspecting the generators on a two-year cycle. All of the generators have been rewound, the oldest being in 1949 and the most recent in 1985. There was no obvious indication of damage or deterioration. The maintenance and inspection reports indicate that Unit 1 was inspected and tested in 1994, Unit 2 in 1995, Unit 3 in 1996, Unit 4 in 1996, Unit 5 field was rewound in 1994, and Unit 6 was inspected and tested in 1997. During generator inspection and testing, the voltmeters, ammeters, and wattmeters are calibrated. At the time of the site visit several of the generators were operating. The generators appeared to be running smoothly and no unusual noise or vibration was observed. The operators indicated that generator operation had been trouble free in the recent past. The working space adjacent to the generators is sufficient to permit any expected maintenance activities and equipment replacement when required. Considering the age of the oldest rewind it would probably be wise to set aside funding for a rewinding project in the not too distant future. Due to the age of these generators finding replacement parts may be problematic.

    The basic design and construction of the generators appears to be conservative and it may be possible to redesign the generator windings to increase the capacity of the generator, depending on the capability of the runner and water supply.

Medium-voltage switchgear

    The generator output circuit breakers are oil quenched devices and are thought to be the original GE supplied devices. They are obsolete and replacement parts are problematic. There were no reported operational problems with the circuit breakers. The circuit breakers are not installed in cubicles and are fully exposed. The 1,100-volt bus work connected to the circuit breakers is exposed. There was evidence of oil leakage from each of the quench tanks and indications of past oil leaks on the floor. A drip pan was beneath each breaker. Access for close inspection was necessarily limited due to the exposed electrical bus work. At the time of each unit generator's inspection and testing, the generator circuit breakers were tested for contact resistance, operating time and Doble. The PCB content of the oil is placarded as less than 50 ppm.

Generator step-up transformers

    The generator output transformers have been replaced within the last 15 years with modern, dry type 3 phase, 1.15 kV/27.6 kV, 4000 kVA transformers supplied by ABB. The transformers are installed in the original transformer bay inside of the station. There is adequate room to work around the transformers but space is not generous. Access to the transformers was somewhat limited and visual

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inspection was limited. There is no bus duct so the buss of the transformers are exposed. Maintenance reports indicate that these two transformers had been tested in 1991 and 1996. The testing included Doble, insulation, turns ratio, temperature gauge calibration. The high and low side cables and bus, and lightning arresters were also tested. Maintenance was performed where required.

Controls

    The instrument and control systems are a mix of the original Thompson-GE instruments and control devices along with newer instrument and control devices. The station has been upgraded with some digital instruments and a SCADA system for remote control and monitoring of a number of parameters. Operational data is digitally telemetered via telephone line to Rocky River Operations center and dispatch information provided by the networked computer system. This allows the station to operate in a semi-automated mode. Plant personnel indicate that the control system operation is satisfactory. Further upgrades of the control system will require significant work in the panel boards as the old instruments will not easily adapt, or will not adapt at all, to digital signal processing and control instruments.

    Additional station-specific observations include:

    The Bulls Bridge station electrical equipment and systems appear to be operating acceptably. The original design of the equipment was conservative and robust.

4.1.2.3 Performance

    Bulls Bridge has six units with a total generating capacity of 8.4 MW. The units are typically operated in a pond and release method twice daily. The impoundment is small so operation of the

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units is tied closely to the river flows. Figure 4-3 shows the average equivalent availability factor, which is variable and reasonable given the age of the station.


Figure 4-3

     LOGO

    Figure 4-4 shows the historical capacity factor as determined from monthly generation data. The indicated capacity factor average, approaching 60%, is high for a run-of-river hydroelectric station.


Figure 4-4

     LOGO

    The projected capacity factor of 61%, as determined by the Market Consultant, is consistent with historical performance, and considered achievable over the projected economic life.

    As with the Falls Village facility, the Bulls Bridge development will operate in a run-of-the-river condition after FERC issues a new license. This provision eliminates the current practice of daily pooling of water and coordination of operation with Falls Village. As discussed in Section 4.1.1, Mr. Gates does not believe the project revenues will be affected by the new WQC. Although there will be a shift of some generation from on peak to off-peak periods, NGC can still bid in the desired markets and actual operating experience in the last year shows that the revenue per MWHr is actually much higher than had been anticipated in 1999. Therefore the revenue statements made in section 8.1

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of this report is still considered an accurate representation of future operating revenues for this development.

4.1.3 Rocky River

    The 29.9 MW pumped storage Rocky River Station, which was constructed in 1929, consists of an upper reservoir (Candlewood Lake) with one dam and five dikes, an intake canal and intake structure, a penstock and powerhouse. Candlewood Lake lies within the boundaries of several western CT towns, including Sherman, New Milford, Brookfield, Danbury and New Fairfield. The Station is one of the earliest known pumped storage applications and the first such development in the USA. This pioneering achievement is noted in the commemorative plaques located on the wall just inside the powerhouse door. Pumped storage at this station is primarily a seasonal operation. All of the CL&P hydro stations on the Housatonic River are controlled or monitored from Rocky River.

4.1.3.1 Civil and Mechanical Equipment and Systems

    In the intake canal, immediately above the powerhouse, there is a tower intake that feeds a concrete penstock section leading to a woodstave penstock that is in turn connected to the bottom of a surge tank. These structures are located on the hill above the powerhouse. The woodstave penstock was viewed from a point near the intake area and it was noted that there were a few small leaks. This penstock was replaced in 1965. There are regular inspections and the bands are adjusted when needed, the most recent tightening having been done two to three years ago.

    Looking up from the powerhouse area the riveted steel surge tank and the riveted steel penstock appeared to be in good condition. An old aerial photograph in the powerhouse showed a branch pipe stub, with a plug, immediately downstream from the surge tank. The Iroquois gas pipeline passes underneath the penstock.

    The powerhouse contains one conventional vertical shaft Francis turbine-generator unit and two small vertical shaft Francis pump-turbine/generator-motor units. There were no Rocky River units running at the time of the site visit but several interesting features were noted. For example, the conventional turbine has a ring gate located just outboard of the wicket gates. This ring gate performs the same function as a conventional inlet valve but it allows the spiral case to remain pressurized when the turbine is shut down. Constant pressurization avoids the repeated stress cycling that takes place with frequent starting and stopping of the turbines. Ring gates have been known to have operating and maintenance difficulties at other stations with larger turbines. It is understood, however, that the ring gate on the Rocky River turbine has not been a source of difficulty.

    The pumped storage operation is performed on a seasonal basis. Pumping is performed during floods, with excess water that would otherwise be spilled at Shepaug and other stations downstream. This water is returned to the Housatonic River later in the season, when it can be used at the downstream stations. The Rocky River powerhouse is located at the upstream end of the reservoir that is formed by Shepaug Dam. At this location, the river is so shallow that pumping would be impractical except during periods of high flow.

    The pump-turbines are started in the pump mode using an induction motor and a tailwater depression air system. Manual intervention is required to establish cooling water and to activate other auxiliary systems. There is a starting breaker and a run breaker for each pump-turbine unit.

    Candlewood Lake, the upper reservoir, was built as part of the power supply facility but as the years have passed has become very much a community enterprise. There is such an abundance of real estate and recreational activity taking place along the shores of this lake that CL&P has followed an operating policy designed to be in harmony with this environment. For example, CL&P has historically performed a deep drawdown of the lake to El 419 during the winter of every second year. This

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drawdown is intended to kill milfoil weed along the shore, by freezing the roots. During alternate winters, the lake is lowered to a shallow drawdown level of El 424 Ft. That drawdown is intended to prevent ice damage to shorefront property, boat ramps and other vulnerable structures. It was explained that the present practice for regulating the drawdown was flexible but that future operation would be governed by the restrictions to be established in the ongoing FERC relicensing process. On August 3, 1999 CL&P committed to an "Approval of Conveyance on Conservation Restrictions" on the operation of the Rocky River impoundment. The new Agreement limits the summer drawdown to 418 feet and the maximum reservoir elevation to 440 feet at all times.

Dam Safety and Stability

    The most recent annual FERC inspection was performed in September 1998 and the developments were found to be in good condition with no safety issues noted. The operations were considered by the inspector to be efficient and diligent and the project to be in compliance with its license.

    The most recent Safety Inspection by an Independent Consultant was performed in July 1998. The Independent Consultant's inspection of the Rocky River development found the structures to be in good to very good condition. A small sinkhole was found in the crest of the Main Dam. The sinkhole was investigated and repaired in a manner acceptable to the Consultant. FERC also requested that the sinkhole area be monitored for changes weekly until the next Five-Year safety inspection is performed. A report on the results of the investigation was submitted to the FERC on December 30, 1998. No other conditions requiring immediate repair or further investigation were reported. However, upon review of the reports' assumptions as to the material used to originally form the Danbury Dike, FERC requested core samples to verify the assumptions and confirm the dike's integrity. These core samples indicate the dike's construction is consistent with that which was originally assumed, and no further action, other than routine monitoring, is required.

    Monitoring at Rocky River includes a number of piezometers, weirs, monuments and alarms to monitor movement and seepage in the dams and dikes around the upper reservoir. The most recent data shows no significant movement in the embankments. The Independent Consultant found the development's stability and spillway capacity to be adequate.

4.1.3.2 Electrical Equipment and Systems

    The Rocky River station serves as central control and monitoring station for the Housatonic River System generation and hydraulic dispatch operations. Most of the generation and electrical equipment is reported to be original. Some of the equipment has been rebuilt. The station appeared to be reasonably well maintained and in generally good condition.

    The station configuration consists of a 30 MVA generator that feeds through a circuit breaker to a 13.8 kV switchyard. Additionally, there are two motor/generators that either provides power through a circuit breaker to a 13.8 kV run bus, or are supplied power at 6.9 kV through a circuit breaker on a start-up bus. Station auxiliary loads are provided through a 500 kVA-transformer fed from offsite.

Generators

    The station has two vertically mounted reversible General Electric generator/synchronous motor machines rated at 7900 kVA/8100 Hp, 13.2 kV, 327 rpm each and a single vertically mounted General Electric self excited generator rated at 30 MVA, 13.8 kV, 0.8 PF, 200 rpm. The equipment is reported to be original. The operators of the Housatonic River system reported that they are inspecting the generators on a two-year cycle. The generator and motor/generators were all rewound in 1982 following a flooding incident. Unit 1 motor/generator rotor was sent out to GE in 1990 for a cleaning, shaft work and balancing. In 1995, it received standard testing on the stator and field, as well as on the isolator-

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reversing switch. A major overhaul was done on Unit 2 M/G in 1990. In 1995 it also received standard testing on the stator and field as well as on the isolator-reversing switch, as did Unit 1. New Westinghouse static exciters were installed on both units in 1995. Unit 3 generator was tested in 1994 and new surge capacitors were installed at that time. The Unit 3 generator breaker was replaced in 1993. In 1997, the generator cables were tested and found to be in good condition. The operators indicated that generator operation had been trouble free in the recent past. There was no obvious indication of damage or deterioration. The working space adjacent to the generators is sufficient to permit any expected maintenance activities and equipment replacement when required. Due to the age of these generators finding replacement parts may be problematic.

Medium-voltage switchgear

    The motor/generator starting and output circuit breakers and the generator output circuit breakers are GE Magnablast 13.8 kV Air quenched CBs, which have been re-built by ABB. The rebuilding was reported as being completed within the last 10 years.

Station Service Transformer

    The station service transformer is a Westinghouse two winding transformer installed in 1993 to replace the original three single-phase units. At the time of the installation, new high voltage and low voltage cables were also installed. The PCB content of the oil is placarded as less than 50 PPM. There is adequate room to work around the transformers. There is no bus duct so the busses of the transformers are exposed.

Controls

    Rocky River is the control center for the Connecticut Hydro Plants. Staff at the station are responsible for river flow forecasting, daily dispatching, emergency action plan duties, supervision of all operators along the river, and flood plan implementation. The station operators use computerized facilities to monitor the Housatonic and Eastern Hydro Systems remotely. Rocky River Station operators can remotely start and stop the Shepaug and Stevenson station units and operate canal headgates at Bulls Bridge, in addition to their responsibilities as the primary operators of the Rocky River units.

    Additional station-specific observations include:

    With regard to electrical equipment and systems, the Rocky River station is 70 years old and appears to be operating acceptably. The original design of the equipment was conservative and robust.

4.1.3.3 Performance

    This is a pumped storage facility with significant pumping restrictions. Since the river is shallow at this location pumping cannot be done on a daily basis. Pumping occurs during times of high river flow.

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Figure 4-5 shows the recent historical Rocky River availability, which has been consistently high since 1992, averaging in the mid to upper nineties.


Figure 4-5

     LOGO

    Figure 4-6 shows the recent historical capacity factor as determined from monthly generation data. These low capacity factors appear to be due to low natural inflow to Candlewood Lake, relative to the installed capacity at Rocky River. However, due to the storage capacity in the upper reservoir, the timing of the achievable output can be somewhat more predictable than on the run-of-river stations.


Figure 4-6

     LOGO

    The projected capacity factor of 6%, as determined by the Market Consultant, is consistent with historical performance, and considered achievable over the projected economic life.

    On December 4, 2000, S&W Consultants had a discussion with Mr. Robert Gates of NGC on the conditions stipulated in the new WQC issued by the State of Connecticut. When the new license to operate is issued by the FERC, the two upstream projects will operate in a run-of-the-river condition and the Rocky River project will not pump unless the river stage at the intake is at least 196.4 feet NGVD. NGC had proposed to limit pump withdrawals to periods when the river flow exceeded 498 cfs. The run-of-river operation means that the pulse of daily flow from Falls Village peaking operation will

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not arrive in the off peak pumping time as current operation allows. Although this source of pump water is not available, Mr. Gates does not believe the project operation will be affected to any great extent. This is due to the fact that, under current operations, the frequency of time that the tailwater is at or below 196.4 feet NGVD is very small. Current pumping operations are essentially limited by low river flows, therefore, the incremental loss of pumping capability is considered to be negligible. Most of the pumping takes place in the spring or during natural high flow periods. If necessary, the operation of Shepaug can be curtailed to pond enough water to raise the impoundment elevation to 196.4 feet NGVD and permit pump operation. Although there will be less flexibility in operation, the revenue statements made in section 8.1 of this report are still considered an accurate representation of future operating revenues for this development.

4.1.4 Shepaug

    Shepaug Station is a 43.4 MW conventional hydro facility located in the towns of Bridgewater, Brookfield, New Milford, Newtown, Roxbury and Southbury, CT. It was constructed in 1955 and consists of a dam, a penstock that is integral to the dam, and a powerhouse. The dam creates the reservoir known as Lake Lillinonah.

4.1.4.1 Civil and Mechanical Equipment and Systems

    The reservoir was formed by a concrete gravity dam that includes an integral powerhouse. Considerable leaching was noted on the concrete surfaces and there were stalactites growing down in the galleries. These effects indicate limited leakage of water through the concrete structure. More extensive leakage would produce a clear stream. No evidence of significant cracking was noted. It was explained that post-tensioned anchors had been installed to increase the stability of the dam. The effect of these anchors might also have been to close the cracks such that the leaching effect might eventually fill the voids and stop the leakage.

    The dam has five Tainter gates, three of which can be operated from Rocky River. Surveillance cameras are provided for observation from Rocky River. The video images were observed during the Rocky River site visit.

    The original turbine was of the Kaplan type, which has adjustable runner blades as well as adjustable wicket gates. This turbine was replaced in 1984, when one of the runner blades broke off. The replacement turbine is a fixed blade propeller turbine. On a Kaplan turbine, the runner blade angle and the wicket gate opening can both be adjusted to achieve an optimum efficiency for any given combination of water flow and head. With the runner blades set at a fixed angle, the only adjustment is with the wicket gates. The given runner blade angle will still produce optimum efficiency at the one condition of wicket gate opening and head for which that blade angle represents the optimum condition. Efficiency will drop sharply as the flow and head move away from this optimum operating point. This effect is much more pronounced on a propeller turbine than on a Francis turbine, which also has fixed blades. There are two issues associated with this tendency for sharp decrease in efficiency—a potential for a limitation in output and a potential for rough operation if the intended operating point is noticeably distant from the point of peak efficiency. Clearly, these two issues are interrelated, as discussed below.

    During the site visit, the operation of the Shepaug unit was observed at an output of 34.8 MW, with a wicket gate opening of 61.2%. The gate limit was at 87.3%. Operation appeared to be smooth as viewed from the turbine pit. At the draft tube mandoor, the sound was like a drumbeat of small stones, crackling and heavy rain. This was not very loud and there were no "hits". There was, however, a steady beat that was timed repeatedly at about 0.2 times rotational speed. This beat could be indicative of a rotating vortex in the draft tube. The observed operation suggests that the operation could deteriorate at higher output.

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    The old nameplate, for the Kaplan turbine, indicates a turbine output of 57,000 hp (42.5 MW at the turbine shaft). The new nameplate, for the fixed blade turbine, indicates a maximum output of 62,800 hp (46.8 MW at the turbine shaft). It was explained that the actual capacity with the old turbine had been 47 MW at the delivery point. The present claimed capacity of 43.4 MW indicates that a derating has already been accounted for, with respect to the old capacity and with respect to the new nameplate. There remains a question concerning the smoothness of operation at the stated capacity but station personnel have explained that there has been no cracking in this turbine runner and minimal cavitation repair. A major overhaul will occur in late 2001 in order to replace the wicket gates that are causing vibration.

    Station personnel explained that there was a dissolved oxygen (DO) deficiency in the turbine discharge water because this water is drawn from the bottom of the reservoir. This issue has been addressed in the past by operating one of the Tainter gates but is intended to be addressed in the future by an oxygen injection system. This change should reduce the amount of energy lost due to spillage of water through the Tainter gate.

Dam Safety and Stability

    The most recent annual FERC inspection was performed in September 1998 and the developments were found to be in good condition with no safety issues noted. The operations were considered by the inspector to be efficient and diligent and the project to be in compliance with its license.

    The most recent Safety Inspection by an Independent Consultant was performed in July 1998. The Independent Consultant's inspection of the Shepaug development found the structures to be in very good condition. No conditions requiring immediate repair or further investigation were reported. Monitoring at Shepaug includes piezometers and extensometers associated with the installation of rock anchors. Though the creep rate is noted to be higher than expected, the Independent Consultant feels that the residual load at the end of the anchor's life will be greater than the original design load. The Independent Consultant recommends continuation of the monitoring for the next five years.

    The Independent Consultant found the development's stability and spillway capacity to be adequate.

4.1.4.2 Electrical Equipment and Systems

    The station went into service in 1955. Most of the generation and electrical equipment is reported to be original. Some of the equipment has been rebuilt. A new output circuit breaker has recently been installed. The station was designed and built for automatic and unattended operation. The station appeared to be reasonably well maintained and in generally good condition.

    The Shepaug Station configuration consists of a single 43.75 MVA generator connected by a generator circuit breaker to 3 single-phase 16,667 kVA step-up transformers. The transformers convert the generator voltage of 13.8 kV to 69 kV. The transformers' secondary is connected through a circuit breaker to a 69 kV bus. Off the 69 kV bus a switch connects to a 500 kVA-station service transformer that converts the voltage to 480 V, to supply a Station Service Control Center. The 480 V Station Service Control Center has an alternate source of power, which is a gasoline engine driven 125 kW generator. Also, off the 69 kV bus, lines go out to supply a 13.8 kV substation through a breaker transformer combination. Additionally, there is a supply to a 115 kV line through another transformer.

Generators

    The station has a single vertically mounted self-excited Allis Chalmers generator rated at 43.75 MVA, 138.5 rpm, 13.8 kV and .85 PF. The generator is reported to be original. Two shorted windings are known to exist. The operators of the Housatonic River system reported that they are inspecting the

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generators on a two-year cycle. The generator has never been rewound. The generator and exciter were tested in a November 1995 outage. At that time it was recommended that the field and exciter receive a thorough cleaning. The generator field-testing included pole balance, AC impedance and DC resistance. The generator stator testing included Doble, DC resistance, polarization index, and slot discharge. A generator circuit-grounding problem occurred in October 1996. This was repaired and the remaining stator coils were tested. There was no obvious indication of damage or deterioration. NGC plans to rewind the generator during the scheduled 2001 overhaul. At the time of the site visit the generator was operating. The generator appeared to be running smoothly and no unusual noise or vibration was observed. The operators indicated that generator operation had been trouble free in the recent past. The working space adjacent to the generator is sufficient to permit any expected maintenance activities and equipment replacement when required. The manufacturer of the generator is no longer active in this market and replacement parts may be problematic.

    The generator output bus duct appeared to be in good condition. Some of the cabinets containing the instruments monitoring the output bus are placarded as containing PCB contaminated components. Site personnel reported that these cabinets contained the potential transformers, current transformers and some smaller capacitors that probably had PCB bearing oil in them. There is a program in place to remove and replace these components but it had not yet been completed.

Low and Medium-voltage switchgear (600V to 15kV)

    The generator output circuit breaker is an ABB dry type magnetic quenched breaker installed about four years ago. There were no reported operational problems with the circuit breaker and the operations personnel are very satisfied with it.

Main Transformer

    The main transformer consists of 3 single-phase transformers rated at 16667 kVA each. GE manufactured these transformers in about 1945. An oil change was made on the transformers in November 1993 at which time they were given a Doble and excitation test. At this time the oil from each transformer was tested for dielectric and color. Tests also included the high and low voltage bushings. In October 1995 the transformers were given a Doble and insulation resistance test.

Station Service Transformer

    The station service transformer is oil-cooled and reported to be in good condition. The PCB content of the oil is placarded as less than 50 ppm. The transformer was Doble, insulation resistance, oil sample and low side cable resistance tested in November 1995.

Controls

    The station was designed and built for fully automatic and unattended operation. The station has been provided with a SCADA system for remote control and monitoring. The analog instrumentation is typical of the time but has been progressively updated over the years. The station has been upgraded with some digital instruments. Operational data is digitally telemetered to the Rocky River Operations center and dispatch information provided by the networked computer system. Plant personnel indicate that the control system operation is satisfactory. Additional station-specific observations include:

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    With regard to electrical equipment and systems, the Shepaug station is 44 years old and appears to be operating acceptably. The original design of the equipment was conservative and robust.

4.1.4.3 Performance

    Shepaug has one generating unit sized at 43.4 MW. This station normally operates on a weekly pond and release schedule as a function of load demand. Shepaug Unit 1 equivalent availability averaged in the mid to upper 90s in the period 1990-2000.

    Figure 4-7 shows the historical capacity factor as determined from monthly generation data. The indicated capacity factors are typical of run-of-river hydroelectric plants.


Figure 4-7

     LOGO

The projected capacity factor of 31.7%, as determined by the Market Consultant, is consistent with historical performance, and considered achievable over the projected economic life.

4.1.5 Stevenson

    Stevenson Station, which was constructed in 1919, is a 28.9 MW conventional hydro facility located in the towns of Monroe, Oxford, Newtown and Southbury, CT. It consists of a dam, four penstocks and a powerhouse. The reservoir created by the dam is called Lake Zoar.

4.1.5.1 Mechanical Equipment and Systems

    The station has a concrete dam, with four integral penstocks and a powerhouse. Station personnel explained that post-tensioned anchors had been installed 10-15 years ago to increase the stability of the dam. The dam has five Tainter gates, three of which can be operated from Rocky River. The dam is also equipped with three feet of flashboards. These flashboards were in place at the time of the site visit and were, at that time, experiencing a slight leakage, in the middle of the dam and toward the right bank.

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    Station personnel explained that CL&P was required to provide the following announcements based on the expected flow downstream from Stevenson Dam:

    One open issue at this dam is the need for replacement of the bridge that spans the river at this point. The existing bridge, which is supported on top of the dam, had very evident salt damage. CL&P owns the existing bridge, with the exception of the roadway surface. The Descriptive Memorandum states that "The Connecticut Department of Transportation is involved in siting a replacement bridge in proximity to the dam or rebuilding on top of the dam." NGC has advised that a bridge upstream from the station is in final design and will be paid for with state and federal funds.

    Stevenson has four vertical shaft Francis type turbine-generator units, three of which (Units 1, 2 and 4) were operating at the time of the site visit. These units appeared to be operating smoothly and there was considerable aeration of the water entering the tailrace. Units 1 through 3 are nominally identical but Unit 4 has a larger turbine runner and a higher capacity.

    The station has an emergency generator inside the powerhouse. This generator is fired by vapor pressure propane.

    The station crane has been upgraded, new governors were installed in the 1980's, the headgates and operators have been replaced and most of the trashrack sections have been replaced.

Dam Safety and Stability

    The most recent annual FERC inspection was performed in September 1998 and the developments were found to be in good condition with no safety issues noted. The operations were considered by the inspector to be efficient and diligent and the project to be in compliance with its license.

    The most recent safety inspection by an independent consultant was performed in July 1998. The independent consultant's inspection of the Stevenson development found the structures to be in good condition. No conditions requiring immediate repair or further investigation were reported. Monitoring at Stevenson includes piezometers associated with the installation of rock anchors. Continuation of the monitoring is considered by the Independent Consultant to be unnecessary.

    The Independent Consultant found the development's stability and spillway capacity to be adequate.

4.1.5.2 Electrical Equipment and Systems

    The station went into service on or about 1919. Much of the generation and electrical equipment is reported to be original. Some of the equipment has been rebuilt. The station is capable of fully automatic and unattended operation. Considering the age of the station it appeared to be reasonably well maintained and in generally good condition.

    The Stevenson configuration consists of four generators paralleled through generator breakers on to a 6.9 kV bus. The 6.9 kV bus has a north section, fed by generators 3 and 4, and a south section fed by generators 1 and 2. There is a disconnect switch between the north and south section busses. A unit voltage regulator is tapped off between each generator and the generator breaker. There is a disconnect switch on the north and south bus that feeds the station service transformers which convert the 6.9 kV to low voltage.

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Generators

    The station has four vertically mounted Westinghouse generators. Three of the generators are rated at 8.333 MVA each and the fourth, which was installed in 1928, is rated at 10.0 MVA. The generators are self-excited. The equipment is reported to be original. The operators of the Housatonic River system reported that they are inspecting the generators on a two-year cycle. All the generators have been rewound, the oldest being in 1949 and the most recent in 1993. There was no obvious indication of damage or deterioration. Since 1993 all generator field and stator windings have been tested on all of the units. These tests include Doble, insulation, winding resistance, PI, Hi-pot, and meggering. Where there had been poor readings, the records indicate that maintenance was performed to correct the problem. Maintenance records indicate that the generator voltage regulators have also been tested through 1994. At the time of the site visit the generators were operating. The generators appeared to be running smoothly and no unusual noise or vibration was observed. The operators indicated that generator operation had been trouble free in the recent past. The working space adjacent to the generators is sufficient to permit any expected maintenance activities and equipment replacement when required. Considering the age of the oldest rewind it would probably be wise to consider a rewinding project during a future overhaul. Due to the age of these generators finding replacement parts may be problematic.

Medium-voltage switchgear

    The generator output circuit breakers are ITE dry type magnetic quenched breakers. The switchgear is old and the manufacturer is no longer active in this market. Replacement parts will be problematic. Maintenance documentation indicates that megger testing is performed on the 6.9 kV bus, relays are calibrated and generator breakers also receive required testing, most recently in 1997. There were no reported operational problems with the circuit breakers.

Station Service Transformers

    The station service transformers are oil cooled, and reported to be in good condition. The PCB content of the oil is placarded as less than 50 ppm. In 1998 transformers 14A-1S and 2S were tested for oil analysis, Doble power factor, turn ratio, and meggered. The high and low side cable received an over potential test. As a result of the test, it was recommended that the oil power factor test be done annually.

Controls

    The analog instrumentation system has been largely modernized and upgraded with some digital instruments and a SCADA system. The station is fully automated and is frequently operated unattended. Operational data and control information is digitally telemetered to the Rocky River Operations center and dispatch information provided by the networked computer system. Plant personnel indicate that the control system operation is highly satisfactory.

    Additional station-specific observations include:

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    The Stevenson station is 80 years old and appears to be operating acceptably. The original design of the equipment was conservative and robust.

4.1.5.3 Performance

    Stevenson Station has four generating units and each has a capacity of 28.9 MW. This station normally operates on a weekly pond and release schedule as a function of load demand. Recent historical equivalent availability, shown in Figure 4-8, has been generally in the mid to upper nineties for Units 1, 2, and 4. Unit 3 availability has been somewhat lower.


Figure 4-8

     LOGO

    Figure 4-9 shows the historical capacity factor as determined from monthly generation data. The indicated capacity factors are typical of run-of-river hydroelectric plants.


Figure 4-9

     LOGO

The projected capacity factor of 40.5%, as determined by the Market Consultant, is consistent with historical performance, and considered achievable over the projected economic life.

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4.1.6 Robertsville

    Robertsville Station is a 0.62 MW conventional hydro facility situated on the Still River in the towns of Colebrook and Winchester CT, and has a drainage area of 49.5 square miles. It was built in 1914 and consists of a dam and reservoir together with a power canal, twin penstocks and a powerhouse containing two hydraulic turbines.

4.1.6.1 Civil, Mechanical and Electrical Features

    During the site visit, both units were shut down, and had been for some time, due to lack of water in the river. The water level was at the top of the flashboards but was not overflowing. The small amount of river flow was being passed through flashboard leakage—which was not much—combined with the water from an overflow point downstream from the canal headgates and a small amount of flow through a sluiceway near the turbine intakes. There was a heavy cover of green algae on the surface of the water in the intake canal. The intake serves two FRP penstocks, which appeared to be relatively new; they were installed about 8-10 years ago. The surface of the concrete at the intake structure was observed to be spalling.

    A flood in August 1955 washed away the top ten feet of masonry from the dam and this section was later restored with pre-stressed concrete. That storm is understood to have been Hurricane Carol, which resulted in extensive damage.

    The station has two vertical shaft turbine-generator units. There were no nameplates on these items. Most of the equipment inside the powerhouse was obviously very old but appeared to be adequately maintained. The turbines, generators and governors were said to be original equipment and there was a classic slate control panel. The station does, however, include a new control package for adjusting load on the unit(s) to maintain the pond level. During the site visit, the water level was 619.7 as indicated on this package and 619.6 as indicated on the staff gauge. The float controls will shut down one unit when the pond level has been drawn down by two feet and will shut down the second unit when the pond level has been drawn down by four feet. Once a unit has been shut down, it is necessary to dispatch personnel to the station when a restart is to be performed. Starting, voltage adjustment and synchronizing are completely manual in the classical fashion.

    The batteries and battery charger had been replaced about 3 to 4 years ago, and the circuit breakers were new. A Halon fire suppression system was also noted to be in place.

Dam Safety and Stability

    The most recent CT DEP inspections of the Robertsville project were performed in 1994, 1995 and 1996. The reports that were issued as a result of these inspections included a checklist of items evaluated, and identified action items required. No action items were identified during the 1994 and 1995 inspections. The action items identified during the 1996 inspection were maintenance items including repair of a floodlight and removal of debris in the vicinity of the dam, canal, and penstock. No action items related to stability or spillway adequacy were identified.

    The Robertsville Project does have an Emergency Action Plan that appears to be complete and current as of September 1998.

    During the August 1999 site visit by S&W Consultants, the project appeared to be well maintained, the security of the project appeared to be adequate, and the warning signs, fencing and boat restraining booms were in place. Attention should be given to debris removal in the vicinity of the dam.

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Electrical

    The electrical configuration at Robertsville consists of two Electric Machinery generators rated at 312 kVA each that feed out at 4600 V through their own circuit breakers and disconnect switches to a 4.6 kV bus. From the 4.6 kV, a line goes out through disconnect switches to Winsted distribution. The 4.6 kV line also supplies a 45 kVA-station service transformer that converts the voltage to 120/208 to supply house loads that included two motor generator sets used for main generator excitation.

    In 1991 Eastern Electric Co rewound the Unit 2 generator stator. Also, the Unit 2 generator and bus cables were Hi-Pot tested. Both Unit 1 and 2 generator breakers were replaced by used, 1958 Westinghouse type F124A, 600 amp, 8.25 kV circuit breakers. Unit 2 was also given a heat run test.

    Outage reports for 1992 indicate that the generator relays were calibrated and trip tested. The station relays and all panel meters were also calibrated. Unit 1 and 2 potential transformers were Doble tested. In 1993 Unit 1 generator field was meggered, given AC impedance and a DC resistance tests. The stator and stator cables were meggered.

    Data on the station transformer was not available.

4.1.6.2 Performance

    Performance data indicate high availability (100%) during the past five years. Figure 4-10 shows the historical Robertsville capacity factor as determined from monthly generation data. These capacity factors are relatively low compared to a typical run-of-river plant.


Figure 4-10

     LOGO

    The projected capacity factor of 24.7%, as determined by the Market Consultant, is somewhat higher than historical performance, but considered achievable over the projected economic life.

4.1.7 Bantam

    Bantam Station is a 0.32 MW conventional hydro facility located on the Bantam River in the town of Litchfield, CT. It has a drainage area of 39.7 square miles. The station was originally constructed in 1905. In 1971 the unit was forced to shut down due to a burned out generator. Restoration of Bantam began in March 1980 and was completed in April 1981.

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4.1.7.1 Civil, Mechanical and Electrical Features

    Bantam Station consists of a main dam, gatehouse, penstock and powerhouse. Operation is essentially run-of-river, particularly in the summer, when fluctuations could affect the trout population. At other times there is some use of float controls, to make use of the available poundage.

    This station was not operating during the site visit. Furthermore, a log book at the site indicated that there had been essentially no generation at least as far back as July 16, 1999. This appears to have been an extremely dry summer. At the dam, the water level was noticeably below the spillway crest, suggesting that the river flow was insufficient even for the leakage.

    The intake structure was observed to have three outlets that were served by manually operated rack and pinion vertical lift shutoff gates. One outlet was connected to the steel penstock that served the powerhouse. A second outlet provided a means of draining the pond and the third outlet served what was explained to be an unused penstock stub. That output was observed to be leaking slightly. The concrete surface of the structure was noted to be spalling.

    It was clear that the 1971 fire and the energy crisis of the late 1970's had presented an opportunity for restoration of the major equipment and modernization of the electrical panels and switchgear. The station has one horizontal shaft turbine-generator unit. There were no nameplates except for a bronze plaque stating the station capacity and years in service. The turbine, generator and governor were original equipment but had been restored during the 1980-1981 project. The belt-driven exciter also appeared to be original.

    The penstock sections inside the powerhouse appeared to be new. Station personnel advised that the battery equipment was 3-4 years old and that the control panel and switchgear were replaced with new equipment in the 1980-1981 project.

    The powerhouse structure was made of wood and the upper floor appeared to be very solid. The lower floor was concrete.

Dam Safety and Stability

    The most recent CT DEP inspections of the Bantam project were performed in 1994, 1995 and 1996. The reports that were issued as a result of these inspections included a checklist of items evaluated and identified action items required. No action items were identified during the 1994 and 1995 inspections. The action items identified during the 1996 inspection were maintenance items including repair of fences, tree and brush trimming, repointing of masonry, and repair of riprap on access road embankment. No action items related to stability or spillway adequacy were identified.

    The Bantam Project does have an Emergency Action Plan that appears to be complete and current as of September 1998.

    During the August 1999 site visit by S&W Consultants, the project appeared to be well maintained, the security of the project appeared to be adequate, and the warning signs, fencing and boat restraining booms were in place. Attention should be given to brush removal on the river side of the powerhouse and in the tailrace area.

Electrical

    The electrical configuration at Bantam consists of a single 475 kVA, 400 rpm generator that feeds at 2300 V through a generator circuit breaker to a 500 kVA three-phase step-up transformer. The transformer secondary provides a 8.3kV supply through a fused disconnect switch to a small station service transformer and to East Bantam.

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    The generator was rewound in 1980. The outage report for 1986 indicated that testing of the generator stator and field was performed. Testing at that time also included the main transformer, transformer cables, exciter, generator breaker, and batteries. The panel meters were calibrated, and the relays calibrated and trip tested. All components tested, with the exception of the batteries, which failed the capacity test, were found to be acceptable. At that time, it was recommended that the batteries be replaced. New station batteries were installed in 1989, and tested with good results in mid 1993. The generator was tested Again in 1991 along with the main transformer, relays, meters, and generator cables and generator breaker. The generator field and stator tested well, following a six-day heating of the windings. With the exception of the generator breaker, which showed some deterioration, all components tested well. It was recommended that the generator's field and stator be cleaned.

4.1.7.2 Performance

    Figure 4-11 shows the historical Bantam capacity factor as determined from monthly generation data. The indicated capacity factors are typical of run-of-river hydroelectric stations.


Figure 4-11

     LOGO

The projected capacity factor of 50%, as determined by the Market Consultant, is somewhat higher than historical performance, but considered achievable over the projected economic life.

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4.1.8 Remaining Life

    There are seven hydroelectric plants in this bundle, with indicated construction dates, capacities and projected remaining economic lives as follows:

Station

  Indicated
Construction
Date

  Nominal
Capacity
(MW)

  Projected
Remaining
Economic Life
(Years)

Falls Village   1913   11   40
Bulls Bridge   1903   8.4   40
Rocky River   1929   29.9   40
Stevenson   1919   28.9   40
Shepaug   1955   43.4   40
Robertsville   1914   0.62   20
Bantam   1905   0.32   20

    The oldest of these stations, Bulls Bridge, has already provided almost a century of service and should continue to operate for a long time with continued maintenance, upgrade and replacement activity. Falls Village and Stevenson are not much newer and they appear to be comparable to Bulls Bridge in anticipated economic life. All of these stations have had ongoing repairs, replacements and upgrades throughout the course of their past service. Much of the original equipment does, however, remain in service. This mature equipment, while quite serviceable, will eventually require replacement or upgrade if only because of the dwindling availability of spare parts. The stations themselves can, however, still be reasonably expected to operate satisfactorily for the projected economic lives.

    The Rocky River station is about a quarter of a century newer than Bulls Bridge and it too has original equipment and equipment that has been replaced or upgraded through the years. The projected 40 year economic life projection therefore appears reasonable for this station.

    The Shepaug station is relatively new in comparison with the other stations discussed above and it has a new turbine, as discussed in the asset description. With appropriate maintenance, the projected 40 year economic life of 40 years is considered conservative.

    Robertsville is a "mature" station, with much antique equipment. The 20-year projected economic life appears to be achievable but not particularly conservative. The equipment at Bantam station appeared to be in much better condition than that at the Robertsville station. With continued maintenance and operation at the projected capacity factors, satisfactory performance is considered achievable for 20 years.

4.2 Operations & Maintenance

    S&W Consultants reviewed historic O&M performance and cost data contained in various documents that were made available for the sale of assets. S&W Consultants also interviewed Owner personnel and reviewed station records during the site visits. The assessment of O&M projections focused largely on the Continued Unit Operation (CUO) studies prepared by NGS for NGC.

4.2.1 System Staffing Levels

    The staffing level for the Housatonic Hydro System is currently 34. The staffing level appears to be adequate for the operation of these units. The numbers are typical of those found in similarly configured stations that S&W Consultants has reviewed.

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4.2.2 Operation and Maintenance Expenses

    The historical O&M expenses are summarized below, along with NGS projected O&M expenses. The values shown are an annual average of the projected expenses from 2001 through 2039 for the units.


Housatonic Hydro System O&M Expenses
(All Values in thousands of Nominal dollars)

Period

  Historical
  NGS
1994   $ 3,677      
1995   $ 3,760      
1996   $ 3,442      
1997   $ 3,404      
1998   $ 3,974      
1999   $ 4,635      
2000   $ 4,658      
2001–2009         $ 5,570
2010–2019         $ 6,348
2020–2029         $ 8,441
2030–2039         $ 11,319

    The NGS O&M expenses between 2001–2009 are slightly more than the historical expenses, and approximately $1,000,000 higher between 2010–2019. The projected expenses are consistently comparable to the historic amounts throughout the entire 40 year period.  The increases are generally due to unit overhauls and the replacement of the Rocky River Station wood stave penstock.

    The O&M expenses generally appear to be adequate based on the staffing level, projected operating level, historical experience and level of detail provided.

4.2.3 Overhaul Schedule

    S&W Consultants reviewed NGS's planned overhaul and maintenance schedule. The Bantam and Robertsville hydro stations do not project any overhauls over the 20 year period prior to retirement. The Stevenson Units No.4 and No.1 will have overhauls and rewinds in 2003 and 2004 respectively, which have been budgeted and are considered reasonable considering the short time horizon envisioned for the current financing (i.e., less than 10 years). An overhaul and rewind will be accomplished for Shepaug in 2001. The Falls Village, Bulls Bridge, and Rocky River hydro station budget projections should be adjusted to include overhauls and rewinds for continued operation beyond the new financing horizon.

    Given the projected capacity factors, the near-term operating plan appears to be adequate assuming that maintenance planning is used effectively and that appropriate condition-monitoring programs are implemented, maintained, and updated periodically.

4.2.4 Capital and O&M Project Expense Forecast

    The capital and O&M project expense forecast provided by NGS and summarized below, was evaluated based on the condition of the Housatonic Hydro System Stations and the projected operating life of the Units.

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Housatonic Hydro System
Capital and O&M Project Expenses
(All Values in Nominal $000)

Period

  Capital
  O&M Projects
2001–2004   $ 7,946   $ 5,506
2005–2009   $ 3,588   $ 2,381
2010–2014   $ 3,657   $ 1,828
2015–2019   $ 4,202   $ 1,984
2020–2024   $ 4,802   $ 2,299
2025–2029   $ 5,567   $ 2,666
2030–2034   $ 6,454   $ 3,090
2035–2039   $ 5,896   $ 3,402
   
 
  TOTAL   $ 42,112   $ 23,155
   
 

    The major O&M and capital projects are for relicensing the Housatonic Project and Falls Village Stations. Another project is to add a dissolved oxygen system at Shepaug in 2003. Also included are various environmental compliance (including fish passage) projects. The projected capital and O&M project expenses over the next forty years of operation appear to be reasonable given the expected operation and age and condition of the stations.

4.2.5 Maintenance Management and Spare Parts

    NGS will continue to use a power plant Preventive Maintenance Management System (PMMS) to control maintenance information. NU currently uses the Passport system for spare parts and accounting. A PMMS developed by NU is fully integrated into the Passport system and its functionality is considered good.

    S&W Consultants reviewed the current summary inventory of spare parts carried for the Housatonic Hydro System Stations. The spare parts inventory appears to be sufficient and adequate to support operations and maintenance activities.

4.3 Environmental/Licensing

    FERC relicensing will combine the five Housatonic sites into a single license and the process should be completed by Spring 2002. The issuance, in August 2000, of the 401 WQC by the CT DEP relieves much uncertainty about the operating parameters and cost impact of pending FERC relicensing. The WQC specifies operating limitations and minimum flows that will likely be similar to those that the new FERC license will require. Upon the issuance of the new FERC license, project operations will change based on new license conditions and the WQC issued by the state will be incorporated by reference as a part of the FERC license. The new WQC includes a provision to alter the terms and conditions as necessary to maintain water quality standards. While there is some uncertainty remaining as to what other new conditions will be included as part of the new FERC license, from the perspective of the entire portfolio of assets (including the Eastern Hydro and Northfield Mountain Systems' assets), the impact, if any, of new license requirements should be relatively small.

    One environmental issue that potentially affects all five of the NGC facilities on the Housatonic River is the position that GE and the Connecticut Attorney General take on the "rest of the river" cleanup of PCBs. On December 27, 1999, NU sent a letter to the assistant Attorney General of Connecticut stating that PCBs in the Housatonic may adversely affect NGC operations and "creates adverse financial and operational exposures for NGC". NU specifically cites how maintenance dredging

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or construction of fish passage facilities in the future may expose PCB contaminated sediments. The U.S. Fish & Wildlife Service has already asked NGC to supply a sediment transport study to show that operations do not resuspend PCB laden sediments. NGC seeks changes in the consent decree between GE and the Connecticut AG to include provisions to allow any other party to sue for cost recovery to GE such that the GE PCBs do not impair any party's use of the river.

    At this time there is no way to quantify the possible exposure that NGC may have in the future for past PCB releases to the Housatonic at GE's Pittsfield MA facility. However, NGC's Bob Gates said that he sits on a committee newly formed by the EPA to study the "rest of the river" effects of the PCB contamination. If sufficient information is developed by the EPA committee, the Connecticut Attorney General may be able to take further action with GE. The outcome of the committee may also provide parties the data needed to pursue cost recovery through civil court or by bringing GE to the table for a more comprehensive settlement. Since there is no way to quantify the extent or cost of contamination, the effect on future operation or the obligation of GE to cover cost exposure for NGC to address PCBs in the Housatonic operation, NGC has addressed the issue as best as can be expected. By including a staff member on the EPA "rest of the river" committee the issue will be monitored in the foreseeable future. It is also possible to construct fish passage facilities without disturbing river sediments. In 1993, S&W Consultants constructed a downstream fish passage facility on the lowermost dam of the Hudson River where sediments are also contaminated with PCB's from another GE facility. Once the issue was identified, the cost of constructing the fish facility was little different from that of an uncontaminated site.

4.3.1 Falls Village

    The Environmental Consultant's reports (Phase I and II) identified some issues of potential concern regarding hazardous material contamination at the site. The issues include PCBs in oil-filled transformers and other oil containing equipment, chemical storage on site, above and below ground oil storage tanks, and the presence of an accumulation of PCB bearing sediments upstream of the dam. These issues are not expected to result in large remediation expenditures.

    Falls Village has a long penstock that diverts (or bypasses) river flow from the natural river bed. CL&P conducted instream flow studies and presented results in the draft license application. The draft license application proposes to voluntarily release a new minimum flow of 80 cfs to the bypass reach of the river, and this has been prescribed in the WQC. Any flow release to the bypass will reduce the generation of each project from currently permitted operating conditions. Minimum tailrace flow is also an issue during FERC relicensing. The CT DEP has prescribed run-of-river operation of the project. This requirement will shift capacity to more off peak generation than is identified by current generating practices upon issuance of a new FERC license.

    Because of a report of a trout kill in a warm weather weekend when the Falls Village project was not operating, NU maintains a warm weather model that predicts when the Falls Village plant should either generate or pass some minimum flows to maintain viable trout habitat below the project. This model will continue in use until a new FERC license is issued and run-of-river operation commences since run-of-river operation would control flow conditions below the project.

    Run-of-river operation, as required by the CT DEP, will eliminate impoundment fluctuations. The WQC will also require installation of gages to monitor the run-of-river operation of this development and the downstream Bulls Bridge development.

4.3.2 Bulls Bridge

    Bulls Bridge has a long canal and penstock that diverts (or bypasses) river flow from the natural river bed. The 401 WQC specifies a minimum flow to the bypass of 200 cfs or inflow, whichever is less. A large tributary stream that enters the project bypass reach complicates the details of this flow

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release. This incremental minimum flow release to the bypass, up from the current FERC license flow of 81 cfs previously proposed by NGC, will reduce the generation of this project over currently permitted operating conditions.

    The existing minimum tailrace flows of 150 cfs has been changed to run-of-river operation by the DEP WQC. Some of this flow release may be available for generation, but since the minimum flow is continuous, there will be a shift in capacity to more off peak generation than is identified by current generating practices.

    NGC also proposed, in their license application, plans to provide weekend releases of 1000 cfs on 6 weekends for 4 hours at a time. This may shift some peak capacity to off peak times but should not greatly affect annual generation. However, with the DEP's run-of-river operation imposed, the licensee will not be required to augment bypass flows with water from the impoundment. Therefore, there will be times when boating releases may not be provided. There are at least 2 years of relicensing efforts and impact assessment tasks that will be undertaken by the FERC in these 2 years.

    In a Motion to Intervene in the FERC licensing of the Housatonic River facilities, the Schaghticoke Tribal Nation cites their interest in a tribal burial ground located on land adjacent to the Bulls Bridge impoundment. The Schaghticokes claim that facility operations cause flooding to the burial ground throughout much of the year. The status of federal recognition of the tribe was still pending at the time of the January 12, 2000 Motion to Intervene. The FERC has accepted the Schaghticoke as an Intervenor in the relicensing process and has stated that the Schaghticoke will be invited to participate as a Concurring Party in the development of a Programmatic Agreement (PA) for the protection of historic resources (Personal communication with J.T. Griffin, FERC, 12/19/00). The burial ground issue was not identified in the Draft Scoping Document issued by the FERC on November 9, 2000 as an environmental issue to be addressed in the National Environmental Policy Act document they are preparing. As a concurring party to the Programmatic Agreement, however, the tribe will likely request additional studies to validate the significance of the burial ground and, perhaps, some protective measures for the resource. Given the uncertainties of this process, however, it is impossible to estimate what might be required or the cost of studies or actions that might be included in the PA.

    The water quality certificate specifies that NGC will be required to design, construct and operate an American eel upstream and downstream fish passage facility. However, the design is not required until January 31, 2021, and the installation is required by April 1, 2024. The design and construction costs for these facilities would be incurred in the last few years of the 25-year period of refinancing. The cost of this design effort should be limited since many other hydroelectric projects located on East Coast United States rivers require design and installation of up and downstream American eel passage facilities on a much earlier schedule than that recommended in the WQC for the Housatonic River. Also, a suitable standard for upstream passage is already established.

    American eel upstream passage facilities are generally less costly to construct than those designed for anadromous fish species. This is because this species can climb steep slopes with little water flow. Often, wetted bundles of fire hose or other fibrous materials are arranged at 20 to 45 degree slopes in simple flumes connecting the project tailrace and headpond. The final design of the upstream passage facilities at Bulls Bridge cannot be anticipated at this time because eel passage is a relatively new goal of the fisheries agencies and designs have been rapidly evolving based on only limited experience. In addition, the agencies could require that more than one facility be constructed. However, using the current state-of-the-art design, we estimate that an eel passage facility could cost approximately $2,000,000 in year 2000 dollars. Most of this expenditure would take place in 2022 and 2023.

    Currently, the state-of the-art design for downstream passage facilities for American eel, includes provisions for generating unit shutdown in fall season evenings under some moon other ambient light conditions. This constraint may affect the evening (generally off-peak) operation of the Bulls Bridge

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facilities for a 6 to 8 week period in the evenings in the fall. These operational costs would begin in the fall of 2024. The downstream eel passage facilities built to-date generally do not require major capital expenditures.

4.3.3 Rocky River

    The new lake level restriction identified in the August 3, 1999 Approval of Conveyance on the Conservation Restriction will not affect the capacity, pumping operations, or peaking operations. The Conservation Restriction speaks to the continuance of FERC oversight and control of operations and maintenance aspects related to Candlewood Lake, the structures, and appurtenances. The restriction reduces the permissible summer drawdown from 3 feet to 2 feet. However, the reservoir operating ranges will be no different than what have been practiced over the past 20 years (+/-). While potential changes in minimum bypass flow releases from upstream hydro projects may increase the periods when pumping operations are allowed, the 401 WQC limits pumping to periods when river elevation is above 196.4 feet NGVD (National Geodetic Vertical Datum).

    As discussed on December 4, 2000 with Robert Gates, the new elevation restriction may create some pump operating restrictions, but should not affect the seasonally available hours of operation for project generation. Even if the Bleachery Dam is breached, the Shepaug impoundment elevation can be moderated to accommodate pumping under the new elevation based operating restriction.

    Although NGC is anticipating that they will continue to financially support the Candlewood Lake Authority (CLA) for costs of patrolling the reservoir, the CLA, in a June 6, 2000 letter to the FERC seeks to have the NGC financial assessment modified from the current 1/6th of the total CLA budget to 1/3rd of the total budget. Since NGC already assumes the cost of implementing the shoreline management plan and licensing of docks and marinas on the reservoir maintained under license by the FERC, there is little obvious reason to suggest that NGC has a further financial obligation to the CLA. This issue will likely be addressed in the NEPA documentation prepared by the FERC or addressed in any settlement between NGC and the CLA.

    The Environmental Consultant's reports (Phase I and II) identified some issues of potential concern regarding hazardous material contamination at the site. The issues include PCBs in oil-filled electrical components and the closure status of a 500 gallon below ground oil storage tank. These issues are not expected to result in large remediation expenditures.

4.3.4 Shepaug

    This project currently spills 1700 cfs over the spillway when generating in the July through September period (if and when measured dissolved oxygen levels are less than the CT DEP water quality standards) in order to mitigate the low DO in the project tailrace in the summer months. This water is lost for the purposes of generation and since this is new operation voluntarily implemented by NU, the lost generation from this operation may not be reflected in the 5- year energy summaries for the project. The 401 WQC requires NGC to oxygenate the reservoir with an oxygen diffuser system in the headpond of the project within 3 years of issuance of the FERC License, and this project's capital, monitoring, and operating costs have been included in budget forecasts. The new oxygen system is expected to eliminate or reduce the need to spill water through the gates during summer generation.

    The WQC also requires that NGC develop a plan to study the effect of the oxygenation system in Shepaug and Stevenson on water quality and the effect of 4.5 foot impoundment fluctuations on the aquatic resources in the impoundment. Although the design of these studies is not completed, the major effort to demonstrate the oxygenation system effectiveness and the effect of the drawdown should be complete in the first few years and could likely be completed for $100,000 per year. Monitoring costs in subsequent years should be much less costly to complete but will be an ongoing cost incurred through the life of the project. There is no way to estimate the outcome of the DO

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enhancement system effectiveness study, and therefore no way to estimate any additional design and construction costs.

    NGC has conducted preliminary studies with agency personnel concerning fluctuating lake levels at the Shepaug and Stevenson developments that have resulted in limited interest by the agencies. While further low cost study and work is expected, Mr. Gates is confident that there is very little exposure to NGC because there are a limited amount of wetlands adjacent to the lakes impacted by level changes. There is no data, at this time, to expect an adverse outcome of further studies and therefore no reason to include any provisions for this possible outcome.

    The WQC also requires fish passage. The first fish passage required to be operational at Shepaug is an interim American eel fish passage facility. This interim facility must be in place 10 years after completion of licensing. Generally such facilities consist of simple traps that collect eels at the base of the dam. The traps are tended every couple days and any American eel are carried by hand or by truck to the headpond or to the headponds of Bulls Bridge and released. There are other methods including electrofishing that has been used on a regular basis to collect eels for transport. Any form of fish collection will require a permit from the state and periodic progress reports to document effectiveness and injury and mortality of collected fish. The labor should be limited to a few hours per week unless a boat is required to tend the traps or collect the upstream migrants.

    The WQC requires two other more permanent types fish passage to be installed. The second phase of fish passage requires design of a permanent American eel up and downstream passage facility and a permanent anadromous fish up and downstream facility. The design of these facilities must be complete by January 2021 and the facilities constructed by April 2024. This period is near the end of the refinancing period. Although the American eel upstream passage facility is generally less costly to construct, the two facilities could be incorporated in the design of a single upstream passage facility. However the upstream passage facilities (eel and anadromous fish) at Shepaug, based only on head and not on any design that creatively utilizes the existing structure or topography, could easily cost $7,000,000 in 2000 year dollars. Most of this expenditure would take place in 2022 and 2023.

    The state-of the-art for downstream passage facilities for American eel, at this time, includes provisions for generating unit shutdown in fall season evenings under some moon other ambient light conditions. This constraint may affect the evening (generally off-peak) operation of the Stevenson, Shepaug, and Bulls Bridge facilities for a 6 to 8 week period in the evenings in the fall. The downstream eel passage facilities built to date generally do not require major capital expenditures.

4.3.5 Stevenson

    In the application for relicense to FERC, NGC proposed to increase tailrace minimum flow to 80 cfs, but the 401 WQC will require 300 cfs, or inflow, whichever is less. This will likely reduce the summer generating capacity and the peak capacity

    NGC voluntarily restricts project impoundment fluctuation beyond the current FERC license limits. These operating limits have been formally incorporated in the new WQC for the project. This could reduce the effective project capacity in the low flow period. However, a December 4, 2000 discussion with Robert Gates of NGC revealed that the new impoundment fluctuation restrictions are no different than the old operating rules that Stevenson operated under for CONVEX, and therefore there are no expected changes in MWe output expected for the project.

    The WQC requires three types of fish passage to be installed in two phases. The only fish passage required to be operational at Stevenson prior to April 2014 is an interim American eel fish passage facility. In this case the interim facility must be in place in the first eel passage season after completion of licensing. As discussed above under the Shepaug section, such facilities often consist of simple traps that collect eels at the base of the dam. The traps are tended every couple days and any American eels

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are carried by hand to the headpond and released. There are other methods of interim "facilities" including a schedule of active electrofishing used on a regular basis to collect eels for upstream transport. Any interim passage facility will require a permit from the state and periodic progress reports to document effectiveness and any injury and mortality of collected fish. The labor for the interim facility should be limited to a few hours per week unless a boat is required to tend the traps or collect the upstream migrants.

    The second phase of fish passage requires design of a permanent American eel up and downstream passage facility and an anadromous fish up and downstream facility. The design of these facilities must be complete by January 2011 and the facilities constructed by April 2014. Although the American eel upstream passage facility is generally less costly to construct, the two facilities could be incorporated in the design of a single upstream passage facility. The state-of the-art design for downstream passage facilities for American eel, at this time, includes provisions for generating unit shutdown in fall season evenings under some moon or other ambient light conditions. This constraint may affect the evening (generally off-peak) operation of the Stevenson, Shepaug, and Bulls Bridge facilities for a 6 to 8 week period in the evenings in the fall. The downstream eel passage facilities built to date generally do not require major capital expenditures. However the upstream passage facilities at Stevenson, based only on head and not on any design that creatively utilizes the existing structure or topography, could easily cost $5,000,000 in year 2000 dollars. Most of this expenditure would take place in 2012 and 2013.

    The Environmental Consultant's reports (Phase I and II) identified some issues of potential concern regarding hazardous material contamination at the site. The issues include PCBs in oil-filled electrical components, an area that was formerly used to burn solid wastes, and the presence of contaminants in an area where a dual underground storage tank was abandoned in place. These issues are not expected to result in large remediation expenditures.

4.3.6 Bantam

    This site was visited on August 18, 1999. Although Bantam does not require a FERC license, it should be noted that any major upgrade or capacity addition, although not envisioned at this time, would likely trigger a requirement that the project apply for an operating license and new WQC. If this project is licensed by FERC it would be subject to periodic dam safety inspection reporting.

4.3.7 Robertsville

    This site was also visited on August 18, 1999. Although Robertsville does not require a FERC license, it should be noted that any major upgrade or capacity addition, although not envisioned at this time, would likely trigger a requirement that the project apply for an operating license and new WQC. Also, the state had scheduled a dam safety inspection at Robertsville in 1998 but never showed up. If this project is licensed by FERC it would be subject to periodic inspection reporting.

5 EASTERN HYDRO SYSTEM

    The Eastern Hydro System consists of the Scotland, Taftville, and Tunnel Stations (hydro), and the Tunnel internal combustion unit (ICU), located in Eastern Connecticut. The hydro assets represent 6 MW of capacity, and the Tunnel ICU 20.8 MW.

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    Basic data for the three hydro stations are shown in Table 5-1.


Table 5-1
Basic Data for the Eastern Hydro Stations

Plant Data

  Scotland
  Tunnel
  Taftville
FERC Project Number   2662   NA   NA
Construction Date   1909   1906(DAM)   1906
        1919(Generators)    
Operational Cycle   Daily   Daily   Daily
Total Capacity (MW)   2.2   2.1   2.0
Total Turbine Flow (cfs)   1,216   1,308   1,215
Conventional Units   1   2   5
Max Operating Pond (ft)   77.9   44.94   52.3 Canal
Nominal Tailwater (ft)   51.0   23.0   26.6
Gross Head (ft)   26.9   21.94   25.7
Drawdown            
  (ft) max   2   5 Useable   5
        3 Normal    
  (Acre-ft)   268   115 Useable   400
          77 Normal    
  Hours at Total   2.7   1.1 Useable   4.0
  Turbine Flow       0.7 Normal    

5.1 Description of Assets

5.1.1 Scotland

    Scotland Project is a 2.2 MW conventional hydro facility located on the Shetucket River in Windham, CT. The facility has a drainage area of 429 square miles and was originally constructed in 1909. Water is directed from the project reservoir to the powerhouse through an intake chamber poured integral with the powerhouse. Turbine discharge is direct to the Shetucket River.

5.1.1.1 Civil and Mechanical Equipment and Systems

    Though the original structures were constructed in 1909, the powerhouse was destroyed by the 1936 flood and a new powerhouse was constructed in 1937.

    During the site visit, it was noted that the dam and portions of the powerhouse had experienced cracking in the concrete. CL&P personnel advised that there had been a significant seepage problem at the dam and that repeated grouting had been ineffective until an epoxy grout was used. They advised that the epoxy grout had apparently solved the seepage problem. Epoxy grout was also very much in evidence as a means of addressing what appeared to be random cracking in the dam superstructure. That cracking might possibly have been caused by alkali Aggregate reactivity, which can cause expansion within the concrete. The epoxy injections appeared to have stabilized the condition.

    Cracking was also noted in the concrete of the powerhouse intake deck and in the area near the generator foundations. The cracks in the intake deck had been sealed. CL&P personnel advised that the generator foundation cracking had been confirmed to have a seasonal pattern and did not exhibit progressive movement.

    The right-bank wall was added to the dam in 1992, to address a problem of sloughing in this area. The flashboards remained in place at the time of the site visit. This station has only one generating unit, which was shut down at the time of the visit. A 36-inch bypass pipe was being used at that time to

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discharge the minimum flow to the tailrace. The valve on this pipe opens automatically whenever the generating unit shuts down. The station has no black start capability.

    The turbine-generator unit is located in the powerhouse, on the east side of the dam. Water is directed into the turbine through a short concrete box-type intake chamber that is located immediately downstream of the trash racks and intake gates. The turbine is a vertical-shaft, fixed-blade, propeller-type that is directly coupled to the generator. The turbine is rated at 2910 horsepower at 25-foot head. The equipment inside the powerhouse provides heat during the winter.

Dam Safety and Stability

    The Scotland project is licensed by the FERC, with the most recent FERC annual inspection performed in June 1998. Based upon observations during the inspection, the FERC inspector found all project structures to be in good condition with no findings related to dam safety or operation and maintenance that would require follow-up action.

    The dam was reclassified in 1996 as having a low hazard potential, and the project is exempted from the requirement to perform and file a Five-Year Safety Inspection Report. Prior to the 1996 reclassification, the Licensee submitted the Second Five-Year Safety Inspection Report which was accepted by the FERC following the implementation of remedial measures in 1995. Based on these remedial measures FERC concluded that the modified Scotland project should not present a hazard to the public and that the stability is adequate given the hazard classification of the project.

5.1.1.2 Electrical Equipment and Systems

    The generators, switchgear, transformers, high voltage circuit breakers and associated controls for Eastern Hydro System sites have been maintained, inspected and tested on a regular basis. The site locations and equipment inside were clean and well maintained.

    The unit generator at Scotland Station is rated at 2.5 MVA and connected through a circuit breaker and disconnect switch to 3 single phase 833 kVA step-up transformers that converts the generator voltage of 2.4 kV to 23 kV. The high voltage circuit breaker and a station service transformer are located in the 23 kV switchyard. The secondary of the step-up transformer supplies the 23 kV bus through a fused disconnect switch.

Generator

    It was reported that the generator had the field rewound during the past 5 years. There are yearly inspections of the generator, which presently show the generator to be in good condition. In 1996, Siemens Power Corporation reinsulated the generator field poles, and the rotor was reinstalled. At this time, the generator armature maintenance testing was also conducted.

Generator

  Unit 1
Installation   1937
Manufacturer   GE
Rated kVA   2500
Voltage (kV)   2.4
PF   0.80
Rated kW   2000
rpm   150
Exciter   Self
Control   Auto/Manual
Generator Rewind   1995
Last Major Overhaul   1986

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Transformer

    Test data on the station transformer indicates that it was last tested in 1993, and that the tests were consistent with previous test data. Testing consisted of the standard Doble test, which include bushing, meggering, and excitation current.

Controls

    A combination of controls including high and low water floats provides automatic operation of the unit when water is available. Turbine control is manually set when water is limited. Automatic station trips are high trash rack differential, governor oil press low, high winding temperature, loss of AC or DC, loss of field, and high bearing temperature. Additional station-specific observations, generally consistent among the Eastern Hydro Station, include:

5.1.1.3 Performance

    Scotland's recent historical availability has averaged in the low 90s. Performance data received for Scotland showed that the average capacity factor from 1990 through 2000 was about 40%. This is typical of run-of-river plants.

    The projected capacity factor of 41.5%, as determined by the Market Consultant, is consistent with historical performance, and considered achievable over the projected economic life.

5.1.2 Tunnel

    Tunnel Station is a 2.1 MW conventional hydro facility located on the Quinebaug River in the towns of Lisbon and Preston, CT. It has a drainage area of 745 square miles. Water is directed from the project reservoir to the powerhouse through a short concrete box-type intake chamber poured integral with the powerhouse and located immediately downstream of the trash racks and intake gates. Turbine discharge is direct to the Quinebaug River. The dam was built about 1906 to serve a compressed air plant and the two hydro generating units were added in 1919.

    The Tunnel ICU is located at the Tunnel Hydro Station. It came on line in 1969 and operates in peaking service. The Tunnel ICU has a rated capacity of 20.8 MW.

5.1.2.1 Civil and Mechanical Equipment and Systems: Hydro Station

    The flashboards were in place on the dam at the time of the site visit. The water level was about 9 inches below the top of the boards and there was a small amount of seepage through the boards. A sluiceway was noted at the bottom of the dam, near the middle of the river. The status of this

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sluiceway was not known. The powerhouse intake was equipped with an Atlas Polar trash rake. CL&P personnel advised that a heavier rake was not necessary because most of the trash consisted of leaves. At this station, everything that is raked out of the river is immediately flushed overboard to the tailrace. This practice is allowed because this project is not under FERC jurisdiction. FERC would prohibit return of the material to the river.

    The two turbine-generator units are located in a common powerhouse on the west side of the dam. Water is directed to the turbines through concrete box-type intake chambers which are located immediately downstream of the trash racks and intake gates. The turbines are vertical-shaft, fixed-blade, Francis-type that are directly coupled to the generators. The turbines are each rated at 1465 horsepower at 24-foot head. The equipment inside the powerhouse provides heat during the winter.

    Inside the powerhouse, it was noted that one of the two units was at 8% gate and was rotating off-line, due to leakage. The other unit was at 89% gate and was generating at 990 kW. There was considerable aeration in the tailrace, particularly in the leakage water from the unit that was off line.

Dam Safety and Stability

    The most recent CT DEP inspection of the Tunnel project was performed in 1996. The report that was issued as a result of the inspection included a checklist of items evaluated and also identified required action items. The single action item identified during the 1996 inspection was removal of vegetation, considered to be a maintenance activity. No action items related to stability or spillway adequacy were identified.

    The Tunnel Project does have an Emergency Action Plan that appears to be complete and current as of September 1998.

5.1.2.2 Electrical Equipment and Systems

    The configuration at Tunnel Hydro Station consists of two generators rated at 1250 kVA each connected through circuit breakers to the 11 kV metal class switchgear. The 11 kV switchgear connects to the station service transformer through a main power transformer breaker. A high voltage circuit breaker and a station service transformer are located in the 23 kV switchyard.

    During the early 1980's, both generators had their fields rewound. There are reportedly yearly inspections, which presently show the generators to be in good condition.

Generators

    Maintenance and outage reports through 1994, for both units, indicate that generator stators and rotors and their exciters have been tested. Additionally, the generator cables have been Hi-Potted and the neutral cable and transformers have received testing.

Generator

  Unit 1
  Unit 2
Installation   1919   1919
Manufacturer   W   W
Rated kVA   1250   1250
Voltage(kV)   11.0   11.0
PF   0.80   0.80
Rated kW   1000   1000
rpm   120   120
Exciter   Self   Self
Control   Manual   Manual
Generator Rewind   1984   1981
Last Major Overhaul   1984   1981

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Transformer

    Test data on the station transformer indicates that it was last tested in 1993, and that the tests were consistent with previous test data. Testing consisted of the standard Doble test, which include bushing, meggering, and excitation current.

Switchgear

    The station personnel indicated that there are yearly inspections of the 11 kV switchgear, which presently show the switchgear has been maintained in good condition. Generator breaker testing reports indicate that there were tests for Unit 1 in 1993 and for Unit 2 in 1989.

Controls

    In the control room, breaker control and metering of the Units is located on an existing switchboard. A new turbine-generator control switchboard will replace the existing switchboard during the next station outage. This should improve the reliability and maintainability of the station operation. The automatic station trips (i.e.: low water level, high trash rack differential, governor oil press low, high winding temperature, loss of AC or DC, loss of field, and high bearing temperature) are checked annually. Turbine control is set manually by opening the gates based on pond depth, generation requirements or minimum unit efficiency. Float controls are set to trip one unit at two feet below full pond level, and to trip the remaining unit at three feet below full pond level.

5.1.2.3 ICU

    The Tunnel Station property also includes a 20.8 MW ICU, Unit 10. The Unit consists of one Pratt & Whitney FT4A-8 Turbojet Power Pac series gas turbine generator, and has a rating of 20.8MW @ 13.8 kV and a 0.85 power factor at 3600 rpm. The Unit was not operated during the site visit. It went into service on July 1969. There have been 603 engine hours since the last major repairs. The gas turbine-generator enclosure (metal building), engine control house, and main transformer are located next to the Tunnel Hydro Station Switchyard. The ICU high voltage disconnect switch is located in the 13.8 kV switchyard. The ICU has remote and local controls, metering and protective relays. There is a 125 VDC battery system and charger for breaker control. The gas turbine-generator was inspected in November 1998 and was found to be in good operating condition. The main transformer and switchyard high voltage disconnect switch appears to be in good condition.

    There have been no trips during testing but there have been a few electrical and fuel trips during other operating conditions. Historically, the availability is about 96.1% and the capacity factor is about 0.5%. Unit 10 is presently utilized for peaking service. There is no black start capability, but with the addition of a DC fuel forwarding pump, the unit could be fully Black Start capable.

5.1.2.4 Performance

    Tunnel hydro availability averaged over 98% during the 1995-2000 period. The equivalent availability factor for the ICU averaged about 97% during the same period.

    Information provided by CL&P indicates an average capacity factor of about 47% for the hydro station and 0.7% for the ICU for the period 1995-2000. The capacity factor for the hydro units is within the typical range for a run-of-river hydroelectric plant. The low capacity factor for the ICU represents the typical operation of this type of unit for short term peaking service.

    The hydro station's projected capacity factor of 51.8%, as determined by the Market Consultant, is consistent with historical performance, and considered achievable over the projected economic life.

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5.1.3 Taftville

    Taftville Station is a 2.0 MW conventional hydroelectric facility located on the Shetucket River in the towns of Norwich, Lisbon and Sprague, CT., and has a drainage area of 510 square miles. The dam was built in 1906.

5.1.3.1 Civil and Mechanical Equipment and Systems

    The Station capacity is 2.0 MW, divided among five units. A power canal conveys water from the dam to the turbines, which are in scattered locations. Unit 1 has its own powerhouse, located between the power canal and the river section immediately below the dam. The other four units are located at various places within the adjoining mill building. It is understood that these turbines at one time provided belt-driven mechanical power to the machines in the mill factory building.

    Units 3, 4 and 5 were operating at the time of the site visit. A bulge was noted toward the left bank of the dam. This is discussed further in the "Dam Safety" section. The canal was equipped with an Atlas Polar rake, located at the end of the canal.

    The five turbine-generator units are supplied with water that is directed through a canal to the station. Water is routed from the canal through an 8 ft diameter steel penstock to the Unit 1 power house located east of the canal. Units 2, 3, 4 and 5 are located in the mill factory. The Unit 2 and 3 generators are located at floor elevation 39.2', and the Unit 4 and 5 generators are located at floor elevation 52.94'. The mill factory has an exciter room at floor elevation 39.9' for Units 1, 2 and 3. A common Control Room for all five units is at floor elevation 52.0', directly above the exciter room. The equipment inside the mill factory and local powerhouse provides heat during the winter, for the respective buildings. Some additional heaters are provided to prevent condensation on the wooden floors. The turbines for Units 1, 4 and 5 are vertical-shaft Francis-type that are directly coupled to the generators. The turbines for Units 2 and 3 are horizontal-shaft, double-runner Francis-type that are directly coupled to the generators. The turbine for Unit 1 is rated at 600 horsepower at 25-foot head, The turbines for Units 2 and 3 are each rated at 600 horsepower at 25-foot head, and the turbines for Units 4 and 5 are each rated at 530 horsepower at 25-foot head. Units 1, 2 and 3 have remote static excitation.

    The shaft on Unit 2 broke in 1992 and was replaced. The broken shaft had been a new shaft that was later found to have had a defect. Apparently, the earlier shaft had been replaced because of surface pitting.

Dam Safety and Stability

    The most recent CT DEP inspection of the Taftville project was performed in 1996. The report issued following the inspection included a checklist of items evaluated and also identified required action items. The action items identified during the 1996 inspection were maintenance items including brush trimming and the addition of warning signs.

    In addition, the inspector noted a bow in the west masonry wall and requested that monitoring points be established and that monitoring be initiated to verify that there is no movement. Because of the location of the bow near the water surface, it was difficult to establish a detailed monitoring program, so the bow was monitored visually. The suspicion that a damaged roof drain was responsible for the wall movement led to further investigation. In August 1999, a test hole was excavated revealing that the joint between the underground roof drain pipe and the pipe through the canal wall had separated allowing drainage to collect behind the wall. The joint was repaired and backfilled. NGC applied grout to targeted areas of the wall in 2000 to further address the problem.

    No other action items related to stability or spillway adequacy were identified.

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    The Taftville Project does have an Emergency Action Plan that appears to be complete and current as of September 1998.

5.1.3.2 Electrical Equipment and Systems

    The configuration at Taftville Station consists of generators 1, 2 and 3 that parallel through circuit breakers to a 600 V switchgear bus, and generators 4 and 5 that parallel through circuit breakers to a 2300 V switchgear bus. The 600 V and 2400 V bus are connected through circuit breakers and a 1500 kVA transformer. From the 2300 V switchgear, a circuit breaker supplies station service transformers and three single-phase 833 kVa step-up transformers. The Unit 1, 2 and 3 generators are connected to GE Air Circuit breakers (Type AL2) located in the 600 V switchgear in the control room. The Unit 4 and 5 generators are connected to GE Magna-Blast Circuit breakers (Type AM-5-50-4) located in 2.4 kV switchgear near the generators.

Generator

    It was reported that during the early 1980's, the generators were rewound on Units 1 and 4. In 1990 and 1995, Units 3 and 5 generators had their fields rewound. There are yearly inspections of the five generators, which have shown the generators to be in good condition. According to the outage report, generator 5 had its stator rewound in 1995 following a fire in Dec 1994. The stator line and neutral cables were also replaced. At this time also, the generator field breaker was found to be in need of repair. The breaker was put back into service until a replacement breaker could be found. A Unit 3-generator report indicates that it was tested in 1990. The tests included stator meggering, absorption, and Hi-Pot. The field was meggered, AC impedance, resistance measurement; pole drop and pole balanced tested. These tests showed the generator to be satisfactory. Data for Unit 1 generator indicates that its cables, stator and field were tested in 1981. For Unit 2 generator, polarization index testing and meggering was performed in 1984. On Unit 4 generator, a rewind was done in 1984 followed by polarization index testing and meggering.

Generator

  Unit 1
  Unit 2
  Unit 3
  Unit 4
  Unit 5
Installation   1926   1966   1906   1949   1949
Manufacturer   GE   Elliot Co   GE   W   W
Rated kVA   500   375   450   438   438
Voltage(kV)   0.6   0.6   0.6   2.4   2.4
PF   0.80   0.80   0.80   0.80   0.80
Rated kW   400   300   360   350   350
rpm   327   200   200   225   225
Exciter   Static   Static   Static   Direct   Direct
Control   Manual   Manual   Manual   Manual   Manual
Generator Rewind   1982       1990   1984   1995
Last Major Overhaul   1982   1992   1982   1980   1998

Transformers

    According to plant personnel, the main power transformers and step-up transformers are inspected and tested yearly. This equipment has been maintained in good operating condition. Maintenance reports show that the main transformers were Doble, power factor and bushing tested in 1994. The 1500 kVA transformer received similar testing in 1994 as well.

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Switchgear

    According to plant personnel, the 600 V switchgear for Units 1, 2 and 3, the 2.4 kV switchgear for Units 4 and 5 and the control room 2.4 kV switchgear are inspected and tested yearly. This equipment has been maintained in good operating condition.

Controls

    During the early 1980's, modifications to the switchyard and the station controls were made to conform to CL&P's operating practices. All metering, breaker control and turbine-generator trouble alarms are located in the Control Room.

    Turbine control is manually set for each Unit by opening the gates based on pond depth, generation requirements or minimum unit efficiency. Float controls are set to trip Units 1, 2 and 3 at three feet below full pond level, and to trip Units 4 and 5 at five feet below full pond level. The automatic station trips (i.e.: low water level, high trash rack differential, governor oil press low, loss of AC or DC, loss of field, high winding temperature on Unit 1, and high bearing temperature on Units 4 and 5) are checked annually. There is an automatic trash rack cleaning system installed on Units 2, 3, 4 and 5 common trash rack.

5.1.3.3 Performance

    The total capacity of Taftville is 2.0 MW divided among five units. Performance data was limited. The availability averaged in the low 90s from1995-2000. The capacity factor averaged about 40%for that same time period. This is typical for a run-of-river hydroelectric plant.

    The projected capacity factor of 36.3%, as determined by the Market Consultant, is consistent with historical performance, and considered achievable over the projected economic life.

5.1.4 Remaining Life

    There are three hydroelectric plants and one ICU in this System, with indicated construction dates, capacities and projected remaining economic lives as follows:

Station

  Indicated
Construction
Date

  Nominal
Capacity
(MW)

  Projected Remaining
Economic Life (Years)

Scotland   1909   2.2   20
Tunnel   1906 (Dam)
1919 (Generators)
  2.1   20
Tunnel ICU   1969   20.8   20
Taftville   1906   2.03   20

    The Taftville hydroelectric station has experienced considerable civil works maintenance activity, which appears to have arrested the problems that were being experienced. Equipment replacements and upgrades have been performed at these stations but the turbines appear to be original equipment. Given appropriate maintenance, 20 years of continued operation is considered reasonable and achievable for these Stations.

5.2 Operations and Maintenance

    S&W Consultants reviewed historic O&M performance and cost data contained in various documents that were made available for the sale of assets. S&W Consultants also interviewed management personnel and reviewed station records during our recent site visit. The assessment of O&M projections focused largely on the CUO studies provided by NGC.

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5.2.1 Staffing Levels

    The staffing level for the Eastern Hydro System is currently 2 people—an Electrician and a shift Group Leader. We understand that NGS plans to keep the same staffing level, which appears to be adequate for the operation of these stations. The numbers are typical of those found in similarly configured Stations that S&W Consultants has reviewed. NGS has established a business line to manage and operate combustion turbines, assuring the necessary expertise is available to maintain the Tunnel jet.

5.2.2 Operation and Maintenance Expenses

    The historical O&M expenses are shown below along with NGS projected O&M expenses. The projected expenses are annual averages from 2001 through 2019 for all units.


Eastern Hydro System O&M Expenses
(All Values in Nominal $000)

 
  Historical
  NGS
1994   $ 616      
1995   $ 810      
1996   $ 425      
1997   $ 387      
1998   $ 675      
1999   $ 532      
2000   $ 700      
2001-2009         $ 724
2010-2019         $ 891

    The NGS O&M expenses between 2001 - 2019 are consistent with historical expenses. The O&M expenses appear to be adequate based on the staffing level, projected operating level, and historical experience.

5.2.3 Overhaul Schedule

    S&W Consultants reviewed NGS's planned overhaul and maintenance schedule. The Scotland, Taftville, Tunnel, and Tunnel ICU stations are projected to have no overhauls or rewinds over the 20 year period.

    Given the projected capacity factors, the plan appears to be adequate assuming that long-range maintenance planning is used effectively and that appropriate condition-monitoring programs are implemented, maintained, and updated periodically.

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5.2.4 Capital and O&M Project Expense Forecast

    NGS's projected capital and O&M project expenses are summarized in the table below. These capital and O&M project expense forecasts were evaluated based on the condition of the Eastern Hydro stations and the expected remaining operating life of the Units.


Eastern Hydro System

Capital & O&M Project Expenses
(All Values in Nominal $000's)

 
  Capital

  O&M Projects
2001-2004   $ 2,351   $ 289
2005-2009   $ 2,333   $ 179
2010-2014   $ 2,852   $ 238
2015-2019   $ 672   $ 284
   
 
TOTAL   $ 8,208   $ 990
   
 

    The capital expenses include relicensing and upstream and downstream fish passage. Also included are clean air act additions at the Tunnel ICU.

    The forecast contains capital and O&M project expenses over the next twenty years of operation for all units and is reasonable given the age and condition of the stations. The projected capital and overhaul expenses should be adequate to keep the stations operating reliably through 2019.

5.2.5 Maintenance Management and Spare Parts

    NGS will continue to use a power plant Preventive Maintenance Management System (PMMS) to control maintenance information. NU currently uses the Passport system for spare parts and accounting. A PMMS developed by NU is fully integrated into the Passport system and its functionality is considered good.

    Information regarding the spare parts inventory for these stations, if any, has not been made available.

5.3 Environmental/Licensing

    S&W Consultants' environmental review focused on those issues that have the potential to result in significant mitigation or compliance expenditures or operating constraints, and is based on the following:

    This environmental review addresses compliance with permits, fish passage, minimum flows, and other environmental issues.

5.3.1 Scotland

    The Scotland Station is the only one of the Eastern Hydro facilities under FERC jurisdiction. Its current license was received in 1981 and expires in 2012. Based on the available information, the

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Station is not under any enforcement or compliance actions. Significant possible future environmental mitigation may include:

5.3.1.1 Relicensing

    The FERC license for the Scotland Station expires in 2012. In anticipation of that event, relicensing studies and application preparation are anticipated to begin in 2008 and continue through about 2014. It is estimated that the capital costs of Scotland relicensing will equal about $563,000 over a 6-year time period between 2008 and 2014.

5.3.1.2 Compliance with permits

    According to the Environmental Consultant's report (Phase I and II), the project is in compliance with Resource Conservation and Recovery Act (RCRA), Spill Prevention Control and Countermeasure (SPCC), National Pollution Discharge Elimination System (NPDES), and Department of Transportation (DOT) regulations.

    The Scotland Station received a Stormwater Permit on March 2, 1998 that expires on October 2, 2002. Water Quality Certification was received for this project on March 13, 1985. The certification requires that a minimum flow of 84 cfs or inflow, whichever is less, be maintained throughout the life of the project. According to the 1999 Minimum Flow Report submitted to the FERC on January 5, 2000, the project was operated so as to ensure that the minimum flow requirements specified in the project license were maintained without exception.

5.3.1.3 Fish Passage

    During the licensing process in the late 1970's and early 1980's, the U.S. Fish and Wildlife Service (USFWS) and the CT DEP raised the issue of fish passage. The need for fish passage was also mentioned in the Environmental Consultant's report as an item that may be required when fish populations exceed certain thresholds in the river. Most recently, in August 2000, NGC signed a MOA with the Connecticut DEP and the USFWS to develop upstream and downstream fish passage at the Taftville and Tunnel Projects. As part of that MOA, the DEP and USFWS agreed to refrain from exercising their rights to re-open the Scotland Project regarding fish passage facilities for the term of the existing license. Given the FERC's track record in responding to Agency requests for fish passage, and the fact that fish passage facilities will be provided at downstream facilities, it is highly probable that upstream and downstream fish passage will be required as part of a new License when the project is relicensed in 2012. NGC estimates that the capital cost of upstream and downstream fish passage facilities at Scotland Station will be approximately $1.7 million (including associated studies).

5.3.1.4 Minimum Flow

    The project currently maintains a minimum flow of 84 cfs or inflow, whichever is less. The application for license (12/19/80) indicated that minimum flows of 214 cfs, 84 cfs and 47 cfs were requested by the US Department of Interior (Interior), the CT DEP, and the Environmental Protection Agency (EPA) respectively. The FERC license required CL&P to perform studies in consultation with the Agencies, to determine the optimum flow and then to report back to the FERC with the findings. Based on those studies, the license set a minimum interim flow at 84 cfs. It is possible that a higher minimum flow could be requested by Agencies at the time of relicensing (2012), particularly if it gets tied in as a requirement for successful fisheries restoration. There is no way of knowing, at this time,

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what flow change might be required or how it would affect station operations. In the year since the original review was performed, no new flow issues have been raised for the Scotland Station.

5.3.2 Tunnel Hydro Station

    The Tunnel Hydro Station is not a FERC licensed project and is therefore not required to meet FERC requirements. Based on available information, the only significant environmental issue of concern for this station is fish passage.

5.3.2.1 Compliance with Permits

    According to site representatives at the site visit, there are no outstanding significant compliance issues associated with this station. The Tunnel Hydro Station received a stormwater permit on March 2, 1998 that expires on October 2, 2002. Our current review identified no new issues or concerns.

5.3.2.2 Fish Passage

    In October 2000, NGC signed a Memorandum of Agreement (MOA) with the DEP and USFWS that commits it to provide both upstream and downstream fish passage at the Tunnel dam. Under the agreement, NGC must submit an alternatives report to the DEP for its review and approval on or before December 31, 2001, and final design plans, specifications, and construction schedule on or before Dec. 31, 2004. Construction of upstream and downstream fish passage facilities must be completed at the Tunnel dam on or before January 31, 2007. The MOA also requires NGC to develop plans for studying the effectiveness of the fish passage facilities over a period of three full calendar years.

    At this time, a fish lift, with provisions for eel passage, appears to be the most acceptable means of upstream passage at this facility. Anticipated downstream passage methods are unknown and it is assumed that the options are under study. NGC estimates that the alternatives study, design, construction, and monitoring (three year program) of upstream and downstream fish passage at Tunnel will have a capital cost of about $1.65 million.

5.3.3 Tunnel ICU

    The Tunnel ICU consists of one Pratt & Whitney FT4A-8 peaking combustion turbine burning jet fuel and generating approximately 20 MW of electrical power. The ICU went into service in July 1969.

    The ICU operates under a valid General Permit that was renewed on June 18, 2001. The general permit allows the ICU to limit its potential to emit air pollutants and thus avoid the Title V operating permit requirements. The ICU currently operates under Consent Order No. 1494 that requires the use of NOx emission reduction credits (ERCs). The original Consent Order expired on May 1, 1999 but has since been extended by the CT DEP to May 2003.

    Possible future environmental upgrades and mitigative projects may include NOx control equipment and/or additional ERCs.

    Other possible future upgrades in air pollution control systems could result from new or future State and Federal regulations regarding ozone and fine particulate standards, toxic air pollutants, regional haze, and global warming but it is unclear at this time what, if any, additional controls may be needed.

5.3.3.1 Air Quality

    The ICU was constructed prior to the applicability of the EPA NSPS but is regulated by CT DEP emission control requirements. Operating limitations related to air quality include the requirement to

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hold sufficient ERCs for the operation of the ICU. The emissions limitations for this unit are summarized in the table below:


ICU Air Pollution Emission Limitations

Pollutant/Fuel

  Tunnel 10
NOx (lb/MMBtu)    
  Jet Fuel (24-hr)   0.80

Opacity (%)

 

 
  Oil (6-min avg.)   20
  Oil (instant.)   40

    The quantities of hazardous chemical storage at the station do not exceed threshold quantities to trigger the need for a RMP under the CAAA Title III, "Prevention of Accidental Releases" program.

5.3.3.2 NOx Compliance

    Under CAAA Title I, the ICU is subject to Phase I of the NOx RACT program that called for implementation by May 1995. Given that this turbine did not meet the NOx RACT emission limits by May, 1995, an NOV was issued by the DEP and a Consent Order was entered into requiring the acquisition of the necessary ERCs for continued operation and imposing the NOx emission rates shown in the previous table. The RACT limit for this turbine is 0.289 lb/MMBtu.

    New sources and gas turbine based non-utility generators receive 100 percent of the allowances needed for full capacity or permitted operation but must return unused allowances to the utilities. The ICU will receive the needed allowances to operate. Actual ozone season NOx emissions for the years 1995, 1996, and 1997 have been 6.1, 2.3, and 1.8 tons per year, respectively.

5.3.3.3 Federal Acid Rain Program

    The ICU is not subject to the Acid Rain Program.

5.3.3.4 Particulate and Opacity Compliance

    The unit is required to have emissions with opacity less than 20% for a 6-minute averaging time and less than 40% opacity on an instantaneous basis. The ICU currently does not monitor opacity.

5.3.3.5 Hazardous Materials

    Five areas of potential environmental concern were identified in the Environmental Consultant's environmental assessment reports. Based on the results presented, any remediation costs associated with these areas are not expected to be significant.

5.3.3.6 Water Supply and Treatment

    The ICU does not have any water issues as the turbine is air cooled.

5.3.3.7 Wastewater Treatment and Discharge

    The ICU does not have any wastewater issues as the turbine is air cooled.

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5.3.4 Taftville

    Taftville was determined to be non-jurisdictional by FERC in the early 1980s and, therefore, is not required to meet FERC requirements. Based on available information, the only significant environmental issue of concern for this station is fish passage.

5.3.4.1 Compliance with Permits

    According to the Environmental Consultant's reports (Phase I and II) for the Taftville Station, the project is in compliance with RCRA, SPCC, NPDES, and DOT requirements. The study did, however, express some concern over spills and contamination from sources other than the Taftville Station (particularly the Ponemah Mill and a dry cleaning business) that potentially affected the property. Concentrations of polycyclic aromatic hydrocarbon (PAH) compounds were detected in a soil sample from a boring. Without knowing the size of area affected it is impossible to calculate a cost that could be associated with cleanup. Since this was an isolated case (one of four samples), it is probable that any cleanup cost would be relatively low and not of particular concern.

    However, concentrations of several PAHs, TPH, copper, lead and zinc were present in all 5 sediment samples obtained from the upstream impoundment, the power canal and the Shetucket River downstream of the main tailrace. Concentrations were noted to be higher in the samples from the power canal and along the retaining wall downstream of the main tailrace compared to samples from the upstream impoundment. Although Connecticut has no current exceedence criteria for sediment, there is a possibility that the state could request ecological risk assessment and/or clean up of these areas in conjunction with assessment and/or cleanup of the contamination found in the area of the soil sample mentioned above. Even though much of this contamination probably came from previous mill activities and is not from the hydro operation, the current owner (NGC) would be responsible for cleanup. It is impossible to estimate how much cleanup might cost based on the information currently available, but the probability of significant cost is low.

5.3.4.2 Fish Passage

    In October 2000, NGC signed a MOA with the DEP and USFWS that commits to the provision of upstream and downstream fish passage at the Taftville dam. Under the Agreement, NGC must submit an alternatives report to the DEP for its review and approval on or before December 31, 2001, and final design plans, specifications, and construction schedules on or before Dec. 31, 2002. Construction of upstream and downstream fish passage facilities must be completed at the Tunnel dam on or before January 31, 2005. The MOA also requires NGC to develop plans for studying the effectiveness of the fish passage facilities over a period of three full calendar years. Interim reports on the results of the study must be submitted in the two interim years before the final report is provided.

    Current plans for the Taftville facility are for a fish lift, with provisions for eel passage. NGC anticipates that capital costs related to the alternatives analysis, design, and construction of fish passage facilities at the Taftville dam will total approximately $1.4 million between 2002 and 2004. It also anticipates expenditures in the order of about $20,000 for the monitoring studies.

5.3.4.3 Other Environmental Issues

    According to the License Application for the Taftville Project (12/80), the station is a contributing element to a Historic District (presumed to be the Taftville Historic District). As such, any physical alterations in the project would be subject to specific review by the State Historic Preservation Officer. Although this does not necessarily place a particular economic burden on the project, it does place restrictions on changes or maintenance actions that may be desirable.

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6 FLOW STUDIES

    S&W Consultants conducted a qualitative review of historical hydrologic data pertaining to issues potentially affecting continued operation of the plants. This review included an assessment of:

6.1 Variation of Generation as a Function of River Flow: Northfield Mountain

    Energy generation at the NGC plants will vary as a function of many parameters including the availability of water. A qualitative sensitivity analysis was performed by reviewing the relationship between historical gross annual generation and historical river flow. NGC provided annual gross generation data for the period 1951 through 1998. Average daily river flows were downloaded from the USGS files on the internet and average annual flows were developed for the period 1951 through 1996.

    The annual flow versus generation data was sorted by increasing flow rates and the generation data was plotted to depict the relationship of generation to increasing flows, as shown for the Northfield Mountain Station in Figure 6-1. A linear trend line was added to the figure to identify the general trend of the generation with increasing river flows.

    The annual generation for Northfield Mountain was compared with Connecticut River flows at USGS gage station 011705000. The daily river flows at this station varied from 463 cfs to 138,000 cfs during the period 1972 through 1996, a range that represents nearly the entire range of the 94 years of recorded flows at the gage station. As shown in Figure 6-1, the energy generation at Northfield varies from about 1,000,000 MWhr annually to about 930,000 MWhr as the average annual river flow increases from 9,800 cfs to 22,000 cfs. Significant excursions from the trend line may be a result of unit availability, system rather than plant optimization, or other factors unrelated to flow availability. The general trend for Northfield Mountain is that generation decreases slightly with increasing river flows as shown in Figure 6-1. This trend reflects the fact that the available storage in the Turners Falls reservoir is higher at lower Connecticut River flows, allowing Northfield Mountain to generate more energy at lower flows than at higher flows.

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Figure 6-1. Connecticut River Flow vs Northfield
Generation

     LOGO

6.2 Impact of Drought on Northfield Mountain Station Operation

    Although pumped storage operation is less affected than run-of-river operation by the variability of precipitation and runoff over time, the potential impact of low flows in the Connecticut River basin on operation at Northfield Mountain was reviewed.

    Northfield Mountain's pumped storage operation utilizes as its lower reservoir the portion of the Connecticut River bounded by Vernon dam, approximately 15 miles upstream of the Northfield Mountain intake, and Turners Falls dam, approximately 51/2 miles downstream from the intake. The lower reservoir level is controlled by the Turners Falls dam with a normal water level that varies between 176 ft and 185 ft due to the generation and pump-back cycle at Northfield. The water stored in this "wedge" in the reservoir between 176 ft and 185 ft is dedicated to Northfield operations. The water is pumped from the Connecticut River to a man-made reservoir at the top of Northfield Mountain and at a later time used to generate as it is returned once again to the Turners Falls reservoir. Turners Falls dam is operated to regulate the Connecticut River flows so that the fluctuations imposed by Northfield Mountain generation and pump-back operations do not affect flows downstream of Turners Falls dam.

    During low flow periods the operation does not change. Minimum required discharge at Turners Falls is equal to 1433 cfs or inflow, whichever is lower. At low flows, Turners Falls outflow equals inflow and the storage in the "wedge" remains available for Northfield Mountain operations. In the worst case scenario, if the Connecticut River flows drop to zero, the wedge of water would be depleted only by evaporation and leakage. Leakage has not been identified as a problem at Turners Falls and evaporation in the northeastern U.S. is small, with the annual average on the order of 25 to 30 inches.

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In a high evaporation year the rates in the Northeast are on the order of 40 inches per year. At Turners Falls reservoir, with a surface area of about 2,000 acres, this evaporation is equal to approximately 290 million cubic feet of water per year or about 9 cfs. Even if the annual evaporation occurred during a 30-day period, the equivalent flow is only 112 cfs.

    To evaluate the potential for low flow periods in the Connecticut River, we reviewed the historical flows in the Connecticut River near Turners Falls dam. The nearest USGS streamflow gage station is at Montague City, Massachusetts, gage station number 011705000. The records for this location include average daily flows from 1904 through September 1997. (The data from September 1997 through today is unchecked by the USGS and is not posted.) Based upon the review of the data through September 30, 1997, the minimum average daily flow in the Connecticut River was 215 cfs recorded in September 1958. Where one day's evaporation is not significant, a more meaningful statistic is the 30-day low flow value. Historically, the lowest 30-day flow was the equivalent of 1,753 cfs daily, more than adequate to make up for the evaporation losses.

    Based upon this evaluation of historical data, low flows pose little risk to operation at Northfield Mountain.

6.3 High Flow Events

    Noting the trend of decreasing total generation with increasing Connecticut River flows as described in Section 6.1, this section explores the frequency of occurrence of high flow days which might impact Northfield Mountain operation.

    In the range of Connecticut River flows from zero to 12,000 cfs, Northfield Mountain operations are coordinated with Turners Falls operations to 1) provide storage of the water released by Northfield and 2) avoid unnecessary spillage at Turners Falls. The pond level at Turners Falls goes up as Northfield generates and goes down as Northfield pumps. Meanwhile, the available natural river flow is passed through the turbines at the Cabot and Turners Falls station. This process allows for operation of Northfield in a way that is essentially unconstrained by available storage in the Turners Falls reservoir. Northfield can then generate up to its maximum nominal energy storage of 8,500 MWH, constrained only by its upper reservoir storage. Maximum and minimum water levels under this condition are, respectively, elevation 185 ft and 176 ft.

    When the river flow exceeds about 15,000 cfs, the combined capacities of the Cabot and Turners Falls stations will be exceeded and there will spillage at Turners Falls. Under these conditions Northfield will have essentially unlimited water available for pumping.

    As the river flow approaches 65,000 cfs, a flood condition would exist in which, according to the operating procedures, the Northfield generation must not increase the flow downstream from Turners Falls. During flood conditions the water level at Turners Falls will be regulated between elevation 176 ft and El 186.5 ft to provide storage of the water used by Northfield. This storage volume will be in the form of a wedge between the backwater curves that define the river surface for the two levels at Turners Falls. The volume of this wedge will decrease as the river flow increases. At 72,500 cfs, for example, Northfield can generate a total of only 6,000 MWH and, as the river flow continues to increase, the constraint on Northfield continues to increases until at 126,000 cfs Northfield can no longer generate.

    The analysis of historical daily river flows at Turners Falls from 1965 to 1997 (see Note) indicates that average daily flows between zero and 65,000 cfs, where there would be no impact on Northfield Mountain generation, occurred 98.5 percent of the time. Average daily flows between 65,000 cfs and 126,000 cfs, where Northfield's maximum generation would be impacted to some degree, occurred only 1.5 percent of the time most often during the spring freshet. Each occurrence of flows between 65,000 cfs and 126,000 cfs extended for a duration of between one and eleven days. Average daily flows greater than or equal to 126,000 occurred in only one high flow event for a total of 2 days during the 33 years on record. The range of flows, historical frequency of occurrence, and the range of impact on Northfield is summarized in Table 6-1.

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Table 6-1
High Flow Impact on Northfield Mountain Operations

Connecticut
River Flow
(cfs)

  Frequency of
Occurrence
1965 to 1997
(% of days)

  Nominal Maximum
Generation at
Northfield
(MWH)

0 to 65,000   98.5   8,500
65,000 to 72,500   0.5   Transition to 6,000
72,500 to 126,000   1   6,000 to 0
greater than 126,000   less than 0.01   0

Note:  Significant flood control reservoirs were constructed in the Connecticut River Basin between 1941 and 1965. As a result, only historical flows from 1965 to 1997 are representative of current hydrologic conditions.

6.4 Variation of Generation as a Function of River Flow: Cabot Station

    An analysis similar to that performed for Northfield Mountain was performed for Cabot Station. The daily river flows at this station varied from 215 cfs to 138,000 cfs during the period 1951 through 1996, a range that represents the entire range of the 94 years of recorded flows at the station. As shown in Figure 6-2, the energy generation at Cabot varies from about 220,000 MWhr annually to about 300,000 MWhr as the average annual river flow increases from 7,800 cfs to 22,000 cfs.

    Also depicted are the significant excursions away from the trend line, which may be a result of unit availability, system rather than plant optimization, or other factors unrelated to flow availability.


Figure 6-2. Connecticut River Flow vs Cabot

     LOGO


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    The general trend, as anticipated for a run-of-river station, is that generation increases with increasing river flows. The cumulative effect of these correlations on the overall operation of the NGC portfolio is discussed in the following Section.

6.5 Variation of Generation as a Function of River Flow: Additional Stations

    A similar analysis was also performed for the Falls Village, Bulls Bridge, Shepaug, Stevenson and Turners Falls stations. Together with Cabot and Northfield Mountain, these plants represent over 97 percent of the average annual energy generated by the hydro assets under evaluation. The results of the analyses are summarized in Table 6-2.


Table 6-2. Approximate Impact of Water Availability on Generation

 
  Total Energy Generation (MWh)
In Lowest Flow and Highest Flow Years

 
  Generation at
Station

  Lowest Flow Year
  Highest Flow Year
Falls Village   30,000   47,000
Bulls Bridge   40,000   50,000
Shepaug   84,000   132,000
Stevenson   80,000   107,000
Cabot   220,000   300,000
Turners Falls   8,000   14,000
Subtotal conventional units   462,000   650,000
Northfield Mountain   1,000,000   930,000

    The results of the flow studies analyses, while approximate, indicate:

    These combined results tend to reduce the overall sensitivity of the assets to fluctuations in the hydrologic cycle.

7 PROJECT AGREEMENTS

    S&W Consultants reviewed the Power Purchase and Sales Agreement (PPA) and the Management and Operation Agreement (MOA) associated with the NGC acquisition. S&W Consultants reviewed the Agreements from a technical standpoint to assess the adequacy and reasonableness of their terms and conditions. Legal, financial and other aspects of these Agreements were not considered for this Report, and are assumed to have been reviewed by other advisors. S&W Consultants was not asked to review the other contracts associated with this transaction.

7.1 Power Purchase and Sales Agreement

    S&W Consultants reviewed the Power Purchase and Sales Agreement between Select Energy, Inc. (Select) and NGC dated December 27, 1999. The Agreement sets forth the terms by which Select will purchase the capacity, associated energy output and ancillary services of the assets being acquired by NGC. The term of the Agreement is six years (through December 31, 2005) with an option for renewal.

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    In addition to supplying the capacity, energy and ancillary services associated with these assets, NGC's specific responsibilities under the contract include communications with ISO-NE and NEPOOL with regard to hourly actual operations, and for qualifying the facilities as generation resources in New England. NGC has sole responsibility for operation and maintenance of the Facilities, and also for maintaining all the necessary licenses, permits, approvals and other related requirements.

    Select is obligated to pay in accordance with the capacity and energy pricing defined in Schedule 1 of the Agreement. An excerpt reflecting the pricing structure for year 2001 is provided in Table 7-1. Delivery points are also specified in Schedule 1.


Table 7-1. Year 2001 PPA Pricing

Facilities

  Price
($/MWH)

  Price
($/kW-Year)

Housatonic System        
  Falls Village 1-3   33.10   14.76
  Rocky River 1-3   33.10   14.76
  Bulls Bridge 1-6   33.10   14.76
  Shepaug   33.10   14.76
  Stevenson 1-4   33.10   14.76
  Robertsville 1-2   33.10   14.76
  Bantam   33.10   14.76

Eastern System

 

 

 

 
  Tunnel 1-2   33.10   14.76
  Taftville 1-5   33.10   14.76
  Scotland   33.10   14.76
  Tunnel ICU   0.00   32.50

Northfield Mountain System

 

 

 

 
  Northfield Mt. Unit 1   0.00   103.70
  Northfield Mt. Unit 2   0.00   103.70
  Northfield Mt. Unit 3   0.00   103.70
  Northfield Mt. Unit 4   0.00   103.70
  Cabot 1-6   33.10   14.76
  Turners Falls # 1-3, 5,7   33.10   14.76

    Select, under a tolling arrangement defined in Article 6, is also obligated to pay the pumping costs associated with the Northfield and Rocky River facilities, and to pay for the cost of jet fuel required for operation of the Tunnel ICU. S&W Consultants was not asked to review any power sales Agreements currently held by Select that would support the payment obligations under this contract.

    Under the Agreement, Select has the sole discretion to request commitment and dispatch from the facilities, and for bidding and scheduling of the facilities with the ISO-NE, within appropriate operating constraints. Select is entitled to all NEPOOL-related benefits from, and obligations and liabilities associated with, the dispatch of the facilities.

    Provisions are also included which address force majeure, insurance, events of default and remedies, liability and dispute resolution.

7.2 Management and Operation Agreement

    S&W Consultants reviewed the draft Management and Operation Agreement dated February 1, 2000, between NGC and Northeast Generation Services Company (NGS) as amended on March 1,

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2000. The Agreement sets forth the terms and conditions by which NGS manages, operates and maintains the NGC assets. The initial term of the Agreement is six years from the date of ownership of the assets, with the option for yearly renewal thereafter. Either party can terminate the Agreement with a one-year advance notice.

    The NGS scope of services includes management, operations, maintenance, administration, labor, consumables, water, supervision and other goods and services necessary for the safe, efficient and reliable management, operation and maintenance of the Facilities on a daily basis. The scope is detailed in Exhibit 2 of the contract and appears, with the addition of minor modifications suggested by S&W Consultants, to be adequate for the continuing safe and reliable operation of the assets.

    The Agreement also defines the generation qualification, dispatch, bidding and scheduling, and communications responsibilities between the parties. NGS will be responsible for qualification of each of the facilities with the ISO-NE, and also for communication with ISO-NE with regard to hourly operation of each of the facilities. NGC will have sole discretion to request commitment and dispatch, and sole responsibility for bidding and scheduling the facilities with the ISO-NE.

    In accordance with Amendment No. 1, NGC pays NGS "actual total costs of providing such services, including applicable overheads and indirect costs, and reasonable compensation for necessary capital as permitted by Rule 91 of the SEC" under the Public Utility Holding Company Act of 1935, as amended. This pricing will continue unless and until the SEC approves or authorizes the pricing provisions contained in the original Agreement.

    The Agreement (Exhibit 5) specifies the approved capital expenditures as shown in Table 7-2.


Table 7-2—Approved Capital Expenditures under the MOA*

Facility

  2000
  2001
  2002
  2003
Housatonic Hydroelectric System                
  Falls Village Station   197.1   121.4   107.7   100.3
  Bulls Bridge Station   192.7   126.5   126.7   130.6
  Rocky River Station   113.8   60.8   158.4   162.7
  Shepaug Station   595.7   1,460.6   297.1   304.9
  Stevenson Station   216.0   165.2   265.1   272.1
  Robertsville Station   7.2   7.3   7.5   7.7
  Bantam Station   5.1   5.2   5.3   5.5

Eastern Hydroelectric System

 

 

 

 

 

 

 

 
  Tunnel Hydro Station   35.8   36.6   37.4   38.3
  Taftville Station   35.8   36.6   37.4   38.3
  Scotland Station   35.8   36.6   37.4   38.3
  Tunnel ICU   0.0   0.0   182.0   19.0

Northfield Mountain Hydroelectric System

 

 

 

 

 

 

 

 
  Northfield Mountain Pumped Storage Station   1,509.2   754.6   772.8   792.1
  Cabot Station   518.2   7,620.3   7,455.8   11,226.0
  Turners Falls # 1 Station   3.2   20.8   27.3   0.0

*
The above table in the MOA has not been formally amended for changes associated with the timing of capital projects in years 2001 - 2004. However, these timing changes are reflected in the financial projections and in the text of this Report. These revised capital expenditures are considered to be reasonable and consistent with the updated CUO plans provided by NGS. Request for and payment of additional capital expenditures is also covered under the Agreement.

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    The estimated costs and approved capital expenditures are intended to correspond with the maintenance schedule shown in Exhibit 7 to the Agreement. These summary level schedules also appear to be consistent with the CUO plans provided previously by NGS.

    Other terms of the Agreement include the "excluded costs" which NGS will not be responsible for paying. These include fuel for the Tunnel ICU, pumping costs, property taxes, insurance premiums and licensing fees.

7.2.1 CUO

    S&W Consultants compared the terms of the Management and Operation Agreement with the budget forecasts (CUO's) provided by NGS. With this understanding, the estimated costs are considered reasonable with respect to the O&M costs to be incurred by NGC, and appear to correspond to the budget forecasts presented in the CUO's.

8 FINANCIAL PROJECTIONS

    S&W Consultants developed the original independent pro forma financial model which combined the capacity and energy pricing forecasts prepared by the Market Consultant ("market pricing"), with the operation and maintenance expenses and capital expenditure forecasts developed by NGS and reviewed by S&W Consultants, and the financing terms provided by Salomon. The financial projections presented herein show the cash flows available to support repayment of debt, including total payback time. The Market Consultant provided forecast results through year 2020. For years 2021 through 2026, the forecast results are assumed to remain constant (in base year dollars) at 2020 levels. These financial projections were developed under three capacity and energy pricing scenarios:

    This section provides a description of model inputs and structure, and summarizes the technical assumptions, revenues, expenses, and results in terms of debt service, under the Base Case, the Lower Fuel Case, and the Overbuild Case. It should be noted that despite recent revisions and changes to the layout of the original model, the underlying cash flow assumptions/drivers have not changed since the model's inception. The only changes in the current financial model consist of minor, non-material revisions in fixed O&M and capital costs, and a correction in misstated revenue in 2005.

8.1 Model Overview

    The model incorporates supporting modules provided by NGS (the project-specific CUO's described earlier) and the Market Consultant (market study results). Financing assumptions, including principal amount, interest rate, and repayment terms, were provided by Salomon and also incorporated into the model. The financial projections include the revenues and expenses, cash flows, income statements, and balance sheets for the years 2002 through 2026, based on data for each of the Assets.

    The model incorporates the CUO files, dated 11/17/00, and updated 7/2001, which include year-by-year direct O&M costs, indirect O&M costs (project, non-project and labor), capital projects

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expenditures, SOX/NOX allowance costs, and inventory requirements at the unit and/or station level. These operating budget forecasts are based on capacity factor estimates that are considered reasonable.

    The model incorporates a market pricing results file, i.e., the results of a dispatch simulation under three defined market scenarios, dated December, 2000. The file consists of a tabular presentation of the projected revenues for each scenario net of pumping costs for Northfield Mountain and the Rocky River pumped storage facilities as well as net of fuel costs for the Tunnel Jet. The results are presented by year from 2002 through 2026, for the NGC portfolio of projects. For years 2021 through 2025, the S&W Consultants model assumes that the capacity factors and prices remain constant (in base year dollars) at 2020 levels.

    The financing structure consists of a two tranche $440 million bond issue. The $120 million Tranche A has a four-year tenor at a 4.998% coupon rate with a scheduled amortization (as shown in the table below). The $320 million Tranche B has a 25-year tenor, a 8.812% coupon rate, a grace period for principal payments of 5 years and an amortization schedule during years 6 through 25 (as shown in the table below). The financial projections show an average debt service coverage ratio of 3.05x with a minimum debt service coverage ratio of 1.54x for the life of the systems.


Tranche A Amortization Schedule

Year

  ($000)
2002   $ 24,000
2003   $ 27,000
2004   $ 31,500
2005   $ 37,500


Tranche B Amortization Schedule

Year

  ($000)
2006   $ 0
2007   $ 3,500
2008   $ 5,250
2009   $ 6,500
2010   $ 8,000
2011   $ 9,750
2012   $ 10,750
2013   $ 5,000
2014   $ 6,250
2015   $ 4,500
2016   $ 6,000
2017   $ 15,000
2018   $ 16,000
2019   $ 19,000
2020   $ 21,000
2021   $ 24,000
2022   $ 26,000
2023   $ 28,500
2024   $ 32,000
2025   $ 35,000
2026   $ 38,000

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8.1.1 General Assumptions

    In the review and development of the Financial Projections, S&W Consultants made certain assumptions with respect to conditions that may exist or events that may occur in the future. In addition, S&W Consultants has used data and information, provided to us, that we believe to be reliable. We believe that the use of these assumptions and data are reasonable for the purpose of our Report. However, some assumptions may differ significantly from actual future conditions due to unanticipated events and circumstances. To the extent that actual future conditions differ from those assumed herein, the actual results will vary from those forecasted.

    The principal considerations and assumptions used by S&W Consultants in developing the Financial Projections include the following:

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8.2 Technical Assumptions

    The technical assumptions are summarized in Table 8-1, and are discussed in detail in various sections of this report.


Table 8-1. Technical Assumptions

Asset

  Type
  Original
Capacity, MW

  Year of
Upgrade*

  Upgraded
Capacity, MW

  Economic
Life

  Capacity
Factor in
2001

 
Northfield Mountain System                          
  Cabot   Hydro   53.00   2004   62.00   40   57.10 %
  Northfield Mountain   P/S   1,080.00   2017   1,120.00   40   17.5 %
  Turners Falls   Hydro   6.25           40   27.27 %

Eastern Hydro System

 

 

 

 

 

 

 

 

 

 

 

 

 
  Scotland   Hydro   2.2           20   41.45 %
  Taftville   Hydro   2.0           20   36.30 %
  Tunnel   Hydro   2.1           20   51.80 %
  Tunnel 10 CT   CT   19.48           20   3.00 %

Housatonic Hydro System

 

 

 

 

 

 

 

 

 

 

 

 

 
  Bantam   Hydro   0.24           20   50.08 %
  Bulls Bridge   Hydro   8.40           40   61.00 %
  Falls Village   Hydro   11.0           40   42.43 %
  Robertsville   Hydro   0.57           20   24.74 %
  Rocky River   P/S   29.9           40   5.94 %
  Shepaug   Hydro   43.4           40   31.77 %
  Stevenson   Hydro   28.9           40   40.55 %
    Total       1,286.38                  

*
Upgrades occur incrementally over a multi-year span; this is the year the year the upgrades are complete for all units.

8.3 Revenues

    The revenue projections include energy and capacity revenues. In the Base Case, revenues for the first five years are based on the pricing defined in the PPA between NGC and Select Energy. Energy and capacity revenues for year six and forward are based on the market pricing forecasts prepared by the Market Consultant. As noted in Section 7.1, the Select Energy PPA involves a tolling arrangement for the Northfield Mountain and Rocky River pumped storage assets and the Tunnel internal combustion unit. Under this arrangement (and the Base Case projections), Select Energy will pay NGC a capacity payment for each of these facilities and will be responsible for providing pumping energy and fuel at Select Energy's own cost. Payments on the regular hydroelectric assets consist of both energy and capacity payments.

    The market pricing forecasts for energy revenues are based on the projected dispatch of each of the Assets and the associated market energy prices. Energy revenues reflect annual distributions of market clearing prices that were not made available to S&W Consultants. The market-forecast capacity revenues are based on market capacity pricing and the normal claimed capacity for the Assets.

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8.4 Expenses

    The major expenses shown in the Financial Projections include operations and maintenance, capital and depreciation projects, and other (emission allowances, insurance, and property taxes, provided by NGC). In all three scenarios, pumping, energy, and fuel purchases are zero during the term of the Select Energy PPA, since they are incurred by the power purchaser. Beginning in year six, the revenues provided by the Market Consultant are net of associated fuel and energy for pumping costs.

8.4.1 O&M Expenses

    The O&M expenses were developed by NGS for each station, and provided to S&W Consultants in the CUO files. O&M expenses include the following:

    The reasonableness of the projected O&M expenditures is discussed in the various "O&M" sections of this report.

8.4.2 Capital Projects Expenses

    Capital projects identified by NGC have also been included in the CUO files and incorporated into the S&W Consultants financial projections. Capital projects are generally depreciated over the remaining economic life of the unit. S&W Consultants finds the adequacy of the capital addition project budgets to be reasonable as discussed in the various sections of this report.

8.4.3 Fuel and Purchased Energy Expenses

    The Market Consultant developed the estimates for off-peak energy purchased to pump water to the upper reservoir of the pumped storage assets as well as the cost of fuel for the Tunnel ICU. Total fuel expense for the Tunnel ICU was calculated as the product of heat rate, fuel price, and energy generation. The Market Consultant then provided streams of revenues net of pumping and fuel costs as input into the financial model. These forecasts were considered inputs to the S&W Consultants model (i.e., reviewed by others). Note that in all three scenarios, fuel and energy purchases are incurred by the power purchaser, rather than by NGC during the term of the PPA, and are, therefore, not included in NGC operating costs.

8.5 Results

    The Financial Projections include the calculation of Cash Available for Debt Service (CADS). This measure of cash flow available to make debt service payments has been calculated by subtracting capital additions expenditures from EBIDTA (Earnings Before Interest, Depreciation, Taxes and Amortization), making it a conservative measure for assessing debt service coverage.

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Cash Flow Summary
($MM Unless Otherwise Noted)
Base Case

 
  2002
  2003
  2004
  2005
  2006
  2007
  2008
  2009
  2010
  2011
  2012
  2013
  2014
 
Net Revenues                                                      
  Contract Sales   136,448   138,131   138,131   138,131                                      
  Market Sales           116,898   120,291   127,053   128,850   134,204   138,831   143,616   148,567   153,689  
   
 
 
 
 
 
 
 
 
 
 
 
 
 
  Total Net Revenues   136,448   138,131   138,131   138,131   116,898   120,291   127,053   128,850   134,204   138,831   143,616   148,567   153,689  

Non-Fuel Expenses

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
  Fixed O&M   18,808   20,177   18,858   18,221   17,909   19,000   18,945   19,555   20,178   20,590   21,133   30,561   32,738  
  Indirect O&M   5,041   5,193   5,350   5,513   5,678   5,849   6,024   6,205   6,391   6,583   6,780   6,984   7,193  
  Property Taxes   7,793   7,969   8,076   8,187   8,293   8,401   8,510   8,621   8,733   8,847   8,962   9,078   9,196  
   
 
 
 
 
 
 
 
 
 
 
 
 
 
  Total Non-fuel Expenses   31,642   33,339   32,284   31,921   31,880   33,250   33,479   34,381   35,302   36,020   36,875   46,623   49,127  

EBITDA

 

104,806

 

104,792

 

105,847

 

106,210

 

85,018

 

87,041

 

93,574

 

94,469

 

98,902

 

102,811

 

106,741

 

101,944

 

104,562

 
Changes in Working Capital   (200 ) (172 ) (259 ) (205 ) 1,586   (352 ) (733 ) (267 ) (566 ) (527 ) (533 ) 189   (433 )
Capital Expenditures   (11,896 ) (9,875 ) (7,486 ) (2,360 ) (5,202 ) (1,782 ) (1,794 ) (1,787 ) (1,841 ) (1,863 ) (2,788 ) (3,139 ) (2,704 )
   
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash Flow Available for Debt Service   92,710   94,745   98,102   103,645   81,402   84,907   91,047   92,415   96,495   100,421   103,420   98,994   101,425  

Debt Service

 

57,896

 

59,659

 

62,753

 

67,104

 

28,198

 

31,621

 

33,024

 

33,784

 

34,678

 

35,685

 

35,804

 

29,233

 

30,015

 
DSCR   1.60   1.59   1.56   1.54   2.89   2.69   2.76   2.74   2.78   2.81   2.89   3.39   3.38  
2002-2005 Minimum   1.54
2002-2005Average   1.57
2006-2026 Minimum   2.69
2006-2026 Average   3.33
2002-2026 Minimum   1.54
2002-2026 Average   3.05

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Cash Flow Summary
($MM Unless Otherwise Noted)
Base Case

 
  2015
  2016
  2017
  2018
  2019
  2020
  2021
  2022
  2023
  2024
  2025
  2026
 
Net Revenues                                                  
  Contract Sales                                                  
  Market Sales   158,987   163,828   168,818   173,959   179,257   184,716   190,257   195,965   201,844   207,899   214,136   220,560  
   
 
 
 
 
 
 
 
 
 
 
 
 
  Total Net Revenues   158,987   163,828   168,818   173,959   179,257   184,716   190,257   195,965   201,844   207,899   214,136   220,560  

Non-Fuel Expenses

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
  Fixed O&M   37,419   38,698   28,892   30,215   30,156   29,667   25,612   26,442   27,186   27,984   28,826   29,691  
  Indirect O&M   7,409   7,631   7,860   8,096   8,339   8,589   8,847   9,112   9,386   9,667   9,957   10,256  
  Property Taxes   9,316   9,437   9,560   9,684   9,810   9,937   10,066   10,197   10,330   10,464   10,600   10,918  
   
 
 
 
 
 
 
 
 
 
 
 
 
  Total Non-fuel Expenses   54,144   55,766   46,312   47,995   48,305   48,193   44,525   45,751   46,902   48,115   49,383   50,864  

EBITDA

 

104,843

 

108,062

 

122,506

 

125,964

 

130,952

 

136,523

 

145,732

 

150,214

 

154,942

 

159,784

 

164,753

 

169,696

 
Changes in Working Capital   (245 ) (494 ) (1,435 ) (525 ) (658 ) (712 ) (1,021 ) (632 ) (659 ) (675 ) (693 ) (693 )
Capital Expenditures   (3,146 ) (3,219 ) (3,017 ) (2,970 ) (3,462 ) (3,940 ) (4,240 ) (2,832 ) (2,920 ) (2,398 ) (2,473 ) (2,473 )
   
 
 
 
 
 
 
 
 
 
 
 
 
Cash Flow Available for Debt Service   101,452   104,349   118,054   122,469   126,832   131,871   140,471   146,750   151,363   156,711   161,587   166,530  

Debt Service

 

27,753

 

28,823

 

37,096

 

36,752

 

38,276

 

38,558

 

39,641

 

39,482

 

39,636

 

40,548

 

40,662

 

40,511

 
DSCR   3.66   3.62   3.18   3.33   3.31   3.42   3.54   3.72   3.82   3.86   3.97   4.11  
2002-2005 Minimum   1.54
2002-2005 Average   1.57
2006-2026 Minimum   2.69
2006-2026 Average   3.33
2002-2026 Minimum   1.54
2002-2026 Average   3.05

A–89



Northeast Generation Company
Cash Flow Summary
($MM Unless Otherwise Noted)
Low Fuel Case

 
  2002
  2003
  2004
  2005
  2006
  2007
  2008
  2009
  2010
  2011
  2012
  2013
  2014
 
Net Revenues                                                      
  Contract Sales   136,448   138,131   138,131   138,131                                      
  Market Sales           107,193   114,317   119,847   121,943   126,433   130,596   134,896   139,338   143,926  
   
 
 
 
 
 
 
 
 
 
 
 
 
 
  Total Net Revenues   136,448   138,131   138,131   138,131   107,193   114,317   119,847   121,943   126,433   130,596   134,896   139,338   143,926  

Non-Fuel Expenses

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
  Fixed O&M   18,808   20,177   18,858   18,221   17,909   19,000   18,945   19,555   20,178   20,590   21,133   30,561   32,738  
  Indirect O&M   5,041   5,193   5,350   5,513   5,678   5,849   6,024   6,205   6,391   6,583   6,780   6,984   7,193  
  Property Taxes   7,793   7,969   8,076   8,187   8,293   8,401   8,510   8,621   8,733   8,847   8,962   9,078   9,196  
   
 
 
 
 
 
 
 
 
 
 
 
 
 
  Total Non-fuel Expenses   31,642   33,339   32,284   31,921   31,880   33,250   33,479   34,381   35,302   36,020   36,875   46,623   49,127  

EBITDA

 

104,806

 

104,792

 

105,847

 

106,210

 

75,313

 

81,067

 

86,368

 

87,562

 

91,131

 

94,576

 

98,021

 

92,715

 

94,799

 
Changes in Working Capital   (200 ) (172 ) (259 ) (205 ) 2,395   (663 ) (630 ) (292 ) (494 ) (489 ) (492 ) 231   (389 )
Capital Expenditures   (11,896 ) (9,875 ) (7,486 ) (2,360 ) (5,202 ) 1,782   (1,794 ) (1,787 ) (1,841 ) (1,863 ) 2,788   3,139   (2,704 )
   
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash Flow Available for Debt Service   92,710   94,745   98,102   103,645   72,506   78,622   83,944   85,483   88,796   92,224   94,741   89,807   91,706  
Debt Service   57,896   59,659   62,753   67,104   28,198   31,621   33,024   33,784   34,678   35,685   35,804   29,233   30,015  
DSCR   1.60   1.59   1.56   1.54   2.57   2.49   2.54   2.53   2.56   2.58   2.65   3.07   3.06  
2002-2005 Minimum   1.54
2001-2005 Average   1.57
2006-2026 Minimum   2.49
2006-2026 Average   3.03
2002-2025 Minimum   1.54
2002-2026 Average   2.80

A–90



Northeast Generation Company
Cash Flow Summary
($MM Unless Otherwise Noted)
Low Fuel Case

 
  2015
  2016
  2017
  2018
  2019
  2020
  2021
  2022
  2023
  2024
  2025
  2026
 
Net Revenues                                                  
  Contract Sales                                                  
  Market Sales   148,666   153,168   157,806   162,584   167,508   172,580   177,758   183,090   188,583   194,240   200,068   206,070  
   
 
 
 
 
 
 
 
 
 
 
 
 
  Total Net Revenues   148,666   153,168   157,806   162,584   167,508   172,580   177,758   183,090   188,583   194,240   200,068   206,070  

Non-Fuel Expenses

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
  Fixed O&M   37,419   38,698   28,892   30,215   30,156   29,667   25,612   26,442   27,186   27,984   28,826   29,691  
  Indirect O&M   7,409   7,631   7,860   8,096   8,339   8,589   8,847   9,112   9,386   9,667   9,957   10,256  
  Property Taxes   9,316   9,437   9,560   9,684   9,810   9,937   10,066   10,197   10,330   10,464   10,600   10,918  
   
 
 
 
 
 
 
 
 
 
 
 
 
  Total Non-fuel Expenses   54,144   55,766   46,312   47,995   48,305   48,193   44,525   45,751   46,902   48,115   49,383   50,864  

EBITDA

 

94,522

 

97,402

 

111,494

 

114,589

 

119,203

 

124,387

 

133,233

 

137,339

 

141,681

 

146,125

 

150,685

 

155,205

 
Changes in Working Capital   (198 ) (466 ) (1,405 ) (495 ) (627 ) (680 ) (990 ) (602 ) (626 ) (642 ) (658 ) (658 )
Capital Expenditures   (3,146 ) (3,219 ) (3,017 ) (2,970 ) (3,462 ) (3,940 ) (4,240 ) (2,832 ) (2,920 ) (2,398 ) (2,473 ) (2,473 )
   
 
 
 
 
 
 
 
 
 
 
 
 
Cash Flow Available for Debt Service   91,178   93,717   107,072   111,124   115,114   119,767   128,003   133,905   138,135   143,085   147,554   152,074  
Debt Service   27,753   28,823   37,096   36,752   38,276   38,558   39,641   39,482   39,636   40,548   40,662   40,511  
DSCR   3.29   3.25   2.89   3.02   3.01   3.11   3.23   3.39   3.49   3.53   3.63   3.75  
2002-2005 Minimum   1.54
2002-2005 Average   1.57
2006-2026 Minimum   2.49
2006-2026 Average   3.03
2002-2026 Minimum   1.54
2002-2026 Average   2.80

A–91



Northeast Generation Company
Cash Flow Summary
($MM Unless Otherwise Noted)
Overbuild Case

 
  2002
  2003
  2004
  2005
  2006
  2007
  2008
  2009
  2010
  2011
  2012
  2013
  2014
 
Net Revenues                                                      
  Contract Sales   136,448   138,131   138,131   138,131                                      
  Market Sales           106,803   121,627   126,007   131,448   135,025   139,126   143,351   147,705   152,190  
   
 
 
 
 
 
 
 
 
 
 
 
 
 
  Total Net Revenues   136,448   138,131   138,131   138,131   106,803   121,627   126,007   131,448   135,025   139,126   143,351   147,705   152,190  

Non-Fuel Expenses

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
  Fixed O&M   18,808   20,177   18,858   18,221   17,909   19,000   18,945   19,555   20,178   20,590   21,133   30,561   32,738  
  Indirect O&M   5,041   5,193   5,350   5,513   5,678   5,849   6,024   6,205   6,391   6,583   6,780   6,984   7,193  
  Property Taxes   7,793   7,969   8,076   8,187   8,293   8,401   8,510   8,621   8,733   8,847   8,962   9,078   9,196  
   
 
 
 
 
 
 
 
 
 
 
 
 
 
  Total Non-fuel Expenses   31,642   33,339   32,284   31,921   31,880   33,250   33,479   34,381   35,302   36,020   36,875   46,623   49,127  

EBITDA

 

104,806

 

104,792

 

105,847

 

106,210

 

74,923

 

88,377

 

92,528

 

97,067

 

99,723

 

103,106

 

106,476

 

101,082

 

103,063

 
Changes in Working Capital   (200 ) (172 ) (259 ) (205 ) 2,428   (1,306 ) (534 ) (570 ) (418 ) (484 ) (486 ) 239   (381 )
Capital Expenditures   (11,896 ) (9,875 ) (7,486 ) (2,360 ) (5,202 ) (1,782 ) (1,794 ) (1,787 ) (1,841 ) (1,863 ) (2,788 ) (3,139 ) (2,704 )
   
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash Flow Available for Debt Service   92,710   94,745   98,102   103,645   72,149   85,289   90,200   94,710   97,464   100,759   103,202   98.182   99,978  
Debt Service   57,896   59,659   62,753   67,104   28,198   31,621   33,024   33,784   34,678   35,685   35,804   29,233   30,015  
DSCR   1.60   1.59   1.56   1.54   2.56   2.70   2.73   2.80   2.81   2.82   2.88   3.36   3.33  
2002-2005 Minimum   1.54
2002-2005 Average   1.57
2006-2026 Minimum   2.56
2006-2026 Average   3.31
2002-2026 Minimum   1.54
2002-2026 Average   3.03

A–92



Northeast Generation Company
Cash Flow Summary
($MM Unless Otherwise Noted)
Overbuild Case

 
  2015
  2016
  2017
  2018
  2019
  2020
  2021
  2022
  2023
  2024
  2025
  2026
 
Net Revenues                                                  
  Contract Sales                                                  
  Market Sales   156,812   162,092   167,550   173,192   179,023   185,051   190,603   196,321   202,210   208,277   214,525   220,961  
   
 
 
 
 
 
 
 
 
 
 
 
 
  Total Net Revenues   156,812   162,092   167,550   173,192   179,023   185,051   190,603   196,321   202,210   208,277   214,525   220,961  

Non-Fuel Expenses

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
  Fixed O&M   37,419   38,698   28,892   30,215   30,156   29,667   25,612   26,442   27,186   27,984   28,826   29,691  
  Indirect O&M   7.409   7,631   7,860   8,096   8,339   8,589   8,847   9,112   9,386   9,667   9,957   10,256  
  Property Taxes   9,316   9,437   9,560   9,684   9,810   9,937   10,066   10,197   10,330   10,464   10,600   10,918  
   
 
 
 
 
 
 
 
 
 
 
 
 
  Total Non-fuel Expenses   54,144   55,766   46,312   47,995   48,305   48,193   44,525   45,751   46,902   48,115   49,383   50,864  

EBITDA

 

102,668

 

106,326

 

121,238

 

125,197

 

130,718

 

136,858

 

146,078

 

150,570

 

155,308

 

160,162

 

165,142

 

170,096

 
Changes in Working Capital   (188 ) (531 ) (1,474 ) (566 ) (703 ) (759 ) (1,022 ) (633 ) (660 ) (675 ) (694 ) (694 )
Capital Expenditures   (3,146 ) 3,219   3,017   (2,970 ) (3,462 ) (3,940 ) (4,240 ) (2,832 ) (2,920 ) 2,398   2,473   (2,473 )
   
 
 
 
 
 
 
 
 
 
 
 
 
Cash Flow Available for Debt Service   99,334   102,576   116,747   121,661   126,553   132,159   140,816   147,105   151,728   157,089   161,975   166,929  
Debt Service   27,753   28,823   37,096   36,752   38,276   38,558   39,641   39,482   39,636   40,548   40,662   40,511  
DSCR   3.58   3.56   3.15   3.31   3.31   3.43   3.55   3.73   3.83   3.87   3.98   4.12  
2002-2005 Minimum   1.54
2002-2005 Average   1.57
2006-2026 Minimum   2.56
2006-2026 Average   3.31
2002-2026 Minimum   1.54
2002-2026 Average   3.03

A–93


APPENDIX B


Independent Market Expert's Report
for the Portfolio of the
Northeast Generation Company

Final Report

Prepared for:
Salomon Smith Barney, Inc.
390 Greenwich Street
New York, NY 10013

Prepared by:
PHB Hagler Bailly, Inc.
1881 Ninth Street, Suite 302
Boulder, Colorado 80302
303-449-5515

December 20, 2000



DISCLAIMER

    This report presents PHB Hagler Bailly, Inc.'s (PHB Hagler Bailly) analysis of the New England Power Pool (NEPOOL) power market.

B–i



TABLE OF CONTENTS


Chapter 1    Introduction

 

B-1
  1.1  Background   B-1
  1.2  Asset Description   B-1
  1.3  Structure of the Report   B-1

Chapter 2    Regional Competitive Power Market Structures

 

B-2
  2.1  Introduction   B-2
  2.2  Competitive Power Markets   B-2
    2.2.1  Reliability and Competitive Markets   B-3
  2.3  NEPOOL   B-6
    2.3.1  Background   B-6
    2.3.2  NEPOOL State Restructuring Status   B-12

Chapter 3    Approach to Market Price Forecasting

 

B-14
  3.1  Introduction   B-14
  3.2  Issues in Forecasting Market Prices   B-14
    3.2.1  Economic Equilibrium and Market Price Forecasting   B-14
    3.2.2  Capacity and Energy Markets   B-12
    3.2.3  Forecasting Generation Service Prices   B-17
  3.3  Approach to Market Price Forecasting   B-18
    3.3.1  Market Characteristics   B-19
    3.3.2  Predicting Energy Prices and Dispatch   B-19
    3.3.3  Predicting Prices Related to Capacity:
The Capacity Compensation Simulation Model
  B-19
    3.3.4  Market Entry and Exit   B-21
    3.3.5  Volatility Analysis   B-21
  3.4  Applying the MVPSM Approach to the NGC Portfolio   B-27
    3.4.1  Forecasting the Future Prices of Ancillary Services   B-28
    3.4.2  Revenue Streams   B-29

Chapter 4  Assumptions

 

B-31
  4.1  Introduction   B-31
  4.2  General Assumptions   B-31
  4.3  Pricing Areas   B-31
  4.4  Fuel Prices   B-31
    4.4.1  Natural Gas   B-32
    4.4.2  Fuel Oil   B-34
    4.4.3  Coal   B-37
  4.5  Demand and Energy Forecasts   B-38
  4.6  Electricity Imports   B-38
  4.7  Existing Generation Units   B-38
    4.7.1  Fossil Units   B-38
    4.7.2  Hydroelectric Units   B-43
    4.7.3  Nuclear Units   B-43
  4.8  Capacity Compensation Simulation Model Input Assumptions   B-44
    4.8.1  Existing Units Going-Forward Costs   B-44
    4.8.2  Capacity Additions Through 2002   B-44
    4.8.3  Capacity Additions Post 2002   B-45
  4.9  Volatility Analysis Assumptions   B-47

B–ii


Chapter 5  Market Price Forecasts   B-47
  5.1  Introduction   B-47
  5.2  NEPOOL Market Assumptions   B-48
  5.3  NEPOOL Cases Considered in This Analysis   B-49
  5.4  Energy Price Forecasts From The Fundamental Analysis   B-50
    5.4.1  NEPOOL Case 1 Fundamental Analysis Results   B-50
    5.4.2  NEPOOL Case 2 Fundamental Analysis Results   B-52
    5.4.3  NEPOOL Case 3 Fundamental Analysis Results   B-54
  5.5  Energy Price Forecasts With Volatility   B-56
    5.5.1  NEPOOL West Case 1 Volatility Results   B-57
    5.5.2  NEPOOL West Case 2 Volatility Results   B-58
    5.5.3  NEPOOL West Case 3 Volatility Results   B-59
  5.6  Relative Uncertainty of Cash Flows   B-60

Appendices:

A
Pricing Areas
B
Regional Specific Coal Price Discussion
C
Transfer Capability
D
Generic Capacity Additions

B–iii



CHAPTER 1

INTRODUCTION

1.1  BACKGROUND

    PHB Hagler Bailly, Inc. (PHB Hagler Bailly) has been retained by Salomon Smith Barney to perform an independent power market study in connection with the bond financing being undertaken to refinance a number of generating facilities purchased from Connecticut Light and Power (CLP) and Western Massachusetts Electric Company (WMECO). These facilities include pumped storage, hydroelectric, and combustion turbine units. This document presents the results of the PHB Hagler Bailly assessment of future prices for electric energy and capacity in the Northeast markets.

    The valuation analysis presented in this report is drawn from the best information available concerning the current regional market structures within this evolving market environment. While forward price forecasting is more challenging in an evolving market, PHB Hagler Bailly's approach is to examine the fundamental economic value provided by these assets, along with an analysis of the volatility inherent in electricity markets, and to place this value in the context of the planned market institutions.

1.2  ASSET DESCRIPTION

    The assets are as follows:

1.3  STRUCTURE OF THE REPORT

    This document describes the anticipated market structures as well as our approach to constructing forward-price forecasts for generation services. The document is organized as follows:

B–1



CHAPTER 2

REGIONAL COMPETITIVE POWER MARKET STRUCTURES

2.1  INTRODUCTION

    In this chapter, PHB Hagler Bailly examines the current and projected development of wholesale power markets in the New England Power Pool (NEPOOL) region. Over the past two decades, the structure of the electric power industry has been increasingly shaped by the emergence of a prevailing market trend in the networked industries, namely the introduction of competition in formerly regulated markets. This chapter sets the background for the restructuring initiatives underway in the target markets examined in this study.

2.2  COMPETITIVE POWER MARKETS

    Much of the recent progress toward implementing competition in electricity markets is due to a series of legislative and regulatory decisions rendered over the past two decades. The legislative and regulatory framework behind the development of competitive wholesale electricity markets in the United States can be largely traced to the 1978 Public Utilities Regulatory Policies Act (PURPA). This act spurred the growth of the non-utility generation industry and increased wholesale competition, albeit on a limited scale due to transmission ownership issues and other market access constraints. The 1992 Energy Policy Act expanded wholesale competition by mandating transmission owners to provide "open access" for all system users. Transmission access rights were further strengthened in 1996 with Federal Energy Regulatory Commission (FERC) Open Access Rule, Order No. 888 (Order 888). This order called for transmission owners to offer "comparable service" to all customers through the application of a pro forma transmission tariff. Order 888 also encouraged the creation of Independent System Operators (ISOs), whose role in operating and managing regional transmission assets is described in greater detail in this chapter. However, even before Order 888 was drafted, the creation of ISOs and the establishment of formalized competitive markets were already underway in California and the Northeast.

    Compared to other countries, which have adopted a national plan for transitioning to competitive power markets, the restructuring process in the United States has progressed piecemeal, with significant differences between various regions. This is largely due to the division of authority over various aspects of the electric power industry between state and federal legislative and regulatory bodies.

    The debate over retail access and other measures to implement market competition has raised a number of fundamental market transition issues. Three of the principle issues common throughout the country are (1) the assessment and allocation of stranded costs, (2) the elimination of market power, and (3) the method for guaranteeing fair and impartial access to the transmission system. These issues are briefly discussed below.

    Stranded costs can be defined as the positive excess of the net book value of generation assets and power purchase costs over the market value of the assets. The introduction of competition in formerly regulated electricity markets presents a significant financial burden for utilities with generating assets or power purchase contracts, which may now be priced out of the market. A large number of utilities throughout the United States are faced with losses due to the adoption of market pricing before they have had a chance to recover the cost of their prior investments through their rate base. In order to ensure the support of the utility industry in the restructuring agenda, many state utility commissions and legislative bodies have agreed to allow utilities to recover either all or part of their stranded costs through a number of different recovery mechanisms. These recovery vehicles are designed to support the introduction of competition while still allowing the affected utilities to recover a specified portion

B–2


of their expected losses over a fixed period of time. However, the cost recovery method varies from state to state.

    Despite two decades of independent power producer (IPP) development, the majority of the generation assets in the United States were to be owned and operated by vertically integrated investor-owned utilities. Within regional electricity markets, the concentration of generating assets is often controlled by a small number of incumbent utilities. The removal of regulation and the introduction of market-based pricing into such markets raise concerns over the potential abuse of market power. To relieve these concerns, federal and state regulatory bodies have taken various measures to eliminate the threat of market power. The principal means of dealing with market power has been the unbundling of generation, transmission, and distribution assets. This is often followed by the mandated sale of a certain amount of generation assets by the traditional utilities to non-affiliated companies or the transfer of assets to an unregulated subsidiary. Such generation auctions and negotiated sales have resulted in the transfer of billions of dollars of generation assets in the past few years, changing the face of the generation industry in many regions of the country. The impact of current and future unbundling and generation ownership transfers must be considered when analyzing long-term conditions in regional power markets.

    In addition to the recovery of stranded costs and elimination of market power, the ability to reach newly opened markets through the high voltage transmission grid at a fair price is a fundamental requirement for introducing true competition. Thus, the issue of transmission access is at the core of the restructuring movement.

    Much of the development of competitive market structures and system operations in recent years has involved the balancing of system reliability concerns with the desire to allow the market to drive the development of the electricity industry. This balancing of market forces and reliability concerns is evident in the transmission industry. The high-voltage transmission system and the corresponding bulk power markets in the United States were originally developed to ensure reliability of supply rather than to support commercial transactions and power trading. Stemming from the Northeast blackout of 1965, the utility industry organized regional reliability councils to coordinate reliability practices in the United States and parts of Canada and Mexico. The continental United States is divided into 10 regional reliability councils whose policies are, in turn, coordinated by the North American Electric Reliability Council (NERC). The reliability councils are voluntary organizations that establish guidelines for all member utilities and suppliers. Two of the principle guidelines established by each council concern:

    The ten regional reliability councils are part of larger interconnected and synchronized electric power systems. There are three synchronized electricity networks in the United States:

B–3


    These systems are interconnected through limited direct current (DC) ties, but their alternating current (AC) systems operate independently of one another.

    While the regional reliability councils provide standards and guidelines, they do not provide actual electricity dispatch, scheduling or other transmission system operational services. In order to capture the economies of scale associated with load and resource pooling as well as joint-dispatch and transmission operations, utilities in a number of regions voluntarily established power pools, the first of which, the PJM Power Pool, was established in 1927. Power pools attempt to capture the benefits associated with being part of a larger generation and transmission system, including improved reliability through coordinated maintenance planning and shared operating reserves, as well as the blending of load profiles and generating resources. Power pools vary widely throughout the United States in terms of the degree to which they provide coordination and services.

    While pooling arrangements were beneficial for reliability, it is possible that they are not suitable for supporting and developing truly competitive electricity markets. Due to their limited membership and strict membership criteria, external marketers, power producers, and eventually regulatory bodies viewed power pools as barriers to competition. Through Order 888, FERC actively encourages the formation of ISOs that replace the power pool organization in scheduling, dispatching and operating the regional transmission system. The purpose of the ISO is to provide independent grid management through a process in which all system users are treated equally. Many of the utilities in the most tightly coordinated power pools in the United States were among the first to file ISO applications with the FERC, but the ISO trend is now progressing through the industry as an increasing number of states enact legislation implementing retail access.

    The creation of an ISO entails the transfer of management and operational control of the transmission system to an independent administrator that has no financial interest in the operation of the generating facilities using that network. As interstate transmission organizations, new ISOs will fall under the regulatory jurisdiction of FERC and must seek FERC approval for their operations. The FERC regulations provide a strong motivation for establishing ISOs, since a retail provider affiliated with an investor-owned utility which has not satisfied the FERC ISO criteria cannot compete for customers outside its franchised service territory unless it maintains rates based on cost of service.

    In connection with the approval process, FERC has created a list of criteria to which ISOs must adhere. Two of the fundamental criteria of the proposed ISO framework are the need to establish an independent governance structure for the ISO and the application of a postage-stamp tariff for the entire ISO region which would eliminate the payment of a transmission fee to each control area that is involved in a transaction ("pancaking"). Independent governance of each ISO is critical to the ability of such ISO to execute transactions in an unbiased manner, applying the same service standards and prices to both incumbent utilities and new market entrants. The application of a system-wide tariff is also critical for competition. It establishes a level playing field in terms of transportation costs for all generators within an ISO's territory, and it reduces the "pancaking" effect of wheeling power through such ISO's territory.

    The role of the ISO in a functioning spot market is critical to the efficient operation of competitive markets. The spot market may be operated by either the ISO or by a separate Market Operator (or Power Exchange). The spot market is designed to provide a balancing function in which excess generation capacity is matched to demand not already covered under existing bilateral contracts. This balancing market allows wholesale suppliers and customers to hedge their existing bilateral contracts with purchases from the spot market, while also providing the ISO with a source for

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regulating capacity and emergency supply through various market mechanisms. The specific characteristics of the regional ISO and power markets will have a direct financial and operational impact on the affected generating assets.

    Several ISOs are already operating or under review by FERC, while several others are in the development stage. However, only a few of these ISOs currently incorporate a spot market function. There are currently five functioning ISOs in the United States: the California ISO (CA-ISO), the PJM-ISO, the New England ISO (NE-ISO), the ERCOT-ISO,(1) and the New York ISO (which officially assumed control of the New York Power Pool grid on November 18, 1999). The Midwest ISO (MISO) was also conditionally approved by FERC in September 1998 and is expected to begin operations by the end of 2001. The Alliance RTO filed for FERC approval in June 1999. In addition, the Entergy Corporation has proposed the creation of a for-profit transmission subsidiary (TRANSCO), to operate and manage its transmission assets in a manner similar to an ISO.

    On December 20, 1999, FERC issued Order No. 2000, Regional Transmission Organizations Docket No. RM99-2-000. FERC's objective in issuing Order No. 2000 "is for all transmission-owning entities in the Nation including non-public utility entities, to place their transmission facilities under the control of appropriate RTOs in a timely manner." Order 2000 establishes minimum characteristics and functions for appropriate RTOs; a collaborative process for developing RTOs; a proposal to consider transmission ratemaking reforms; an opportunity for non-monetary regulatory benefits; and a time line for public utilities to make appropriate filings with the Commission to initiate operation of RTOs.

    In the preceding Notice of Proposed Rulemaking (NOPR) issued May 13, 1999, the Commission proposed a rule on RTOs that identified concerns with the traditional means of grid management. The Commission reviewed evidence that traditional management of the transmission grid by vertically integrated electric utilities was inadequate to support efficient and reliable operation of the grid. Continued discrimination in the provision of transmission services by vertically integrated utilities may be impeding fully competitive electricity markets.

    The development of appropriate regional transmission institutions could (1) improve efficiencies in transmission grid operation, (2) improve grid reliability, (3) remove remaining opportunities for discriminatory transmission practices, (4) improve market performance, and (5) facilitate lighter handed regulation.

    Order 2000 establishes minimum characteristics that an RTO must satisfy including independence, scope and regional configuration, operational authority, and short-term reliability.

    The minimum functions that an RTO must satisfy include tariff administration and design, congestion management, parallel path flow, ancillary services, OASIS and Total Transmission Capability (TTC) and Available Transmission Capability (ATC), market monitoring, planning and expansion, and interregional coordination.

    FERC allows industry participants to retain flexibility in structuring RTOs that satisfy the minimum characteristics and functions. Different organizational forms such as ISOs, TRANSCOs, combinations of the two, or new forms not yet discussed could be utilized. FERC also establishes an "open architecture" policy that provides regulatory flexibility to allow the RTO and its members to improve their organizations.

(1)
ERCOT is not under FERC jurisdiction; the Texas Public Utility Commission approved the ISO proposal.

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    All public utilities (with the exception of those participating in an approved regional transmission entity that conforms to the Commissions's ISO principles) that own, operate or control interstate transmission facilities must file with the Commission by October 15, 2000 a proposal for an RTO with the minimum characteristics and functions to be operational by December 15, 2001, or, alternatively, a description of efforts to participate in an RTO, any existing obstacles to RTO participation, and any plans to work toward RTO participation.

    While each of the individual power pools and RTOs are developing individually and have different products, the final resulting economies will likely be similar. Thus, PHB Hagler Bailly approaches all regions with the same fundamental analysis (see Chapter 3). The following section describes the structure of the target market analyzed in this study.

2.3  NEPOOL

    This section describes the New England Power Pool (NEPOOL) component of the Northeast Power Coordinating Council (NPCC). NPCC is the regional organization responsible for the coordination of the operation and planning of the bulk power electric systems in New York, New England, and eastern Canadian Provinces. The purpose of this coordination is to maximize the efficiency of the planning and operation of individual electric systems within the region in order to ensure system stability and reliability. The NPCC is split into two ISOs, NEPOOL and the New York Power Pool (NYPP). On November 9, 1965, a blackout took place that left most of the northeastern United States without power for as long as thirteen hours. A lack of coordination between the existing utility companies was seen as a primary reason for the power failure. Pressure was applied on the northeastern United States to pool power sources together. This was the impetus that brought about a cooperative system amongst the northeastern United States' electric service providers. This cooperation evolved into NEPOOL in November of 1971.

    NEPOOL's voluntary membership includes municipal and consumer-owned systems, investor-owned utility systems, power marketers, joint-marketing agencies, load aggregators, independent power producers, and exempt wholesale generators. NEPOOL's main functions are to coordinate, monitor, and direct the operations of virtually all of the major generation and transmission bulk power supply facilities in New England. NEPOOL's annual peak load exceeds 23,000 MW with resulting capacity requirements over 28,000 MW (2000). NEPOOL participants own and operate over 1,800 miles of 345 kV transmission lines, 400 miles of 230 kV lines and nearly 6,000 miles of 115 kV lines. NEPOOL's two primary objectives are to assure the reliability of the bulk power supply in the New England region while minimizing costs and fairly allocating them. It achieves these two objectives primarily through central planning and dispatch of all of the bulk power facilities in the region.

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    On July 1, 1997 New England's Independent System Operator (ISO-NE) was established as a non-profit corporation responsible for the management of the regions bulk power generation and transmission systems. Created by NEPOOL, ISO-NE has responsibilities to its parent that are defined in an independent system operator contract. ISO-NE administers the NEPOOL Tariff transmission facilities in a fair and neutral manner with reliability and cost-effectiveness acting as two driving forces.

    There are two types of transmission service. The first is known as "Through" or "Out Service." This covers transmission service routed through the NEPOOL Control Area. The other transmission service is known as Regional Network Service (RNS). This covers the remaining types of regional service routed through the NEPOOL Control Area. The charges for these services are determined by Schedules 8 and 9 of the Tariff. Transmission rates are recalculated on June 1st of each year, as stated in the Tariff. There are three transmission interfaces between New England and neighboring regions. These are New York, Hydro-Quebec, and New Brunswick. The Hydro-Quebec interface is currently fully utilized under a long-term contract that ends in the summer of 2000. NEPOOL's Pool Transmission Facilities (PTF) network path is mapped out in Figure 2-1.


Figure 2-1
New England Transmission System(1)

LOGO

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    The NEPOOL Market structure is currently going through significant changes. The Operable Capability Market was disbanded on March 1, 2000 and the Installed Capability Market(2) followed suit on August 1, 2000.

    ISO-NE oversees the Internet-based trading of five wholesale electricity products that are bought and sold in New England daily. The Federal Energy Regulatory Commission is hearing the proposed changes in the NEPOOL Market from ISO-NE and the generators that product the regions' power. For this reason the seven markets that were in existence at the beginning of the year 2000 will be reviewed as their histories have some effect on the market structure today.

    The following seven markets were in existence at the start of the year 2000: Energy, Installed Capability (replaced with an administratively set deficiency charge), Operable Capability (disbanded on August 1, 2000), Automatic Generation Control (AGC), Ten Minute Spinning Reserve (TMSR), Ten Minute Non-Spinning Reserve (TMNSR), and Thirty-Minute Operating Reserve(3) (TMOR).

    Bids in each of these markets are comprised of all the information submitted by a participant that relates to bid price, quantity, technical bid parameters, and timing of offers for a Generator or Dispatchable Load to provide specific services in one or more of the defined markets. The bid prices are the amount that a participant offers to accept in a notice furnished to the system operator, in this case ISO-NE. The bid prices are meant to compensate for:

    The Energy Market.  The energy market is currently structured so generators submit hourly bids ($/MWh) on a day-ahead basis for the next 24 hours. Based on these bids, ISO-NE schedules the generating units that will provide energy on the following day with the objective of minimizing total costs in the energy market. Hourly settlement occurs after the fact. Suppliers receive and buyers pay amounts equal to the MWh sold and bought, respectively, multiplied by the ex post facto energy clearing price. Compensation to the out-of-merit unit is the higher of the bid or market clearing price. There is only one financial settlement, based on the actual energy quantity bought/sold in real time. In the event that transmission constraints occur, congestion costs will be apparent in the difference in energy prices between or among nodes and will reflect the marginal cost of supplying additional demand at each node in any given hour. This system is currently under review, as discussed in the section covering anticipated market changes.


(2)
As discussed in the following sections, the capacity requirement remains in place with requirements purchased in the bilateral market and shortfalls assessed a deficiency charge.
(3)
Operating Reserves (OR) are the necessary level of generation capability that must be available at all times for increased generation output. Operating Reserves are needed to maintain system reliability in the event of an instantaneous loss of a generating unit or transmission interconnection with surrounding control areas. NERC and NPCC require operating reserve availability in all control areas to protect against significant contingencies such as changes or reductions in supply sources. The three types of operating reserves are Ten-Minute Spinning (TMS), Ten-Minute Non-Spinning (TMNS), and Thirty-Minute Operating Reserves (TMOR). These operating reserves combine with the AGC market to produce the four bid-based ancillary service markets. Each operating reserve has its own market and bidding process.

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    Installed Capability Market.  On May 8, 2000, in an amendment to its earlier filing of the Congestion Management and Multi-Settlement Systems (CMS/MSS) proposal, ISO-NE proposed eliminating the Installed Capability Market. In its June 28 ruling on CMS/MSS, the FERC approved the elimination of the Installed Capability Market effective August 1, 2000.

    While the Installed Capability Market was disbanded, the New England ISO still imposes installed capability requirements on all Load Serving Entities (LSE) in the market. Since there is no longer a spot auction market, LSEs must now go to the bilateral market to meet their capacity needs. If a LSE fails to meet this requirement, they must pay an administratively determined capacity charge. Proceeds from this charge are distributed to market participants with surplus capacity.

    Operable Capability Market (recently disbanded).  Operable Capability focused on an entity's ability to respond to ISO-NE's call for energy, operating reserve, or AGC. However, on February 23, 2000, the FERC ordered this ruling.(4) "We will accept NEPOOL's proposal to terminate the OpCap market effective March 1, 2000. The OpCap market is a redundant market whose value to consumers has not been demonstrated. In addition, the capacity available through the OpCap market is also available through the Operating Reserves and Energy markets. Generators: (1) already receive compensation from the Operating Reserves and Energy markets for daily availability, and (2) provide no additional service for the revenues they receive from the OpCap market."

    Automatic Generation Control (AGC Market).  AGC is a measure of the ability of a generating unit to provide instantaneous control balance between load and generation and help maintain proper tie line bias. This is done to control frequency and to maintain currently proper power flows into and out of the NEPOOL Control Area. In short, AGC is basically a ramping service to follow the second-to-second fluctuations in load and supply. AGC responds to the NEPOOL Area Control Error (calculated every four seconds) in an effort to continuously balance the NEPOOL Control Area's supply resources with minute to minute load variations in order to meet the NERC and NPCC Control Performance Standards. AGC performs the ancillary service known as regulation. In the absence of AGC services, interconnected control area operation and control area frequency control could not be adequately maintained. Participants give one day advance bids for a Generator supplying AGC to the market in terms of $/hr. Each Generator must have a separate AGC bid for each hour of the following day. An AGC Bid may include up to four Regulating Ranges for a single Generator, each defined by an Automatic High and Low Limit and an Automatic Response Rate.

    ISO-NE calculates a lost opportunity payment and a production cost charge for AGC if the resource is committed to AGC. The system operator ranks generators according to their AGC bid, the generator's opportunity cost payment, and the AGC production cost change to select resources for AGC service. Generators successful in the AGC market are paid for the revenues they would otherwise have received plus compensation for the loss in efficiency of their units.

    Ten-Minute Spinning Reserve (TMSR).  TMSR provides contingency protection to ISO-NE's system. TMSR is measured as the Kilowatts of Operable Capability that an electrical generating unit can provide. This unit, unloaded during all or part of the hour, is able to load to supply energy on demand (within ten minutes), reach its maximum generating capacity in under ten minutes, and able to sustain the maximum output level for over thirty minutes. A TMSR unit is also capable of providing contingency protection by immediately reducing energy requirements within ten minutes and maintaining the reduced requirements ISO-NE determines.

    In the initial market, bidding in the ten-minute spinning reserve market is restricted to hydroelectric, pumped storage, and dispatchable load resources. All on-line generation that is capable of raising generation can supply TMSR. Bidders submit hourly bids in $/MW for the next day and designate the reserve market for their bids. The ISO-NE ranks generators from least to most expensive.


(4)
FERC statement, 2/23/2000.

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In the case of TMSR, this includes consideration of lost opportunity cost and production cost differences should the unit be committed to TMSR instead of the energy market.

    Reimbursement for a Generator committed to ten minute spinning reserve is as follows. It receives the energy market clearing price, its TMSR bid price for the MWs provided, and a lost opportunity payment for the margin it would have received in the energy market. Should a generator be committed to ten-minute non-spinning or thirty-minute operating reserves, it receives the time-weighted average price for the specific type of reserve it provided during the hour. Since initially only hydroelectric facilities (including pumped storage) and dispatchable generators may bid into the TMSR market, these resources can receive higher prices for TMSR service than other resources.

    Ten -Minute Non-Spinning Reserve (TMNSR).  TMNSR is generation that can reliably be connected to the network and loaded, or load that can reliably be removed from the network, within ten minutes of activation on a sustainable basis. TMNSRs are any resources and requirements that were able to be designated for the TMSR but were not designated by the system operator for such duties during the a specific hour. Surplus TMSR can be counted as TMNSR.

    Thirty-Minute Operating Reserve (TMOR).  TMOR is generation output that is available to the system operator within 30 minutes after request or load that can reliably be removed from the network within 30 minutes on a sustainable basis. TMORs are any resources and requirements that were able to be designated for the TMSR and TMNSR but were not designated by the system operator for such duties during a specific hour. Surplus TMSR and TMNSR can be counted as TMOR. The NE-ISO may contract for additional ancillary services as needed.

    Anticipated Market Changes.  New England has built a solid market structure over the past several years. NEPOOL is however continually changing in an effort to achieve further reliability and cost gains, and ISO-NE is proposing various market revisions to be implemented as soon as possible. Full implementation of a Congestion Management/Multi-Settlement System (CMS/MSS) is anticipated in the next 16 to 24 months, and the proposals contain many new market design elements.

    A multi-settlement system (MSS) is being proposed. This will be a two-settlement system involving a day-ahead market and a real-time market for energy and ancillary services. It is expected to run as follows. Prices and scheduled quantities for each product will be established based on a day-ahead bid that binds the participant into a financial settlement on the following day. Separate prices will be determined for real time operations, and a second binding financial settlement will be made based on changes in real time from the day-ahead schedule.

    A permanent Congestion Management System (CMS) will be implemented in the next 16 to 24 months. ISO-NE would manage transmission congestion based on locational marginal prices. Hourly energy prices paid to generators would vary at each node to reflect transmission congestion. ISO-NE would establish eight load zones based on reliability regions. Loads would pay the weighted average of the nodal prices in the zone, based on historical load patterns for that zone. Zonal pricing of load is needed for two reasons. The majority of New England's distribution companies are required to provide uniform pricing in their region of operation and the necessary metering is not in place in all areas to implement nodal pricing of loads. Transmission customers would not bid for transmission; instead, a customer taking transmission service would be required to pay the applicable transmission congestion charge. The FERC has accepted ISO-NE's proposal for a permanent CMS. However, CMS implementation is not expected for at least a year.

    ISO-NE is planning on having generators submit a three-part bid on a daily basis. The three parts will be comprised of energy production, no-load, and start-up. Generators would be scheduled over the day to minimize total bid costs, but the energy price would be set based only on the energy bid of the marginal supplier. The logic behind this pricing is it reflects the marginal bid-cost of producing energy. The three-part bid should allow generators to bid a more accurate representation of their cost

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functions. This three-part bid has been approved by the FERC with the requirement ISO-NE submit an evaluation of its efficiency after the MSS has been in operation for six months.

    On August 28, 2000, the three northeast ISO's (New England, New York, and Ontario) jointly issued a Request for Proposal (RFP). The proposal asked to perform a feasibility study for a regional day-ahead electric market that would establish energy prices and schedules for the next day. The goal is to offer additional capability for market participants to buy and sell electricity across a broader region than is presently available within the ISO markets. The RFP falls in line with FERC's Order 2000, which calls for the formation of Regional Transmission Organizations (RTO). In that same order, FERC indicated that it favors larger regional ISO markets that reduce what they refer to as "seams" between existing markets. There are three phases to the study. The first phase is to analyze various options and recommend something to be approved by all three ISO's. Once the first phase is accepted, the second phase would incorporate a system reliability study. The third phase would then produce functional specifications based on the outcomes of the first two phases. The first phase should be completed on or before March 30, 2001.

    Proposed changes to the ancillary service markets include a system where generators submit combined bids for both energy and spinning reserves. Currently, generators submit separate bids for energy and each of the four ancillary services. ISO-NE considers all of these bids jointly in determining how to schedule and dispatch generators to meet the energy and ancillary services requirements while minimizing total cost. Under the proposed system, three-part bids would be submitted into the auction. ISO-NE would decide which participant provides energy and which distributes spinning reserves. (The ISO would continue to consider all bids jointly when developing a least total cost schedule.) The price paid for spinning reserves would then reflect the opportunity cost of not selling energy. The opportunity cost would be calculated by taking the difference between the applicable energy price and the generator's energy bid. This proposal was denied by the FERC on June 28, 2000.

    ISO-NE is proposing to take price into consideration in determining how much of each ancillary service to purchase in the day-ahead market. Currently, ISO-NE purchases the required amount of ancillary services regardless of the price. It is feasible for suppliers to set prices arbitrarily high in times of limited excess capacity. Under the new plan, a demand curve will be derived for each ancillary service. This would be accomplished by predicting the amount of each ancillary service that loads would be willing to buy at numerous prices. ISO-NE would coordinate this estimated demand curve with supply bids to determine how much of each ancillary service to purchase daily. ISO-NE states that the demand curves will help avoid overpaying for an ancillary service. ISO-NE is the first independent system operator to propose using demand curves in procuring ancillary services. Given the current plan's ambiguity (derivation of demand curves and exact benefits of the proposal are still unclear), the FERC has approved requests to apply price or bid caps.

    The four-hour reserve is a non-spinning reserve is designed to encourage accurate demand-side bidding in the day-ahead market. ISO-NE anticipates it will provide adequate capacity in the real-time market. ISO-NE wants to make its own forecast on demand, and compare the forecast to the quantity of energy scheduled in the day-ahead market. If ISO-NE's demand forecast exceeds the day-ahead scheduled quantity, purchases made on the four-hour reserve market would allow them to make up the difference. The plan calls for operating reserves to be substituted for four-hour reserves if the cost is cheaper. The cost of four-hour reserves is allocated to participants who underbid their load day-ahead. ISO-NE projects the real-time price will be typically higher than the day-ahead price, and thus will provide an adequate penalty for non-performance. The FERC has approved the proposal for four-hour reserves, recognizing it could improve reliability. Some areas have to be worked on before implementation, such as the fact that ISO-NE will determine the amount of four-hour reserves based on its forecast, but it does not pay for the reserves. ISO-NE will work with New York and PJM ISOs in designing this market.

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    Finally, in connection with its filing with the FERC to eliminate the Installed Capability Market, and in subsequent discussions with PHB Hagler Bailly, the ISO-NE indicated the need for a mechanism to compensate and encourage entry of generating units that provide quickstart capability. The ISO is currently considering alternative mechanisms that could meet this need.

    The states in the NEPOOL region are in different stages of restructuring their retail markets. The states of Massachusetts and Rhode Island have already established retail competition while Maine and Connecticut are starting retail competition in 2000. New Hampshire has been in litigation with Public Service Company of New Hampshire over recovery of stranded costs. Further hearings on this issue are occurring in 2000. The state of Vermont has started an investigation into retail competition following a voluntary plan submitted by the IOUs in March 1999. The status of restructuring is summarized below for each of the states included in NEPOOL.

    Implementation of retail choice began on January 1, 1998. Full competition is scheduled to begin October 1, of 2000. A 5% rate reduction will occur on October 1, 2000 if competition has not occurred. Transmission and distribution will still be regulated when customer choice is introduced.

    New Hampshire was among the first few states in the country to enact electric deregulation legislation. However, because of disagreements with the Public Service Company of New Hampshire (PSNH) and the state government over the size of rate cuts and stranded cost recovery the process had been delayed until recently. Legislation was passed and signed into law in June 2000. Senate Bill 472 authorizes refinancing of $800 million of PSNH's debt to be paid off over 12 to 14 years. PSNH will reduce rates by an average 15.5% for businesses and 17% for residential consumers. Residential rates will be capped for nearly three years, and businesses' rates for nearly two years. PSNH agreed to divest its generation assets by July 2001, and operate as a transmission and distribution utility, regulated by the State.

    Also in June 2000, the New Hampshire Electric Cooperative voted to set their own rates and approve financing without oversight of the Public Utility Commission (PUC). The PUC will, however, continue overseeing contracts between the cooperative and outside suppliers, IPPs, municipal utilities, and deregulation activities within the service territory.

    The state legislature opened up full customer choice on July 1, 1998. As of June 1999, roughly 2,000 customers out of the State's 456,000 had chosen alternative generation suppliers. Retail access was implemented with 25 registered suppliers, but the standard offer interim rates (3.2 cents/kWh) offered by the State's investor-owned utilities (IOU) were low enough that no real competition has occurred. The rates have been increased three times to 4.5 cents/kWh because of increased wholesale prices. As a result, competition has begun to emerge.

    A 2.8 cent/kWh transition charge is assessed to customers for the first three years in order to recover stranded costs. A standard offer rate offered to customers who have never chosen a supplier will be based on 1996 prices plus inflation until the year 2009.

    In December of 1998, the governor submitted a plan to have customer choice by March of 2000, but there was no retail choice legislation passed in 1999. Currently there are no definite plans to have customer competition implemented in the state any time soon. There are currently state groups set up analyzing the structure that could be seen in the retail market.

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    Central Vermont Public Service Company and Green Mountain Power proposed a plan to the Public Service Board to voluntarily open their franchises to retail competition as early as the end of 2001. A collaborative process was started to examine the proposal and determine the best way to establish retail competition in Vermont.

    Following legislation, Maine customers started seeing itemized billing that separated the costs of power generation from delivery in January 1999. The Maine Public Utilities Commission (PUC) increased standard offer rates for Bangor-Hydro customers to 4.6 cents/kWh in July 2000 (less than a 1% increase). A bill was passed in the early part of 2000 that delayed the startup of competitive billing and metering until March 2003, when billing services will be subjected to competition. Large investor-owned utilities are not allowed to have affiliates sell more than 33% of the kilowatt-hours sold within its regulated service territory. They are also not allowed to provide standard offer service for more than 20% of its regulated-affiliate's load.

    In August 2000, the Maine PUC approved a transmission/distribution rate scheme submitted by the Maine Public Service Company and the Maine Office of the Public Advocate. The order separates Maine Public Service Company's overall transmission and distribution revenue requirements into a transmission component under FERC jurisdiction and a distribution component under PUC's jurisdiction.

    In April 1998, restructuring legislation was passed that required retail competition for 35% of consumers by January 2000 with all customers having retail competition by July 2000. In April 1999, the Department of Public Utility Control (DPUC) ordered generation charges be shown as a separate charge beginning July 1999. As of June 1999, no suppliers had yet applied for licensing to serve Connecticut's market upon its January 2000 opening. From January 1, 2000 through January 1, 2004, each distribution company is required to provide a standard offer rate that is at least 10% less than the December 31, 1996 base rates. Beginning January 1, 2004, a distribution company will procure generation services for customers who do not have an alternate supplier through competitive bidding. Also, electric suppliers are required to obtain specific percentages of their power from renewable energy sources, with percentage increases each year through 2009.

    In August 2000, Northeast Utilities announced that Dominion Resources will pay approximately $1.3 billion for its three-unit Millstone nuclear station. The transaction is expected to be complete by April 2001, pending approval from several state and federal agencies. This followed news of a Connecticut restructuring law passed in 1999 that required the sale of nuclear assets by 2004.

    Massachusetts consumers began to sign up to purchase power from competitive suppliers in June 1998. In September 1998, Pennsylvania Gas & Electric secured a multi-year contract with the Massachusetts High Technology Council to provide electricity to its members. This is the largest aggregation of customers in the United States, representing approximately 1.2 million MWh annually.

    The Department of Telecommunications and Energy (DTE) established two options for default service rates in June 2000. The first called for default service customers (defined as those customers who have left their competitive supplier, or are new to the utility's territory) to choose between a six-month fixed price option and a variable monthly rate. Customers that switch between competitive and fixed-price service during a six-month period will have their bills for all six months adjusted. The purpose of this is to prevent customers and suppliers from gaming the system. In July 2000, the DTE issued a rule that will allow utilities to base their rates for default service on the wholesale bid prices, beginning January 2001. Utilities complained that the required rate, set below the cost of wholesale power, was causing them to lose money on default customer accounts. Utilities may begin issuing competitive bids seeking 6-month to 1-year contracts for the power needed to serve their default service customers. The DTE is also looking into eliminating exclusive service territories for investor-owned utilities.

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CHAPTER 3

APPROACH TO MARKET PRICE FORECASTING

3.1 INTRODUCTION

    This chapter discusses PHB Hagler Bailly's approach to forecasting market prices for the services of generating units in the context of estimating the revenues that may accrue to assets of the type owned by Northeast Generating Company—namely pumped storage, hydroelectric, and peaking plants. A key characteristic of these assets, particularly the pumped storage assets, is their ability to arbitrage movements in electric energy prices—buying energy when the price is low and selling energy when the price is high. These assets are also unique in their flexibility and they provide substantial amounts of ancillary services (particularly automated generation control, the service that regulates the second-to-second variations in the frequency of power and spinning reserve).

    This chapter is organized as follows. The first section discusses the issues faced while forming these forecasts, namely the distinction between capacity and energy markets and the evolution of market structures. The second section describes the relationship between energy markets and compensation for capacity and the implications for forecasting market prices. The third section summarizes the methodology used for estimating market prices for electricity in this analysis. The final section discusses specific issues to estimating the revenues streams associated with pumped storage facilities.

3.2 ISSUES IN FORECASTING MARKET PRICES

    This section discusses several issues that form the basis for PHB Hagler Bailly's approach to market price forecasting. The first of these issues is the concept of economic equilibrium and how it suggests that the market will react to returns on equity (or lack thereof). The second has to do with the components of revenue that are present in our forecasts. Each of these topics is addressed below.

    3.2.1  Economic Equilibrium and Market Price Forecasting

    A fundamental tenet of PHB Hagler Bailly's market price forecasting approach is that markets are attempting to adjust to economic equilibrium conditions. By economic equilibrium, we mean that the market will attempt to exploit or capture excess margins through entry (e.g., when the return on equity is above market), and will attempt to increase margins where they are below market through exit. In other words, excess returns should not persist because someone will enter to capture a portion of the above market return.

    While the concept of economic equilibrium is sound in principle, actual markets may not follow economic equilibrium exactly. Many industries have shown cycling returns, where high returns are followed by excess entry resulting in low returns which are followed by a disincentive to invest which results in high returns. While such cycling and overshooting is often a characteristic of commodity markets, these markets are, in general, attempting to adjust to a level commensurate with economic equilibrium—that is, they cycle around the price level suggested by economic equilibrium.

    To explore the implication of such "disequilibrium" conditions, we generally construct an overbuild scenario where excess entry is presumed to occur. Excess entry is presumed to occur early in the study period, as the impacts on generation assets are likely to be most severe in this timeframe. Subsequent to this period of capacity abundance, we then examine how the market might return to economic equilibrium.

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    3.2.2  Capacity and Energy Markets

    One must consider the institutions that define the electric market in order to make market price forecasting relevant. Some electric markets, such as those in the Northeastern United States (New York, PJM, New England) and England and Wales, provide separate compensation for energy and capacity. Generators have the opportunity to recover their variable costs and going-forward costs(1) from the energy market and in the capacity market. This market structure encourages generating capacity and provides for fair market compensation.

    Other electric markets, such as Australia, New Zealand and many regions of the United States, are energy only markets where the market does not separately pay generators for their installed capacity.(2) In theory, an energy only market leads to economically efficient capacity levels in the long run. As long as prices rise sufficiently to allow the generators in the market to recover their variable costs and going-forward costs, the average energy price should cover the costs of new capacity, even if there is no separate capacity payment delivered from either a traded capacity market or administered by the market operator.

    While the type of market in place in a given region will determine the composition of the revenue streams and will affect the mix and timing of new generating units, the financial return on new assets is likely to be similar in both types of markets as generators seek to cover their total going-forward costs.

    The structure of U.S. electricity markets is evolving and new forms of market organization have been adopted in areas such as California and the Northeast and are proposed for the Midwest and ERCOT. These structures will continue to evolve as electricity markets develop and move through the transition period from regulated monopolies to fully functioning competitive markets. Indeed, competitive market structures may continue to change even after a market is considered mature, as is occurring in England and Wales.

    Although no region in the United States has a fully mature market today, there is an emerging worldwide consensus on what a competitively restructured electricity industry should look like. Principle facets of the market should include:

    In addition, a competitive market should allow for effective competition among generators, with minimal abuse of market power.(3)


(1)
Going-forward costs are those costs that a generator cannot avoid if they remain in the market, such as fixed operation and maintenance (O&M), property taxes, employee benefits, and incremental capital expenditures. These costs do not include a return on capital or debt service, as these costs are deferrable on capital that is already committed to the marketplace (e.g., sunk).

(2)
Forms of energy-only pricing systems also may include payments for spinning and operating reserves. However, payments for ancillary services are differentiated from capacity reserve payments for purposes of this discussion.

(3)
Ideally, the wholesale market would be competitive with no presence of market power. However, electricity is not quite a pure commodity, as it must be produced in real time with no inventory. This leads to the circumstance that location matters in electricity as it does in real estate. Such a spatial market cannot avoid the periodic presence of market power, but such occurrences should be, ideally, minimal.

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    The United States is currently experimenting with both markets that have fixed reserve margin requirements coupled with capacity markets and those that implicitly price capacity through high on-peak energy prices. It is not clear which model will eventually become more widespread. Nevertheless, in both types of markets, new generating capacity will be developed based on the revenue streams determined through competition.

    In electric markets, such as PJM, New York, or New England, where load-serving entities are required (by administrative rule) to own or contract to for a minimum generating capacity reserve level, the capacity obligation creates a market between those that are short on their capacity obligation and those that have surplus capacity. In a competitive market, potential suppliers compete to provide this capacity. Markets have been developed to support trading of this capacity, typically in the form of daily, monthly or annually traded capacity, for which generators are compensated for being available to produce if and when required. In such markets, generators attempt to cover their total going-forward costs through a combination of revenue from energy, capacity, and ancillary service markets as well as through sale of options and forwards on a bilateral basis.

    In market structures without an explicit capacity market (such as California), generators must place greater weight on recovering their going-forward costs from the energy market. Were capacity to trade in a market with a capacity obligation for significant amounts of revenue, one would expect that a market without a capacity market would have more volatile prices than one that has a capacity market.

    As mentioned above, one would expect that price volatility would be higher in a market that does not provide a meaningful stream of revenue as a capacity payment. This is because the marginal plants (e.g., the last few generators needed to support reliability) would need to increase their bids above their costs in order to earn a sufficient margin when they are called upon to generate to cover their going-forward costs. In low load hours, however, there is an abundance of capacity present in the marketplace, and prices are more likely to be driven to marginal cost.

    Volatility in the spot market affects pricing in the forward market and for options. Because of the volatility in spot prices, marginal generators, who might not be expected to run but for a few hours, may be able to sell call options for power with high strike prices. These options may, or may not, actually be "in the money," but market participants may be willing to buy these call options as a hedge against the possibility of even higher market prices.

    These contracting mechanisms, fostered from volatile spot prices, provide the means for some of the marginal plants to recover their going forward costs. They also provide the mechanism for the market to secure an economic level of reserves to meet peak demand. In addition to option contracts and energy prices being set above the marginal cost of the price setting plant, generators can also be compensated for capacity through ancillary services.

    Even in markets with capacity obligations and a traded capacity market, energy prices have been quite volatile. This price volatility stems from an intrinsic characteristic of electricity: because there is no inventory, electricity must be produced in real time. This means that errors in forecasting demand or plant commitment, failures in equipment, and market perceptions amplify price movements. This has led to electricity having the most volatile spot prices of any commodity traded.

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    3.2.3  Forecasting Generation Service Prices

    Irrespective of where the debate on the future and viability of capacity markets lies, PHB Hagler Bailly produces forecasts of generation service prices by examining two components of value in our fundamental analysis:

    Compensation for capacity may take many forms. Payments could be in the form of a capacity price arising from a capacity market, a regulated payment fee, bilateral option contracts, payments by the ISO for ancillary services, or in the form of energy prices above the marginal cost of the price-setting plant. Regardless of the form, the sum of the compensation for capacity and the market price for energy will ultimately reflect what customers are willing to pay for both energy services and reliability. It is PHB Hagler Bailly's belief that the majority of the compensation for capacity actually arises through energy prices that are higher than marginal cost (and hence our energy price forecast) for some substantial portion of hours.

    Actual market price results support this belief. Figure 3-1 presents a graph of market prices in the PJM market in February 2000. This month was selected since it is one of the lowest load months in PJM, and prices should not be reflecting much in the way of a "scarcity premium" associated with insufficient generation to cover demand.

    What is abundantly clear is that generators do not simply bid their marginal cost of generation under all circumstances, or else one would expect that the price results in Figure 3-1 would be closely clustered around the line representative of marginal cost. Rather, there is considerable dispersion in the data, particularly in the higher load hours where marginal generation has a greater ability to support a price above marginal cost.

    The terms "compensation for capacity" and "energy price" as used in this report reflect the prices needed by the marginal units to recover their variable and going-forward costs. These prices together form the all-in price received by generators to meet all of their going-forward costs. Compensation for capacity and energy prices are inversely related; as one rises the other falls, so that the all-in price remains somewhat in balance.

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Figure 3-1
Price vs. Load—PJM West, February 2000

     LOGO

3.3 APPROACH TO MARKET PRICE FORECASTING

    Projecting electric market prices (and generation product sales) requires PHB Hagler Bailly to consider not only price formation in the market, but also the issues of market entry and exit. Figure 3-2 provides a graphical view of PHB Hagler Bailly's process for producing electric market price forecasts. The process begins with a definition of the characteristics of the market, including the electric generating units currently in operation, their production efficiencies (including heat rate curves), a projection of plant additions (based, in part, on announcements and, in part, on an equilibrium evaluation of market price signals and new investments), consumer demand and load, and generation fuel prices.

    Thus, this process develops prices based on a dynamic examination of market entry and exit (including retirement) decisions made by the supply-side players in the market. The following sections will briefly discuss PHB Hagler Bailly's approach to each of these steps.

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Figure 3-2
Approach to Developing Compensation for Capacity and Energy Prices

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    3.3.1  Market Characteristics

    The first step is to understand the nature and parameters of the market and the generation assets that participate in that market. PHB Hagler Bailly uses a variety of data sources to characterize the market. These include:

    3.3.2  Predicting Energy Prices and Dispatch

    PHB Hagler Bailly uses a detailed chronological production-cost model to simulate energy price formation in the market area of interest based on short-run marginal costs.

    From the energy price analysis, PHB Hagler Bailly determines the net energy margins (price minus variable cost) for each generating unit in the market. These margins, along with estimates of "going-forward costs," are used in the Capacity Compensation Simulation Model to predict the additional margins related to the provision of capacity.

    3.3.3  Predicting Prices Related to Capacity: The Capacity Compensation Simulation Model

    Compensation for capacity is a mechanism for supporting an appropriate amount of generating capability in the system. There are two reasons for including a measure of the compensation for capacity or shortage payment in the projection of market prices. First, if generators bid their short-run marginal costs into an energy market, only inframarginal plants (those not on the margin) earn a contribution toward their going-forward costs. Plants at the top of the supply curve receive little, if any, contributions toward their going-forward costs. In addition, some of the baseload and cycling plants

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that are not at the top of the supply curve but have high going-forward costs may not earn a sufficient operating margin from the energy market alone to cover all of those costs.

    PHB Hagler Bailly predicts a value for compensation of capacity using PHB Hagler Bailly's proprietary Capacity Compensation Simulation Model. This model presumes that the market will retain a sufficient amount of capacity to meet economic reliability targets. In other words, PHB Hagler Bailly simulates a capacity market consisting of a supply curve and a demand curve for reliability (or capacity) services. PHB Hagler Bailly assumes a competitive market, and that the market-clearing compensation for capacity is determined by the intersection of the supply and demand curves. PHB Hagler Bailly constructs supply and demand curves for each year in the simulation time horizon.

    The supply curve is developed based on all of the generators in the market. For each generating unit, the net of going-forward costs and energy market margins, expressed on a per-kilowatt basis, are calculated. These net costs represent the minimum amount a generating unit needs to go forward. Ranking these net costs in ascending order produces a supply curve for capacity.

    Next, the demand curve is estimated. The demand curve is estimated by representing the capacity associated with a target reliability level. The demand curve is a vertical line derived using a target reserve margin or target level of installed capacity.

    Finally, the intersection of the demand curve and the supply curve represents the capacity contribution that the market would support in that year. The capacity contribution forecast is the capacity payment derived for each year of the study period. A sample supply and demand curve for a hypothetical year is shown in Figure 3-3.


Figure 3-3
Example Supply and Demand Curve

     LOGO

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    3.3.4  Market Entry and Exit

    It is necessary to assess the feasibility and timing of new capacity additions as well as the exit of uneconomic existing capacity. PHB Hagler Bailly's proprietary modeling approach serves two purposes:

    Capacity additions through 2002 are based on known, planned additions. Thereafter, PHB Hagler Bailly's approach uses a financial model to assess the decision to add new capacity and to retire existing capacity. The approach to plant additions is based on a set of generic plant characteristics, financing assumptions, and economic parameters. This "add/retire" analysis is an iterative process performed simultaneously with the development of the energy price forecast and the projected compensation for capacity.

    The methodology assesses the feasibility of annual capacity additions based on a Discounted Cash Flow (DCF) model using net energy revenues determined in the production-cost simulations and compensation for capacity determined from the Capacity Compensation Simulation approach. For each increment of new capacity, a "Go" or "No Go" decision is made based on whether the entrant would experience sufficient returns (developed in the DCF model) to merit entry. In addition, economic retirement decisions are made at each step in the iterative process based on the specific financial and operating characteristics of the existing plant.

    The iterative process begins with the addition of new capacity when needed. A production-cost run is executed to determine energy prices, dispatch, and operating costs. The Capacity Compensation Simulation is then performed. Results for energy and capacity compensation are combined in the DCF model to determine whether the new unit is a "Go" or "No Go." If the new unit is a "Go," another new unit is added in that year and the process repeated. This occurs until the next new unit returns a "No Go." Should the analysis show "No Go," the unit is removed (e.g., not added).

    Annual retirements are determined after new units are added for that year. A financial analysis of each unit is performed beginning in 2002, combining the results of the energy and capacity compensation. If the operating profit (loss) for an existing unit is negative for any five-year consecutive period, it is retired at the end of the third year of consecutive operating loss. Although the decision criterion is somewhat subjective, it is interpreted conservatively. Thus, if a unit loses money for two years, is profitable over the third year, and then loses money for two more years, the unit is maintained online.

    If units are retired, the iterative process begins again with the addition of new capacity. In this way, the introduction of new units influences the retirement of existing units, and the retirement of existing units enables the introduction of new units. Since the addition of new units is "lumpy," the iteration generally stops with new generators earning a small increment above their cost of debt and equity. The addition of one more new unit then pushes many of the previous additions into losses. This process is repeated chronologically through the end of the analysis for each year continuing to show a deficiency after the most recent new unit addition. This approach reflects a game theoretic concept of market equilibrium.

    The standard method for valuing specific electric generating units uses discounted cash flows constructed from production-cost models. By simulating regional electricity operations, production-cost models weigh the fundamental drivers of market supply and demand, with detailed attention to supply.

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By aiming at cost, production-cost models can potentially miss the true target, price. Further, production-cost models may underestimate the volatility of electricity prices. This is illustrated by a comparison of historical prices from the spot market (Figure 3-4) with forecast prices from a production-cost model (Figure 3-5). Note that both the means and the variations of prices from the production-cost model are lower than the actual market for the same time period.


Figure 3-4
PJM Hourly Energy Prices, Summer 1999

LOGO


Figure 3-5
PJM Hourly Energy Prices, Production-Cost Model, Summer 1999

     LOGO

    Electric generating units can respond to volatility in electricity prices by increasing output (and revenues) when market conditions are favorable and decreasing output (and costs) when market conditions are unfavorable. The consequence is that valuation methods based on production-cost

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modeling tend to underestimate the value of cycling (i.e., midmerit) and peaking electric generating units.

    To demonstrate why analyses based on conventional production-cost model simulations may underestimate the effects of price volatility, we present the following simplified example of a power system dispatch for a single hour.

    In a competitive electricity market, a number of key variables determine the price of electricity, all of which involve varying degrees of uncertainty, including:

    However, analyses done with conventional production-cost models only represent generator forced outages as random variables. Among the other random variables, hourly demand has one of the largest impacts on price uncertainty and hour-to-hour volatility.

    Conventional production-cost models typically represent hourly demand as a certain, known quantity, as illustrated in Figure 3-6a. A more realistic representation is that demand is a random variable drawn from a continuous probability distribution. To make the calculations transparent in this example, PHB Hagler Bailly will approximate the continuous distribution of demand with the discrete distribution shown in Figure 3-6b.

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Figure 3-6
Two Different Approaches to Modeling Hourly Demand

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    Based on the representation of expected demand, shown in Figure 3-6a, and the target generator's cost curves, a conventional production-cost model will simulate the system hourly dispatch as shown in Figure 3-7.

    In this example, the Hourly System Marginal Price is $20.50/MWh, at which price the target generating unit runs at full output because its marginal cost at that output is only $20.00/MWh. Thus, the unit is projected to earn an operating profit of $100 in that hour. Because the inputs to the model are expected values, the outputs, including the candidate unit's revenues, are assumed to also be expected values. This is not necessarily true, as is discussed below.

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Figure 3-7
Dispatch Results Simulated by a Conventional Production-cost Model

     LOGO

    Now, consider what actually happens in the real world when demand uncertainty manifests itself. Representing the possible states of the demand variable as shown in Figure 3-6b, and combining that with the target generating unit's cost characteristics, yields the results shown in Table 3-1. Because the operator has the flexibility to adjust the output of the plant to avoid losses and capture margins, the expected value of the margin is greater than the result captured in the production-cost model.


Table 3-1
Possible Target Generating Unit Profit Levels

 
   
   
  Target Generating Unit
Likelihood

  Demand (MW)
  System Marginal
Price
($ per MWh)

  Sales (MWh)
  Average Cost
($ per MWh)

  Profit Margin
($ per MWh)

  Profit
($)

10%   28,000   $ 19.50   0   $ 20.00   $ (0.50 ) $ 0
20%   29,000   $ 20.00   200   $ 20.00   $ 0.00   $ 0
40%   30,000   $ 20.50   200   $ 20.00   $ 0.50   $ 100
20%   31,000   $ 21.00   200   $ 20.00   $ 1.00   $ 200
10%   32,000   $ 21.50   200   $ 20.00   $ 1.50   $ 300
Expected Value   30,000   $ 20.50                   $ 110
Production-cost Result   30,000   $ 20.50   200   $ 20.00   $ 0.50   $ 100

    Examining Table 3-1 provides insights into the value of volatility. If load in the area is 28,000 MW, the resulting market-clearing price is $19.50 per MWh. The margin for the plant at that load level is negative (the costs are greater than the revenue), so the plant operator would not operate the plant if that were the result. At 29,000 MW of load, the price is $20.00 per MWh. At this load level, the price is established by the bid submitted by this plant, and the plant is dispatched to its full load. However, it makes no money—its revenues are exactly equal to its costs. But at higher load levels, the generation unit makes money, and will be started and ramped to full load.

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    The conventional production-cost model presumes that the load is certain and, hence, the resulting prices are certain. Since prices are, in reality, uncertain, the production-cost model misses the flexibility the generation unit may have to respond to prices as they are revealed. This flexibility can provide tangible value that is in excess of the value calculated by the production-cost model. In this simple example, the value of the plant is 10% greater than that estimated by the production-cost model.

    Note that this increase in value depends on two conditions. First, the plant must have the ability to respond to prices. The greater the flexibility, the greater the potential value the plant can extract by adjusting its operating strategy to take advantage of favorable prices while minimizing the losses from unfavorable prices. Second, the plant must be subject to price volatility that actually causes it to alter its operating strategy. A plant that is either so low cost or so high cost that it never would adjust its operating strategy has no option value or may have a negative option value (as compared to the fundamental model). It is only by adjusting its operating strategy that a plant will accrue value from price volatility. Hence, a plant that sets the price (is "at the money") will have higher volatility value than a plant with similar flexibility, but which has lower or higher operating cost.

    A key feature of electricity markets, currently and in the future, is volatility in prices. This volatility stems most directly from the fact that electricity has to be produced in real time with few storage opportunities. In fact, electricity is among the most volatile commodities traded in the world. To ignore price volatility is to ignore one of the most important aspects of the wholesale electricity markets.

    PHB Hagler Bailly has developed a proprietary market valuation process, MVPSM, to estimate the value of electric generation units based upon the level of prices and their volatility. As shown in Figure 3-8, MVP is a two-step process. The first step is to characterize the volatility in prices, while the second step examines how the generation unit responds to those prices and derives value from operational decisions.


Figure 3-8
PHB Hagler Bailly's Market Valuation Process (MVPSM)

LOGO

    Note that MVP does not replace the use of a production-cost model. The production-cost model provides insights into the fundamental drivers (such as fuel prices, demand, entry, and exit) that a volatility analysis cannot address. MVP integrates the two approaches to create a better estimate of the value a generating unit by accounting for both volatility effects and changes in the fundamental drivers of electricity prices.

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    MVP uses a real option approach to value electric generating capacity, and thereby captures the value of price volatility. An electric generating unit can be viewed as a strip of European call options on the spread between electricity prices and the variable cost of production (which is largely fuel). Unlike most option analysis, however, a generation unit does not have perfect flexibility to adjust to the price-cost spread. A generation unit may have costs that must be incurred to start up as well as constraints on its operation that may limit its ability to capture margins when the spread is positive (price is greater than variable cost) or avoid losses when the spread is negative (variable cost is greater than price). Hence, the second step of MVP focuses on the ability of the generation unit to capture margins given its cost structure and constraints on operation.

    The steps to the approach are as follows:

    Different generating units have different capabilities of responding to electricity and fuel price volatility. Thus, the same price patterns for electricity and fuel may yield different option values for different generating units, depending on the operating costs and characteristics of the generating units. Those generating units with the greatest flexibility to respond to different market prices and that often set energy prices will have the highest option values, while those plants that never set energy prices have little or no ability to respond and will have virtually no option value.

3.4  APPLYING THE MVPSM APPROACH TO THE NGC PORTFOLIO

    We used historical NEPOOL hourly price data from May 1, 1999 through June 1, 2000 to estimate the statistical parameters that characterize the observed pattern of NEPOOL hourly prices. We also estimated a stochastic model for gas prices, based on the records of daily gas prices for NYPP Citygate, as this gas market drives gas prices in NEPOOL. These statistical models were used in combination with a forecast of gas prices from the fundamental analysis and historical temperature records for NEPOOL to generate a set of 100 different price paths describing the possible evolution of NEPOOL hourly electricity prices.(4)


(4)
These price paths are based on the set of market assumptions embodied in the fundamental analysis—with different fundamental assumptions, the hourly prices will change.

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    This process yields hourly electricity prices(5) from 2001 to 2010, and for 2015 and 2020. For 2001, the forecast prices were replaced with NEPOOL electricity forwards. The prices in 2002 and 2003 were adjusted to trend between these forwards and the fundamental analysis results in 2004.

    To ensure consistency between the fundamental analysis and the volatility analysis, we calibrated the stochastic price forecasts so that both current marginal units as well as potential marginal units in the future (new combined cycles and combustion turbines) covered their going-forward costs.(6) For this analysis, we calibrated to a series of NEPOOL steam units for 2004 through 2006, and to a generic combined cycle from 2007 onwards. No calibration was required for 2001 through 2003, as these prices are based on the electricity (and gas) forwards.

    Calibration preserves the properties of the fundamental results—that is, if substantial additional margin were available to the marginal unit when considering volatility, then additional entry might be warranted. On the other hand, if the marginal units were not to recover their going-forward cost, then additional unit retirements are likely. In either case, such a result would represent a market that was not in equilibrium. For NEPOOL, the method of calibration adjusted summer and winter peak prices in a systematic manner so that the net revenues obtained for these units in the energy market(7) would cover the going-forward costs of the units.

    In Chapter 5, we describe how our analysis was carried out for three different sets (cases) of future NEPOOL market conditions. The three cases reflect different gas price forecasts and different levels of installed capacity, and so each case requires a different set of calibrated hourly prices.

    As some of the units (particularly the Northfield Mountain pumped storage facility) are important suppliers of ancillary services in the New England market, we needed to forecast prices for ancillary services. For this analysis, ancillary services prices were modeled as a function of energy prices, day of the week and peak and off-peak variables. We used NEPOOL historical data to estimate the values of the model parameters.

    For our analysis, we found that we could estimate Ten Minute Spinning Reserve (TMSR) prices from our forecast of energy prices along with chronological information. For Automatic Generation Control (AGC), from NEPOOL historical data we were unable to find a statistically-appropriate relationship between AGC prices and energy prices. We found that AGC prices demonstrated a distinct hourly pattern during the day and tended to be lower on weekends. As a result the AGC prices were modeled to be a function of the time of day and the day of the week.


(5)
As discussed in Section 3.1, a key characteristic of the Northfield pumped storage plant is its ability to arbitrage movements in electricity prices. Northfield uses low-cost (generally off-peak) electricity to pump water from a lower reservoir into an upper reservoir, and then uses the stored water to generate and sell electricity when power prices are much higher (generally during on-peak hours). Northfield's energy margins result from the difference between power prices when Northfield is pumping and generating, after accounting for efficiency losses of about 35% associated with this process. Since Northfield's profitability is driven by the differential between on-peak and off-peak power prices, it is important to use a forecasting methodology that accurately reflects the hourly changes in electricity prices in order to produce a realistic estimate of Northfield revenues.

(6)
The calibration for future marginal units meant that a new CC would recover its going forward cost in most years. For a new CT, this calibration meant that a substantial portion of the going forward cost would be recovered in most years.

(7)
Assuming the units are selling as merchant plants into the spot market.

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    As noted above, for both TMSR and AGC prices the model parameters were estimated from NEPOOL historical data and these parameters along with chronological information were used for price forecasting. Additionally we also imposed a restriction on the ancillary services prices such that these prices do not exceed the energy price for any given hour, as is required by the New England ISO.

    In our analysis, we considered four types of revenue for the units in the NGC portfolio:


In our analysis of the operation of the assets, we modeled the provision of TMSR and AGC, where the historical record of revenues for these assets indicate the majority of ancillary services revenues will be derived. Although the units may also be bid into other ancillary services markets (Ten Minute Non-Spinning Reserve, Thirty Minute Operating Reserve) we have not modeled this as it is a small part of their potential revenue.

    For each case, energy revenues for the NGC portfolio were estimated by dispatching the various units against the series of hourly prices generated from the volatility analysis.

    For the hydro units, this was done on the basis of the historical generation patterns combined with the forecast of energy prices for each case.

    For the Northfield pumped storage station, PHB Hagler Bailly developed a dispatch model for a pumped storage station that considered energy and ancillary service revenues together. The energy revenues estimated for Northfield also included the opportunity cost payments to Northfield when the New England ISO "postures" the Northfield units, i.e., holds the station in reserve as a system safeguard. This has historically occurred 1-2 days a year, usually when loads are high and some large unit or units have suffered forced outages.

    The revenues for the Tunnel CT were estimated using a thermal unit dispatch model also developed by PHB Hagler Bailly.

    To participate in the TMSR market, units must be synchronized with the system. In this analysis the Northfield pumped storage unit can provide spin during all time periods. TMSR can also be provided by a number of the smaller hydro units, but these are more restricted in terms of when they can provide spin and the quantity of spin available.

    Ten minute spinning reserve revenues for the hydro units were calculated based on historical revenues. For Northfield, ten minute spinning reserve revenues were calculated from the same dispatch model that estimated energy revenues. This ensures that ten minute spinning reserve revenues are consistent with the energy dispatch of the Northfield units.

    The Northfield pumped storage unit is very well situated to provide AGC in the NEPOOL market given that its marginal cost of providing AGC is nearly zero as compared to other units which have

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efficiency losses associated with providing AGC. As a result Northfield is assumed to be a large player in the AGC market and provides this service based on the number of units it has operating during any given hour. It may only provide AGC during hours it is generating.

    AGC revenues for Northfield were calculated based on the NEPOOL rules defining AGC payments. For this analysis, we combined the historical pattern of AGC provision for 1999-2000 with a forecast of AGC prices derived from a statistical analysis of past AGC prices, as discussed previously.

    The New England ISO has stated that there is a need for additional quickstart capability in the New England market.(8) In the course of forecasting future NEPOOL electricity prices, we discussed with the New England ISO the level of peaking capacity required in NEPOOL to provide adequate quickstart capability. It was the view of the New England ISO that there was insufficient quickstart capability from combustion turbines and similar units to support system reliability. As part of our analysis, we estimated the revenues that would be earned by a new combustion turbine from the calibrated hourly prices derived from the volatility analysis. Typically, we found a new combustion turbine would earn $49-57/kW-yr from this energy market, which is not sufficient to meet the carrying cost of around $70/kW-yr (see Chapter 4) for these units. Consequently, it appears that long-run market equilibrium will require additional revenue to be earned by these units to ensure adequate entry of needed quickstart peaking units. As the financial mechanism for providing this quickstart support is unclear, for each year we have estimated this revenue stream as the difference between the carrying cost of a generic combustion turbine and the revenues earned by the combustion turbine in the energy market for that year in Case 1. We have presumed that the generation owner and the ISO enter into some sort of contractual arrangement specific to quickstart units. Thus, the support payment is not dependent on the scenario under consideration.

    The significance for this analysis is that the Northfield pumped storage unit, because of its operational characteristics, would be able to earn such quickstart revenues. The Tunnel 10 combustion turbine would also earn these revenues.


(8)
Letter from NE-ISO to NEPOOL participants dated April 3, 2000, and Minutes of NEPOOL Participants Committee (March 3, 2000).

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CHAPTER 4

ASSUMPTIONS

4.1  INTRODUCTION

    This chapter describes the key assumptions used in the development of the annual energy and capacity market price forecasts. Based on the assumptions below, PHB Hagler Bailly simulates the hourly market-clearing price of energy using MULTISYM,(1) a production-costing framework that allows the characterization of multiple pricing areas within larger transmission regions. Each major generating unit within a transmission area is represented individually in the MULTISYM production-costing model using unit-specific cost and operating characteristics. The MULTISYM model is used to perform an hour-by-hour chronological simulation of the commitment and dispatch of generation resources. As discussed in Chapter 3, the output of this model is then used in PHB Hagler Bailly's Capacity Compensation Simulation Model to develop the annual capacity contribution. In the NEPOOL market, volatility is also analyzed based on the specific assumptions used in the Market Valuation Process (MVPSM).

4.2  GENERAL ASSUMPTIONS

    The following general assumptions were utilized in this study:

4.3  PRICING AREAS

    The pricing areas used in the MULTISYM analysis of the hourly energy markets are defined as follows:

NPCC/MAAC Pricing Areas

NYPP-East   NEPOOL-South East
NYPP-West   NEPOOL-Maine
NYPP-In-City   NEPOOL-West
NYPP-Long Island   Ontario
PJM-East   Quebec
PJM-Central   New Brunswick/Nova Scotia.
PJM-West    

    A list of the major utilities in each pricing area is provided in Appendix A.

4.4  FUEL PRICES

    All fuel types were analyzed on either a regional (natural gas and oil) or plant location (coal) basis in order to capture pricing variations among major delivery points. The forecast prices for each fuel includes the cost of transportation to the power plant site.


(1)
MULTISYM is a product developed by Henwood Energy Services, Inc. (HESI).

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    4.4.1  NATURAL GAS

    The primary inputs into the analysis were forecasts(2) from The Energy Information Administration (EIA),(3) The Gas Research Institute (GRI),(4) The WEFA Group (WEFA) and Standard and Poor's (S&P). Table 4-1 outlines the Henry Hub projection from each of the four source forecasts as well as the consensus forecast of natural gas prices at the Henry Hub.

 
  Table 4-1
Henry Hub Projections (Real 2000 $/MMBtu)

 
 
  2000
  2005
  2010
  2015
  2020
  Average Annual
Growth Rate

 
EIA   2.56   2.76   3.06   3.19   3.31   1.29 %
GRI   2.44   2.15   2.09   1.97   1.85   -1.37 %
WEFA   2.65   2.50   2.70   2.79   2.86   0.38 %
S&P   2.61   2.24   2.36   2.57   2.75   0.26 %
Consensus   2.56   2.41   2.55   2.63   2.69   0.25 %

(2)
EIA, Annual Energy Outlook 2000, December 1999; GRI 2000 Baseline Projection, November 1999; The WEFA Group, Natural Gas Outlook 2000, April 2000; S&P Platt's US Energy Outlook, Fall-Winter 1999-2000.

(3)
The EIA does not explicitly forecast a Henry Hub price. The EIA Henry Hub projection is an estimate based on the EIA lower-48 wellhead price forecast and the historic relationship between that wellhead price and the Henry Hub price.

(4)
The GRI forecast includes price projections only through 2015. The 2020 price is an estimate based on the 2015 price and the GRI price escalation pattern from 2010 to 2015.

    While these forecasts represent industry standard market information on long-run equilibrium price, the natural gas market can exhibit extended periods where supply and demand are not in balance and prices can fluctuate significantly. The recent unprecedented price levels indicate that the market is currently in just such a period of transition. As a result, PHB Hagler Bailly also has modeled near term prices based on recent actual spot prices and futures prices through December 2001, trending back to the long-term consensus view by 2003. Table 4-2 displays the near term price projection.

Table 4-2
Henry Hub Projections Using NYMEX Prices(1)
(real 2000 $/MMBtu)

Year

  Henry Hub Projection
2000   3.65
2001   3.67

(1)
Based on NYMEX futures prices on 7/10/2000.

    Regional prices throughout the United States were projected based on this consensus Henry Hub forecast. For all regions modeled, the delivered price is the sum of the Henry Hub projection, the projected regional basis differential, and other natural gas supply costs including all taxes.

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    The Henry Hub forecast is used as a basis for projecting regional market center prices. The Henry Hub forecast, plus the basis differential to a particular region, equals the commodity component of each region's natural gas forecast. Regional market prices for natural gas are based PHB Hagler Bailly on this Henry Hub forecast and historic (1994-1999) and projected spot price differentials. Projected changes in the basis differentials are a result of increased integration of natural gas supply centers, changes in regional demand levels, and increased deliverability in some areas resulting from new pipeline construction. The regional reference hub assignments used in the analysis are summarized in Table 4-3.

Table 4-3
Reference Hub Assignments for Differential Analysis

Region
  Reference Hub
  GRI Region
PJM East   NY Citygate   Middle Atlantic
PJM West   Pittsburgh Citygate/CNG North   Middle Atlantic
PJM Central   Average of PJM East and PJM West   Middle Atlantic
New York-East(1)   NY Citygate   Middle Atlantic
New York-West   Pittsburgh Citygate/CNB North   Middle Atlantic
NEPOOL(2)   Boston Citygate   New England
Canada   Parkway Dawn Ontario   New England

(1)
Includes In-City and Long Island transmission areas.
(2)
Comprised of Maine, Southeast, and West transmission areas.

    In addition to the regional commodity cost, natural gas price inputs also include an additional liquidity premium designed to account for the fact that units are not necessarily located at a major trading hub. As a result, units are likely to pay some premium over prices available at major pipeline intersections. This premium is expected to remain constant at $0.05/MMBtu ($2000) over the forecast horizon.

    As electric industry deregulation pressures generators to reduce costs, new gas-fired applications will be located so as to minimize fuel costs. As a result, new capacity will have an incentive to locate on the interstate pipeline system in order to avoid both Local Distribution Company (LDC) charges and operating pressure concerns. Therefore, it is assumed that new plants will be sited to take advantage of direct connections to interstate pipeline systems. Existing units in the model are assumed to incur LDC charges. The LDC charge is assumed to be $0.10/MMBtu in 2000 declining to $0.05/MMBtu by 2020. In addition, New York City units pay an additional tax on all natural gas consumed.

    Some baseload gas-fired plants, however, may incur fixed costs to ensure firm natural gas supplies. The EIA projects that as industry restructuring increasingly puts pressure on generators to reduce costs, generating stations will rely on interruptible deliveries and will ensure fuel supplies by using oil as a backup fuel(5). The total delivered price of natural gas in each market region is presented in Table 4-4.


(5)
EIA, Challenges of Electric Power Industry Restructuring for Fuel Suppliers, September 1998, p. 65.

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Table 4-4
NPCC/MAAC Delivered Natural Gas Price (real 2000 $/MMBtu)(1)

Pricing Area

  2000(2)
  2005
  2010
  2015
  2020
  Average Annual Growth
Rate

 
PJM East   3.25   2.93   3.07   3.15   3.22   -0.05 %
PJM West   3.19   2.82   2.96   3.05   3.11   -0.13 %
PJM Central   3.27   2.92   3.07   3.15   3.22   -0.08 %
New York-East(3)   3.29   2.97   3.12   3.20   3.26   -0.05 %
New York-West   3.14   2.78   2.92   3.00   3.07   -0.11 %
New York—In City   3.37   3.04   3.19   3.27   3.34   -0.04 %
NEPOOL(4)   3.43   3.05   3.19   3.28   3.34   -0.14 %
Canada   3.05   2.84   2.99   3.07   3.14   0.15 %

(1)
The prices shown represent the prices for existing units. New units are assumed not to pay LDC charges of $0.05/MMBtu to $0.10/MMBtu.
(2)
The 2000 delivered price is based off the consensus Henry Hub. Prices are adjusted upward for the NYMEX analysis.
(3)
Includes the Long Island transmission area.
(4)
Comprised of Maine, Southeast, and West transmission areas.

    Natural gas prices exhibit significant and predictable seasonal variation. Consumption increases in the winter as space heating demand increases and falls in the summer. Prices follow this pattern as well; the seasonal pattern is most striking in cold weather locations. Dispatch prices in the model reflect the seasonal effects based on 5-year historic price patterns exhibited at the regional market centers.

    4.4.2  FUEL OIL

    The fuel oil forecast methodology is described below for No. 2 Fuel Oil and No. 6 Fuel Oil. Prices are developed based on a consensus of crude oil by major forecasters as presented in Table 4-5.(6) These widely used sources present a broad perspective on the potential changes in commodity fuel markets. Each forecast was equally weighted in an effort to arrive at an unbiased consensus projection of fuel prices.

Table 4-5
Crude Oil Price Projection (real 2000 $/bbl)

 
  2000
  2005
  2010
  2015
  2020
  Average Annual Growth
Rate

 
EIA   21.92   21.19   21.72   22.27   22.80   0.20 %
GRI   18.42   18.42   18.42   18.42   18.42   0.00 %
WEFA   24.22   18.74   18.84   19.80   20.81   -0.76 %
S&P   21.14   16.50   17.32   19.31   20.72   -0.10 %
Consensus   21.42   18.71   19.07   19.95   20.68   -0.18 %

(6)
The source forecasts are as follows: 2000 Annual Energy Outlook, EIA; 2000 Baseline Projection, GRI; 2000 Natural Gas Outlook, WEFA; Standard & Poor's World Energy Service U.S. Outlook, Fall-Winter 1999-2000.

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    As is the case with natural gas, today's oil markets are in a period of transition as OPEC wrestles with its production targets. As a result, PHB Hagler Bailly has modeled a case in which near term model inputs reflect recent actual oil prices and futures prices through December 2001, rather than the long-run equilibrium price. In this case, prices return to the long-run consensus by 2003. The near term price projection is shown in Table 4-6.

Table 4-6
Crude Oil Price Projection Using NYMEX Prices(1)
(real 2000 $/MMBtu)

Year

  Price Projection
2000   27.61
2001   25.37
2002   23.51

(1)
Based on NYMEX futures prices on 7/10/2000.

    Prices for No. 2 Fuel Oil were derived from EIA data on historical delivered-to-utility prices for the period 1994 through 1998, on a regional basis. Fuel costs are comprised of commodity costs and transportation costs. Each region in the analysis was assigned to a reference terminal as shown in Table 4-7. The commodity component is calculated by escalating the historic reference terminal prices at the escalation rate implicit in the crude oil forecast outlined in Table 4-5.


Table 4-7
Reference Terminal Assignments for No. 2 Fuel Oil Analysis

Region

  Reference Terminal

PJM East   Baltimore
PJM West   Pittsburgh
PJM Central   Average of PJM East and PJM West
New York-East(1)   New York
New York-West   New York
NEPOOL(2)   New York
Canada   New York

(1)
Includes In-City and Long Island transmission areas.

(2)
Comprised of Maine, Southeast, and West transmission areas.

    Transportation costs are calculated as the 5-year average premium for delivered fuel oil in each region above the market center price for the terminal assigned to that region. This transportation cost is held fixed over the forecast horizon. This methodology captures both the commodity and transportation components of delivered costs. Representative final delivered price for No. 2 fuel oil is provided in Table 4-8.

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Table 4-8
NPCC/MAAC Delivered No. 2 Fuel Oil Price (real 2000 $/MMBtu)

Pricing Area

  2000(1)
  2005
  2010
  2015
  2020
  Average Annual Growth Rate
 
PJM East   5.03   4.42   4.50   4.70   4.86   (0.17 )%
PJM West   5.20   4.57   4.65   4.86   5.03   (0.17 )%
PJM Central   5.20   4.56   4.65   4.85   5.02   (0.18 )%
New York-East(2)   5.61   4.98   5.07   5.27   5.44   (0.15 )%
New York-West   5.61   4.98   5.07   5.27   5.44   (0.15 )%
NEPOOL(3)   5.15   4.50   4.59   4.80   4.97   (0.18 )%
Canada   5.10   4.45   4.53   4.74   4.92   (0.18 )%

(1)
The 2000 delivered price is based off the consensus Henry Hub. Prices are adjusted upward for the NYMEX analysis.

(2)
Includes In-City and Long Island transmission areas.

(3)
Comprised of Maine, Southeast, and West transmission areas.

    Prices for No. 6 Fuel Oil were derived using an identical methodology as that employed for No. 2 Fuel Oil prices. Because residual oil is so thinly traded, it is difficult to identify significant regional price premiums. As a result, all eastern regions were assigned to the New York Harbor reference terminal and all regions in WSCC were assigned to the U.S. Westcoast reference terminal. As a result, commodity prices for all regions were based on 1% sulfur residual oil at New York Harbor and are therefore the same. Transportation costs for each region, however, do vary.

    The transportation costs for each region were based on an analysis of historic New York Harbor prices and delivered residual oil at electric generating stations in the region. Transportation costs equal the 5-year average premium for delivered No. 6-oil in above the New York Harbor price. This transportation cost is held fixed over the forecast horizon. Final delivered prices for No. 6 Fuel Oil are listed in Table 4-9.


Table 4-9
NPCC/MAAC Delivered No. 6 Fuel Oil Price (real 2000 $/MMBtu)

Pricing Area

  2000(1)
  2005
  2010
  2015
  2020
  Average Annual Growth Rate
 
PJM East   3.28   2.88   2.94   3.06   3.17   (0.17 )%
PJM West   3.39   2.98   3.04   3.17   3.28   (0.17 )%
PJM Central   3.38   2.98   3.03   3.16   3.27   (0.17 )%
New York-East(2)   3.66   3.27   3.32   3.45   3.55   (0.15 )%
New York-West   3.66   3.27   3.32   3.45   3.55   (0.15 )%
NEPOOL(3)   3.28   2.88   2.93   3.06   3.17   (0.17 )%
Canada   3.21   2.80   2.86   2.99   3.10   (0.17 )%

(1)
The 2000 delivered price is based off the consensus Henry Hub. Prices are adjusted upward for the NYMEX analysis.

(2)
Includes In-City and Long Island transmission areas.

(3)
Comprised of Maine, Southeast, and West transmission areas.

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    Price projections for lower sulfur oil products(7) were also calculated to generate model inputs for regions that have more stringent environmental regulations. The premium for lower sulfur products was derived from a comparison of historic price data.

    PHB Hagler Bailly developed a forecast of marginal delivered coal prices and the corresponding SO2 allowance prices. The SO2 prices are presented in Section 4.7.1. PHB Hagler Bailly developed a base case forecast of annual average marginal delivered coal prices (in real dollars) for the period 2000 through 2020 on a unit-by-unit basis for electric generators in each region.

    In cost-based electric dispatch modeling, the marginal variable cost of production is expected to determine dispatch order and the wholesale market price of electricity. For this reason, PHB Hagler Bailly has provided marginal delivered coal prices. These prices reflect PHB Hagler Bailly's projection of a particular unit's marginal coal selection and market pricing for that coal, as well as the rate for transportation for such marginal purchases. If a particular unit purchases some higher-priced coal under long-term contracts, the unit's average cost of coal acquisition will be different from its marginal coal acquisition cost. It is expected that the cost of higher-priced, contract coal will not be reflected in dispatch pricing or in market prices for electricity.

    Delivered coal prices were projected in two components: (1) coal prices at the mine (on a FOB(8) basis), and (2) transportation rates. Because individual units within a plant sometimes burn different coals, coal selection and delivered pricing was developed on a unit-by-unit basis.

    The projected coal selection for individual units reflects differing requirements for compliance with emissions regulations over time, as well as economics. To determine the selected coal, PHB Hagler Bailly considered the use of flue gas desulfurization equipment (scrubbers), requirements to comply with Phase I and/or Phase II of the Clean Air Act Amendments of 1990 (CAAA), and requirements for compliance with New Source Performance Standards (NSPS) and State Implementation Plan (SIP) limits, along with the variable costs of different methods of CAAA compliance. While a unit's historical coal selection was an important factor in the projections, substitutions of coal types were projected for some units over time as delivered price economics (including allowance prices) are expected to change.

    FOB mine prices were projected with consideration of productivity increases and supply and demand economics for different coal types in an integrated market analysis. The coal price forecast is conservative in that only approximately one-half of total historical total factor productivity improvements are reflected in projected price decreases. Real prices are expected to decrease over the forecast period for all of the major coal types, but the rate of decrease varies based on considerations specific to each coal type such as supply and expected depletion of reserves, market demand, and the sulfur content of the coals.

    In general, prices for low sulfur coals decline the least, and prices for mid sulfur coals decline the most. Low and mid sulfur coals currently receive a price premium relative to high-sulfur coals based on their lower sulfur content. However, higher SO2 allowance prices are expected to reduce demand for the mid-sulfur coals at unscrubbed plants, which will reduce the price difference between mid and high sulfur coals over time.

    Projected transportation rates are based on available delivery options at each plant for the coal types selected for each unit. Transportation modes included rail, barge, truck transportation, and


(7)
Includes 0.3% residual oil, low sulfur 2-oil, and jet fuel.

(8)
"Free on Board," indicating that the price includes the costs of loading coal onto a train, truck, or barge.

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conveyor transportation for minemouth plants. Rates for different transportation modes in different regions of the country are projected to vary at different rates over time. In cases where a multi-mode movement of coal is required (such as a combination rail and vessel movement), the rate for each mode of transportation is projected separately, and the total transportation rate is the sum of these separately escalated components.

    In addition, potential future changes in transportation options were considered. In some cases, for example, PHB Hagler Bailly projected the addition of rail or vessel receiving capability. Potential future rail regulatory relief was also projected for some plants without access to competitive transportation options.

    Region-specific coal forecast discussions are provided in greater detail in Appendix B.

4.5 DEMAND AND ENERGY FORECASTS

    The projected demand and energy forecasts are based on the following sources:

    The projected average annual demand and energy growth for the period 2000 through 2020 is summarized in Table 4-10.


Table 4-10
Projected Average Annual Load Growth Rates

 
  Average Annual Growth Rate
 
Region

 
  Demand
  Energy
 
NEPOOL   1.94 % 2.16 %

    The hourly data for the analysis is based on a synthetic hourly load shape based on five years of actual hourly data (1992-1996) provided with the MULTISYM production-costing model to represent the native load requirements for each of the pricing areas. The annual demand and energy forecast values are applied to the native hourly load requirements to develop the forecasted hourly loads for each year of the analysis.

4.6 ELECTRICITY IMPORTS

    Imports and exports between transmission areas are determined by the model using inputs for transfer capabilities, wheeling rates, and line losses. The transfer capabilities and wheeling rates between pricing areas are provided in Appendix C. Line losses between all pricing areas are assumed to be 2%.

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4.7 EXISTING GENERATION UNITS

    Each of the existing fossil generating units in the model is characterized using the following parameters:

    Summer and winter capability values were obtained from the following sources:

    Full load heat rate values are based on those reported in the 1995 EIA Form EIA-860.(9) This form contains data, including full-load heat rates, for existing electric generating plants and for new plants scheduled for initial commercial operation within 10 years of the filing of the report. PHB Hagler Bailly then made adjustments to the full load heat rate values reported in Form EIA-860 based on generic heat rate curve assumptions by unit type.

    Generating unit operating characteristics (i.e., minimum capacity, ramp rate, minimum uptime, and minimum downtime) were estimated by PHB Hagler Bailly based on typical characteristics by unit type.


(9)
EIA Form EIA-860, 1995, which is the most recent year the report was published.

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    The scheduled maintenance outage rates and equivalent forced outage rates for all fossil units were estimated by PHB Hagler Bailly based on historical data for comparable units contained in the GADS database.(10)

    Each generating unit's variable operation and maintenance cost is represented by PHB Hagler Bailly's default values. The values used are as follows: $4/MWh for scrubbed steam-coal units, $3/MWh for other steam-coal units, $2/MWh for steam-gas and oil units, $2/MWh for combined cycle units, and $5/MWh for peaking units (includes combustion turbine units, internal combustion units, and jet engines).

    Title IV of the Clean Air Act created a cap-and-trade program for SO2 emissions from electric generating plants. The program was implemented in two phases. Phase 1, which was implemented beginning January 1, 1995, covered a selected list of generating units emitting the largest quantities of SO2. SO2 emission allowances were allocated to these plants based on each unit's historical average utilization, and an average emission rate of 2.5 lbs. 502/MMBtu. Phase II, which began on January 1, 2000, covered all SO2 emitters and allocated SO2 emission allowances based on a lower average emission rate about 1.2 lbs. S02/MMBtu. The total quantity of SO2 emission allowances issued annually by the EPA is equal to the total national SO2 emission cap established by Congress. One allowance provides the right to emit one ton of SO2.

    SO2 allowances can be banked for use in future years or traded. Therefore, utilities can choose to reduce their emissions below the target levels and over-comply. If they over-comply, they can either save their excess allowances for future use or sell them. Other utilities can choose to operate their plants above the target emission levels and become net buyers of allowances.


Table 4-11
SO2 Cost Curves (real 2000 $/ton)

Year

  SO2
2000   $ 150
2001   $ 165
2002   $ 287
2003   $ 316
2004   $ 347
2005   $ 382
2006-2020   $ 420

    PHB Hagler Bailly estimated the SO2 allowance price by determining the allowance price by determining the allowance price needed to achieve the Phase II cap once the current bank of more than 10 million tons has been depleted. The forecast assumes that the operators of generating plants will choose the lowest cost compliance option available to them given the allowance price. Therefore, a combination of strategies will be used to meet the Phase II cap. Some units will use low capital and high variable cost solutions, such as switching to lower sulfur coals or using the same coal but reducing the loading on the units. Other units will install scrubbers, which is a high capital, low variable cost solution. The allowance price is the cost of removing the last or marginal ton of SO2. Both capital and variable costs are included in the estimates of SO2 removal costs. However, the dispatch decision is


(10)
North American Electricity Reliability Counsel, Generating Availability Data System (GADS), Equipment Availability Report (1994-1998).

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based only on variable costs. Therefore, a unit that chooses to install a scrubber may actually have its variable costs decline and its utilization increase. A plant that switches to a low sulfur coal may have its variable costs (including the cost of allowances) increase and its utilization decline.

    PHB Hagler Bailly's forecast of SO2 allowance prices is shown in Table 4-11. The price of SO2 allowances starts at $150 per ton in 2000, and increases to $420 per ton by 2006, with the largest annual increase occurring in 2002.

    The relatively low current prices for SO2 allowances (below our expected long-term value of allowances, on a discounted basis) reflects the accumulation of a large bank of SO2 allowances, which resulted from over-compliance with Phase I of the Clean Air Act SO2, and a number of political and regulatory uncertainties (including the outcome of the 2000 election, the outcome of the New Source Review litigation, and the Supreme Court's ruling on EPA's proposed fine particulate regulations) that could reduce the value of SO2 allowances. PHB Hagler Bailly expects that the outcome of these uncertainties will be known by 2002. Assuming that these issues are resolved in a manner that essentially preserves the current market-based regulatory system for SO2 (rather than moving toward command-and-control policies), and that additional regulations do not suppress SO2 prices, one would expect SO2 allowance prices to increase substantially from 2001 to 2002.

    The SO2 allowance price trajectories for 2001 and 2003-2005 reflect PHB Hagler Bailly's expectation that, since SO2 allowances are a relatively risky investment (due to the regulatory and political uncertainties mentioned above), they will generally escalate at a discount rate consistent with such risky investments. For this forecast, PHB Hagler Bailly has assumed a 10% expected annual real rate of return on holding "banked" allowances during these periods, which produces our price trajectories for 2001 and 2003 to 2005.

    The real cost of SO2 allowances is projected to plateau at $420 per ton for 2006 and later years. This price level is determined by the marginal cost of installing scrubbers at existing plants."(11) PHB Hagler Bailly estimates that this price level will be reached in 2006 because the "bank" of SO2 allowances will be almost fully depleted by 2006. (Only a small "bank" will remain, for transactional liquidity purposes.)


(11)
This assumes a continuation of current regulations under the 1990 Clean Air Act Amendments. As noted above, some proposals under consideration by EPA (such as controls on fine particulates) could change these regulations.

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    PHB Hagler Bailly's forecast of NOx allowance prices is shown in Table 4-12. This forecast includes both an estimate of NOx compliance costs for units in the Ozone Transport Region (OTR) for 2000-2002, and an estimate of the NOx control costs for all of the units affected by EPA's NOx State Implementation Plan (SIP) Call from 2003 forward.


Table 4-12
NOx Cost Curves (real 2000 $/ton)

Year

  NOx
2000   $ 700
2001   $ 1,000
2002   $ 1,000
2003-2020   $ 4,000

    The OTR includes 12 states, primarily in the Northeast. With some exceptions, affected NOx emission sources in this region were required to reduce NOx emissions either by 55%, or to 0.2 lbs. NOx/MMBtu (whichever is a lesser reduction) by May 1, 1999.(12) The region affected by the EPA's NOx SIP Call includes 19 states in the eastern half of the U. S. (i.e., most of the states east of the Mississippi River).(13)

    PHB Hagler Bailly's forecast of NOx allowance prices assumes that plants will purchase NOx allowances when their marginal cost (not their average cost) of abatement exceeds the expected price of emission allowances. Unlike SO2 allowances, NOx allowances are for a single season only.(14) Therefore, the forecasted allowance price for each year is based on the marginal cost of installing controls sufficient to meet the relevant NOx emissions cap in that year. The allowance price is determined by the marginal cost of installing the highest-cost technology required to meet the emissions cap. Under the OTR regulations, the highest-cost technology required to meet the emissions cap is Selective Non-Catalytic Reduction (SNCR). The highest-cost technology required to meet the tighter cap in the EPA's proposed SIP call regulations is Selective Catalytic Reduction (SCR).

    For each unit subject to these regulations, generating costs were estimated assuming that NOx emission costs were equal to the tons of NOx emitted after installation of applicable control technologies, multiplied by the price of allowances represented by the NOx forward-price forecast. The resulting NOx emission costs were added to the variable cost of each generating unit and included in the development of the energy price forecast. Any capital expenditure incurred was included in the generating unit's fixed costs and in the capacity compensation simulation.


(12)
Sources in the state of Maryland were exempted from these emission reduction requirements until May 1, 2000. A portion of the Ozone Transport Region is subject to slightly stricter requirements (to reduce emissions either by 65%, or to 0.2 lbs. NOx/MMBtu).

(13)
Georgia, Missouri and Wisconsin were recently exempted from the SIP Call Region, but we have assumed for modeling purposes that Georgia will be subject to the NOx program in 2004 and that Missouri and Wisconsin will be affected in 2005.

(14)
Although its possible to bank NOx allowances under both the OTR regulations and the regulations proposed in EPA's NOx SIP Call, the conditions for banking allowances are so onerous that they are likely to be uneconomic in most cases. Therefore, any banking that occurs is unlikely to have a significant effect on NOx allowances prices.

B–42


    The NOx allowance price forecast begins at the 2000 ozone season(15) price, which is approximately $700/ton (see Table 4-12). The price is expected to rise slightly (to $1,000/ton) in 2001 and 2002, and then rise to approximately $4,000/ton in 2003 as the tighter NOx regulations proposed in the SIP call go into effect.

    The $4,000/ton NOx allowance price is expected to remain constant in real terms after 2003, as gradual reductions in the NOx emissions cap are expected to offset any improvements in technology. This assumption reflects the fact that EPA's suggested SIP standards include provisions for a slight decline in NOx allowances over time. EPA proposed to have the number of NOx allowances granted to plants decline as their utilization goes down. Therefore, assuming that most states adopt EPA's suggested language, the NOx emissions budget should decline slowly over time. Although this is not expected to cause an increase in NOx allowance prices (since most coal-fired units reach their maximum utilization by 2003), NOx allowance prices are expected to remain sufficiently high to justify the installation of additional NOx control equipment needed to meet the slowly tightening NOx cap.

    The hydroelectric plants are consolidated by utility and categorized as peaking or baseload. Similar to the thermal units, the maximum capacity for each unit was taken from the sources cited above for summer and winter capabilities. Monthly energy patterns were developed from the 1993-1998 EIA Forms 759, which contain monthly generation and (for pumped storage units) net inflows.

    PHB Hagler Bailly evaluated the operation of nuclear plants in the regions covered by this study on the basis of going-forward costs to determine which plants would remain in service based on their economic performance.

    PHB Hagler Bailly estimated the annual going-forward costs (fixed O&M, property taxes, and annualized incremental capital costs) associated with each unit. The incremental capital costs do not include the original investment in the plant. The original investment is treated as a sunk cost and is not considered in the determination of the future competitiveness of a station. Incremental capital costs only include modifications made to the plant each year. These costs are very difficult to track due to the reporting methods. However, in recent years, the number of modifications to nuclear power stations has decreased and these costs are relatively low compared to O&M costs.

    There are a number of other non-economic issues that might affect a shutdown date. Politics of the region plays an important part in the premature shutdown of the units. Equipment failures and poor overall performance can also cause a utility to shut down a unit before its license expires. As the units age, the amount of investment required to continue operating the unit becomes an important factor.

    Historical performance as well as recent trends in forced outage rates at each unit were reviewed. Future forced outage rates were forecast for each year, and each unit's scheduled outages during the year were also considered. From this information, and noting that outages are becoming shorter as the industry improves outage planning, the duration of outages for each unit was forecast. For refueling outages, sources included refueling outage schedules, published every six months in Nuclear News for all U.S. units.


(15)
The ozone season, for purposes of assessing NOx costs, is defined as May 1 through September 30.

B–43


    The decision whether to retire a unit prior to its license expiration date was made based on a thorough review of the unit's projected future economic performance. Nuclear unit retirements were made based on the same process applied to all other units as described in Section 3.3.4. A summary of nuclear unit retirements is provided in Table 4-13.


Table 4-13
NEPOOL Nuclear Unit Retirements—2000 through 2020

Unit

  Trans Area
  Capacity (MW)
  Retirement Date
 
Pilgrim 1   East   664   12/31/2004 (1)
Vermont Yankee 1   West   500   12/31/2012  
Millstone 2   West   871   12/31/2015  

(1)
Economic Retirement.

4.8  CAPACITY COMPENSATION SIMULATION MODEL INPUT ASSUMPTIONS

    PHB Hagler Bailly developed projections of Fixed Operation & Maintenance (FO&M) costs for steam generating units. FO&M costs are intended to include all forward (non-sunk) costs of operating and maintaining plants, except those variable costs, such as fuel costs, which are included in the dispatch cost. Total O&M expenses, excluding fuel expenses, rents, and allowances were obtained from the OPRI(16) Database of FERC Form I data. Internal estimates of Variable Operation & Maintenance (VO&M) costs (see Section 4.7.1) were used in conjunction with the data to net the variable portion out of total O&M expenses, generating a value for FO&M for each plant.

    Estimates of pension and benefit expenses, based on the number of full-time employees at each station, were also obtained from FERC Form I data and added to the FO&M estimate for each plant.

    FO&M estimates were developed for broad prime mover, fuel type, and size categories. For example, coal steam plants were grouped together, as were all oil and gas fired steam plants. Plants in each of these groups were further grouped by size categories. Plants in each resulting grouping were then ranked according to FO&M value.

    To account for an expected reduction in FO&M costs over time in a deregulated environment, the cost for the plant at the 25th percentile in each grouping (lower percentiles indicating lower costs) was taken as an appropriate value for the 50th percentile of plants in the same grouping for 2005. Estimates of annual incremental capital expenditures were based on a ten-year national average of capital additions to utility steam generating plants. These estimates were added to the FO&M cost figures to develop a total annual going-forward cost. After 2005, FO&M costs were assumed to decrease at a constant real rate of 3% per year, equivalent to the average rate of worker productivity improvement in the U.S. industrial sector over the past several decades.

    Property tax data for each unit was derived by applying an estimated mill levy rate to an assumed market value.

    A critical step in simulating the regional capacity market is to ascertain the number and timing of capacity additions for the near term (2000 to 2002). To this end, PHB Hagler Bailly worked toward the


(16)
OPRI is a division of Resource Data International Inc.

B–44


following goals: determining the number and status of greenfield power plants that are currently under development in the regions, determining the average length of time required to construct and operate a new power plant in the regions, and determining the costs associated with constructing and operating a power plant in the regions.

    In order to collect and analyze sufficient data to meet these goals, PHB Hagler Bailly completed a number of separate tasks. PHB Hagler Bailly performed a literature search in an effort to identify articles referring to planned power plant development in the regions. Also, PHB Hagler Bailly's experts analyzed PHB Hagler Bailly's IPP Database to determine the number of plants currently under development in the regions and also the average length of time required to bring a plant on line following the announcement of a new project.

    As a result of PHB Hagler Bailly's analysis and investigation, a baseline on-line scenario was developed which reflects PHB Hagler Bailly's estimate of the plants that realistically will be constructed in the target region through the year 2002. These are summarized for NEPOOL region in Table 4-14.


Table 4-14
NEPOOL Base Case Additions—2000 through 2002

Developer (Plant)

  Size (MW)(1)
  Unit Type
  Fuel Type
  On-Line Year
Skygen Energy (Androscogin)   150   CT   Natural Gas   2000
EMI/Calpine (Rumford)   265   CC   Natural Gas   2000
EMI/Calpine (Tiverton)   265   CC   Natural Gas   2000
Berkshire Power (Berkshire)   270   CC   Natural Gas   2000
Duke Energy (Maine Independence)   497   CC   Natural Gas   2000
PG&E Gen (Millennium)   360   CC   Natural Gas   2000
Power Dev Corp (Milford)   544   CC   Natural Gas   2001
Calpine (Westbook)   540   CC   Natural Gas   2001
PG&E Gen (Lake Road)   792   CC   Natural Gas   2001
ANP (Blackstone)   550   CC   Natural Gas   2001

(1)
Maximum net capacity.

    The validity of capacity additions post 2002 is assessed based on a discounted cash flow (DCF) approach that provides a "Go" or a "No Go" decision for each increment of generic new capacity.

    The DCF framework captures the net present value of the various cash flow streams: revenues, including compensation for capacity and energy; and expenses, including fixed and variable O&M, fuel, property taxes, and principal and interest expenses for the new capacity additions. The analysis merges assumptions concerning the general economy, capital markets, tax structures, fixed costs, and depreciation with the operating projections for the potential new capacity in order to capture the gross cash flow from the unit's projected operation.

    The starting point for the DCF calculation is the generic unit-specific operating parameters for new combined cycle and combustion turbine units. The generic parameters and assumptions assumed in the model are displayed in Table 4-15. The first year in which new generic capacity is considered in the model is 2003. Capital costs are assumed to decrease at 1% per annum (real 2000 dollars). Table 4-16 indicates the assumed schedule and effect of technology improvement on new unit heat rates.

B–45



Table 4-15
New CC Generating Characteristics (real 2000 $)

 
  Combined
Cycle

  Combustion
Turbine

Capital Cost ($/kW)   $ 610   $ 430
Fixed O&M ($/kW-year)   $ 11.50   $ 6.00
Variable O&M ($/MWh)   $ 2.00   $ 5.00
Size (MW)     520     345


Table 4-16
Full Load Heat Rate Improvement (Btu/kWh)(1)

 
  1999-2003
  2004-2008
  2009-2013
  2014-2018
  2019+
 
Combined Cycle   6,700   6,566   6,435   6,306   6,180  
Combustion   10,400 (W) 10,192 (W) 9,988 (W) 9,788 (W) 9,593 (W)
  Turbine   10,700 (S) 10,487 (S) 10,427 (S) 10,070 (S) 9,871 (S)

(1)
Degradation was assumed in the modeling of the units.

    Information on fixed costs, depreciation and taxes is also developed and incorporated within the DCF analysis to determine the economic viability of the new unit additions. Environmental costs and overhaul expenses are not included, due to expectations that such expenses would be minimal in early years of operation.

B–46


4.9  VOLATILITY ANALYSIS ASSUMPTIONS

    The volatility analysis features a probabilistic representation of electricity and natural gas price evolution. The patterns of short-term and seasonal price evolution are established by regressions estimated from historical data. Long-term price trends are established through economic modeling or assumption.

    The volatility analysis uses Monte Carlo simulation to represent natural gas price evolution. In the model, natural gas price evolves day to day. To represent the day-to-day evolution of natural gas price, regressions have been fit to the daily NY Citygate price data obtained from Gas Daily. The short-term and seasonal patterns established by this statistical analysis are used to model day-to-day evolution of natural gas price in the regions included in the MULTISYM analysis. Even though the same statistical patterns are used in all regions, the price levels and associated volatility still differ within the regions. For example, if the gas price in New York is high on a simulated winter day, the gas price for Boston will also be high on a proportional basis. For such a day, with both New York and NEPOOL gas prices high, the gas price in New York City will be greater than the NEPOOL gas price because this is the long term expectation. Long-term trends in natural gas price and fuel oil products are set to be consistent with the fuel price forecast assumptions (see Section 4.4.1), so the analysis replicates the annual averages of the fuel forecast assumptions.

    Similarly, the volatility analysis uses Monte Carlo simulation to represent electricity price evolution. In the model, electricity price evolves hour-to-hour. To represent the hour-to-hour evolution of electricity price, regressions have been fit to hourly price data from the NEPOOL market, as reported by the New England ISO. Electricity price data from May 1, 1999 through June 31, 2000 have been analyzed to yield a statistical model of short-term price evolution. As in the simulation of natural gas price evolution, all different electricity markets in the analysis are simulated using the same relative patterns of short-term evolution. Thus, if the simulation exhibits higher-than-average electricity prices for NEPOOL on a simulated summer day, the NYPP and PJM markets also exhibit proportionally higher-than-average prices. Long-term trends in electricity price are established by annual averages resulting from the MULTISYM analysis.


CHAPTER 5

MARKET PRICE FORECASTS

5.1  INTRODUCTION

    This chapter summarizes the market price projections for the NEPOOL West transmission subregion and net revenue projections for the units that correspond to the specific NGC generating assets. These were described in Chapter 1 and are:

    In carrying out the analysis, we have considered three market scenarios that describe possible future NEPOOL market conditions. For each scenario, we report:

B–47


5.2  NEPOOL MARKET ASSUMPTIONS

    The NGC assets located in the NEPOOL West pricing area participate in the NEPOOL wholesale electricity market, which covers the entire NEPOOL transmission region. Figure 5-1 illustrates the load and resource balance for NEPOOL through the end of the study period.


Figure 5-1
NEPOOL Load and Resource Balance

LOGO


(1)
Reserve Margin is assumed to be approximately 15%. Net additions are net of retirements.

    Peak demand in the NEPOOL market is forecasted to grow at an annual compound rate of approximately 2.0% per year from 2000 through the end of the study period. A required system wide reserve margin of approximately 15% is assumed through the study period.

    The existing capacity in NEPOOL is initially sufficient to meet the system reserve requirement. However, as demand grows and the market tightens, a gap forms between existing and required system resources. This resource gap is addressed by the addition of merchant plants through 2002. These assumed additions are detailed in Chapter 4. After 2002 the model assumes that new units are brought on-line as needed to meet the specified reserve requirement.

B–48


    The transmission transfer capability between NEPOOL and the surrounding transmission areas is defined in Appendix C. While NEPOOL shares numerous interconnections with surrounding regional markets, transfer capability can be limited under certain operating conditions, reducing total import capabilities into the NEPOOL system.

    The relative mix of the capacity and energy generation in the NEPOOL market is illustrated in Figures 5-2 and 5-3. As shown, the NEPOOL market is largely comprised of gas/oil fired generating units and hydro units.

Figure 5-2
NEPOOL Capacity
  Figure 5-3
NEPOOL Capacity

LOGO

5.3  NEPOOL CASES CONSIDERED IN THIS ANALYSIS

    PHB Hagler Bailly developed three Cases (scenarios) that reflect our best assessment of future market conditions and sensitivities on some of the conditions for the NEPOOL market. It should be recognized that these cases will vary to the extent the input assumptions change, and such assumptions should be reviewed with the same rigor as the resulting forecast.

    The three cases are:

B–49


NEPOOL Capacity Additions (MW)

  2000
  2001
  2002
  2003
Case 1: New Capacity   1,807   2,246   0   0
Case 3: Overbuild: Incremental New Capacity   0   0   3,050   665
Case 3: Overbuild: Total New Capacity   1,807   2,426   3,050   665

    These sensitivities were developed to exhibit the variance from Case 1 in the resulting forecast given the change in these significant input variables. It should be noted that other market conditions could also change and affect energy prices and the portfolio revenues. These sensitivity cases may not present all the risk factors to be considered.

5.4  ENERGY PRICE FORECASTS FROM THE FUNDAMENTAL ANALYSIS

    As discussed in Chapter 3, the market price forecast from the fundamental analysis is composed of two price streams:

    In reporting the results of the fundamental analysis, we report both streams separately. We also combine the two streams as an all-in price forecast, where the additional compensation for capacity needed to maintain a minimum amount of capacity in the market is factored in to the all-in market price forecast (assuming 100% load). Thus, the all-in price is a good representation of the average price needed in the marketplace to maintain equilibrium.

    The amount of compensation for capacity needed is directly related to the energy price level and the ability of the marginal unit to recover its fixed costs. As energy prices rise and fall, compensation for capacity will also adjust to ensure that the total going-forward costs of the marginal unit are met.(2) As a result of this dynamic equilibrium, the revenues that form the all-in market price will always be sufficient to support the minimum amount of capacity needed by the system.

    The results of the fundamental analysis for the three Cases or scenarios we have analyzed are provided in Sections 5.4.1 through 5.4.3.

    5.4.1  NEPOOL Case 1 Fundamental Analysis Results

    This case models near term fuel prices based on recent actual spot prices and futures prices through December 2001, trending back to the long-term consensus view by 2004.

    Due to the high reserve margin, units with higher going-forward costs (nuclear and small coal units) are required to meet this reliability target in 2000 and 2001, which results in the higher relative capacity compensation for these years, as seen in Table 5-1.


(1)
If additional compensation for capacity were not present in the market, then a substantial portion of the generating capacity necessary to meet peak demand, let alone necessary to maintain an economic level of reserves, would exit the market as these plants would not be able to meet their going-forward costs. Such a forecast is nonsensical; therefore the energy price generated by the model should not be considered without factoring in the value of the assets needed to maintain reliability in the market.
(2)
In each year the value of the additional compensation for capacity captured cannot be greater than the annual carrying cost of a new combustion turbine. If the additional compensation for capacity were higher than the carrying cost of a new unit, then the new unit would be constructed to displace other higher cost units in the system. Thus, the total compensation for capacity is capped in each year by the carrying cost of a new combustion turbine.

B–50



Table 5-1
NEPOOL Case 1 Compensation for Capacity Forecast (real 2000 $/kW-yr)

2000   36.50   2007   58.80   2014   60.00
2001   34.80   2008   62.80   2015   60.40
2002   36.00   2009   62.50   2016   59.60
2003   44.20   2010   63.10   2017   58.00
2004   48.10   2011   62.20   2018   62.60
2005   37.60   2012   60.40   2019   63.30
2006   42.40   2013   59.00   2020   62.80

    The energy prices in the initial years are higher due to the market fuel price forecast. In 2004, when the consensus forecast begins, the energy prices in NEPOOL West remain fairly steady throughout the study period (see Table 5-2).

    The all-in price represents a combined compensation for capacity and energy price (assuming a 100% load factor). The compensation for capacity contribution to the all-in price ranges between approximately $4.00/MWh and $7.00/MWh.

    The Case 1 energy and all-in market price forecasts are presented in Table 5-2 and Figure 5-4 for the NEPOOL West pricing area.


Table 5-2
NEPOOL West Case 1 Energy and All-In Price Forecasts (real 2000 $/MWh)

Energy Price Forecast
  All-In Price Forecast
2000   34.30   2011   26.30   2000   38.50   2011   33.40
2001   32.10   2012   26.20   2001   36.00   2012   33.10
2002   29.10   2013   26.60   2002   33.20   2013   33.30
2003   26.60   2014   26.60   2003   31.60   2014   33.40
2004   26.30   2015   26.50   2004   31.80   2015   33.40
2005   27.10   2016   26.90   2005   31.40   2016   33.70
2006   27.60   2017   27.00   2006   32.40   2017   33.60
2007   25.90   2018   27.30   2007   32.60   2018   34.40
2008   26.00   2019   27.50   2008   33.20   2019   34.70
2009   25.80   2020   27.40   2009   33.00   2020   34.50
2010   26.00           2010   33.20        

B–51



Figure 5-4
NEPOOL West Case 1 Energy, All-In, and Compensation for Capacity Forecasts(1)

LOGO

    5.4.2  NEPOOL Case 2 Fundamental Analysis Results

    Case 2 examines the effect of lower natural gas and oil prices as described in Section 5.1. Since fuel oil and natural gas are the marginal fuels in several of the transmission or pricing areas, the energy price forecast is driven in large part by the forecasted price of these fuels. In order to test the sensitivity of the energy price forecast to changes in the natural gas and fuel oil forecasts, Case 2 was analyzed for the NEPOOL region.

    The overall effect of Case 2 is lower compensation for capacity, as well as energy prices, throughout a majority of the study period as compared to Case 1. The gas-powered units that set the compensation for capacity in NEPOOL are allowed to generate more due to the lower fuel cost. Even with lower energy prices, increased generation allows these units to recover a greater percentage of their fixed cost in the energy market.

    The compensation for capacity for Case 2 is presented in Table 5-3 and the energy and all-in price forecasts are presented in Table 5-4 and Figure 5-5.

B–52



Table 5-3
NEPOOL Case 2 Compensation for Capacity Forecast (real 2000 $/kW-yr)

2000   36.10   2007   54.80   2014   54.00
2001   36.00   2008   57.20   2015   54.60
2002   41.50   2009   56.90   2016   56.70
2003   46.70   2010   55.00   2017   58.90
2004   48.90   2011   54.00   2018   62.70
2005   41.40   2012   55.90   2019   63.30
2006   43.40   2013   54.50   2020   62.80


Table 5-4
NEPOOL West Case 2 Energy and All-In Price Forecasts (real 2000 $/MWh)

Energy Price Forecast
  All-In Price Forecast
2000   31.20   2011   24.20   2000   35.30   2011   30.30
2001   29.10   2012   23.80   2001   33.20   2012   30.20
2002   26.70   2013   24.10   2002   31.40   2013   30.30
2003   23.70   2014   24.20   2003   29.00   2014   30.30
2004   23.50   2015   24.00   2004   29.10   2015   30.20
2005   24.60   2016   23.80   2005   29.30   2016   30.30
2006   24.70   2017   23.80   2006   29.70   2017   30.50
2007   23.60   2018   23.80   2007   29.80   2018   31.00
2008   23.60   2019   24.00   2008   30.10   2019   31.20
2009   23.70   2020   23.90   2009   30.10   2020   31.10
2010   23.90           2010   30.20        

B–53



Figure 5-5
NEPOOL West Case 2 Energy, All-In, and Compensation for Capacity Forecasts(1)

LOGO

    5.4.3  NEPOOL Case 3 Fundamental Analysis Results

    Case 3 examines the effect of exuberance in merchant plant development. This case assumes that in addition to the merchant plants identified for the previous cases (see Section 4.8.2), several additional merchant plants would come online in the near term (2001-2003). This assumption could be interpreted as the ability of all generators to seek recovery of out-of-the-market costs from other sources (e.g., stranded cost recovery). Table 5-5 displays the incremental merchant plant development assumed for Case 3.


Table 5-5
NEPOOL Case 3 Incremental Merchant Plant Assumptions

 
  Capacity (MW) Additions in:
   
Trans Area

   
  2002
  2003
  Total
NEPOOL-Maine   600   0   600
NEPOOL-SE   930   665   1,595
NEPOOL-West   1,520   0   1,520
New York(1)   0   2,420   2,420
PJM   1,095   1,100   2,195
Total   4,145   4,185   8,330

(1)
Includes In-City.

B–54


    The result of Case 3 is lower compensation for capacity than Case 1, when the overbuild begins in 2002. Capacity compensation remains lower than in Case 1 due to differences in the units setting the marginal price because of changes in new unit entrant characteristics.

    The compensation for capacity for Case 3 is presented in Table 5-6 and the energy and all-in price forecasts are presented in Table 5-7 and Figure 5-6.


Table 5-6
NEPOOL Case 3 Compensation for Capacity Forecast (real 2000 $/kW-yr)

2000   36.50   2007   33.00   2014   50.70
2001   34.80   2008   33.10   2015   52.90
2002   31.60   2009   33.90   2016   52.60
2003   36.00   2010   32.50   2017   53.40
2004   36.00   2011   32.30   2018   54.20
2005   28.20   2012   36.10   2019   54.20
2006   29.30   2013   50.90   2020   59.00


Table 5-7
NEPOOL West Case 3 Energy and All-In Price Forecasts (real 2000 $/MWh)

Energy Price Forecast
  All-In Price Forecast
2000   34.30   2011   26.70   2000   38.50   2011   30.30
2001   32.10   2012   27.30   2001   36.00   2012   31.40
2002   27.60   2013   27.10   2002   31.20   2013   32.90
2003   24.60   2014   27.30   2003   28.70   2014   33.10
2004   24.10   2015   27.10   2004   28.20   2015   33.10
2005   24.50   2016   27.10   2005   27.70   2016   33.10
2006   25.00   2017   26.80   2006   28.40   2017   32.90
2007   24.30   2018   26.90   2007   28.10   2018   33.10
2008   24.60   2019   27.00   2008   28.40   2019   33.20
2009   25.10   2020   27.00   2009   29.00   2020   33.70
2010   25.70           2010   29.40        

B–55



Figure 5-6
NEPOOL West Case 3 Energy, All-In, and Compensation for Capacity Forecasts(1)

LOGO

5.5  ENERGY PRICE FORECASTS WITH VOLATILITY

    Chapter 3 of this report discussed the importance of incorporating volatility in energy price forecasts when valuing generation assets, particularly those that include a pumped storage facility where the critical factor affecting revenues is the spread in prices. PHB Hagler Bailly has used historical NEPOOL market data coupled with the results from the fundamental model to estimate the market prices and revenues that the NGC portfolio is forecast to capture for each of the three Cases described previously.

    In volatility analysis, unit revenues are derived directly from the energy market. There is no explicit compensation for capacity as this is implicitly included in the volatile historical NEPOOL prices that were analyzed to yield a stochastic price forecasting model. The price forecasts derived from analyzing volatility are naturally higher than the energy price forecasts derived from the fundamental model as reported in Section 5.3, but generally lower than the all-in prices from the fundamental model.

    As discussed in Section 3.4, the units in the NGC portfolio will also earn revenues through the provision of ancillary services—ten minute spinning reserve (TMSR), and automatic generation control (AGC). From our analysis of the NEPOOL market, we also believe the Northfield station and the Tunnel CT will earn additional revenue through their quickstart capability. These represent important additional revenue streams to the NGC portfolio.

B–56


    5.5.1  NEPOOL West Case 1 Volatility Results

    Table 5-8 displays the NEPOOL Case 1 (base case) energy price forecasts for a market where it is assumed there is no capacity compensation for generation, and the revenue from units such as combined cycles and combustion turbines is derived directly from energy market sales.

    Table 5-9 displays the estimated total revenue for the NGC portfolio for Case 1, including energy, ancillary services and quickstart revenues.

    Total revenues for the portfolio start strong due to the current high forward prices for electric energy and natural gas. Revenues drop through the end of 2002 as we presumed that the gas market would transition back to the consensus gas forecast in 2003. Revenues increase in 2004 due to our assumption that the ISO would institute some sort of market mechanism to compensate quickstart units for their presence in that year.(3)


(3)
Note that discussions with ISO New England has confirmed the ISO's belief that additional quickstart capacity is required in the region for system reliability purposes, and that the ISO is looking for mechanisms to compensate these types of units to remain and be built for the market. While we have assumed this compensation begins in 2003, it could begin earlier.


Table 5-8
NEPOOL West Case 1 Energy Price Forecasts(1)
Volatility Adjusted, Energy Only Market

Year

  Average Price
All Hours

  Year

  Average Price
All Hours

2001   40.99   2007   31.35
2002   35.17   2008   31.46
2003   30.54   2009   31.64
2004   29.51   2010   31.99
2005   31.03   2015   32.18
2006   31.68   2020   32.16

(1)
Results are expressed in real 2000 dollars.

B–57



Table 5-9
NGC Portfolio Revenues(1)—NEPOOL West Case 1
Volatility Adjusted, Energy Only Market ($M)

Year

  Energy Revenue
  Spinning Reserve Revenue
  AGC Revenue
  Quick Start Support
  Total Portfolio
Revenue

2001   81.8   16.1   7.8   0   105.7
2002   67.7   12.9   7.8   0   88.4
2003   54.4   11.2   7.8   20.1   93.5
2004   58.7   10.5   7.6   23.5   100.3
2005   61.1   11.2   7.8   18.3   98.5
2006   61.4   11.3   7.8   17.4   97.9
2007   64.9   11.0   7.7   14.2   97.8
2008   67.1   10.8   7.7   14.6   100.3
2009   65.4   10.9   7.6   14.8   98.8
2010   65.2   10.9   7.8   15.6   99.5
2015   66.0   11.1   7.7   17.3   102.0
2020   62.2   11.6   7.9   20.6   102.3

(1)
Results expressed in real 2000 dollars.

5.5.2  NEPOOL West Case 2 Volatility Results

    Table 5-10 displays the NEPOOL West Case 2 energy price forecasts for a market with lower gas and oil fuel prices. Table 5-11 displays the estimated total revenue for the NGC portfolio for Case 2, including energy, ancillary services and quickstart revenues.


Table 5-10
NEPOOL West Case 2 Energy Price Forecasts(1)
Volatility Adjusted, Energy Only Market

Year

  Average Price
All Hours

  Year
  Average Price
All Hours

2001   36.98   2007   28.52
2002   32.34   2008   28.44
2003   26.88   2009   28.71
2004   26.82   2010   28.92
2005   27.86   2015   29.21
2006   28.42   2020   28.36

(1)
Results are expressed in real 2000 dollars.

B–58



Table 5-11
NGC Portfolio Revenues(1)—NEPOOL West Case 2
Volatility Adjusted, Energy Only Market ($M)

Year

  Energy Revenue
  Spinning Reserve Revenue
  AGC Revenue
  Quick Start Support
  Total Portfolio Revenue
2001   71.1   14.1   7.7   0   92.8
2002   61.7   11.5   7.8   0   81.0
2003   46.2   9.6   7.6   20.1   83.5
2004   55.7   9.1   7.4   23.5   95.8
2005   55.3   9.7   7.6   18.3   90.9
2006   55.0   9.8   7.6   17.4   89.8
2007   61.7   9.5   7.6   14.2   92.9
2008   63.2   9.2   7.6   14.6   94.6
2009   61.7   9.4   7.5   14.8   93.5
2010   61.2   9.6   7.7   15.6   94.1
2015   60.6   9.9   7.6   17.3   95.4
2020   57.5   9.7   7.7   20.6   95.6

(1)
Results are expressed in real 2000 dollars.

5.5.3  NE POOL West Case 3 Volatility Results

    Table 5-12 displays the NEPOOL West Case 3 energy price forecasts for a market with substantial additional merchant plant capacity coming into operation in 2002 and 2003. Table 5-13 displays the estimated total revenue for the NGC portfolio for Case 3, including energy, ancillary services and quickstart revenues.


Table 5-12
NEPOOL Case 3 Energy Price Forecasts(1)
Volatility Adjusted, Energy Only Market

Year

  Average Price All Hours
  Year
  Average Price All Hours
2001   40.93   2007   31.35
2002   32.62   2008   31.46
2003   27.76   2009   31.64
2004   26.48   2010   31.99
2005   27.33   2015   32.18
2006   28.27   2020   32.16

(1)
Results are expressed in real 2000 dollars.

B–59



Table 5-13
NGC Portfolio Revenues(1)—NEPOOL West Case 3
Volatility Adjusted, Energy Only Market ($M)

Year

  Energy Revenue
  Spinning Reserve Revenue
  AGC Revenue
  Quick Start Support
  Total Portfolio
Revenue

2001   81.4   16.1   7.8   0   105.3
2002   61.5   11.9   7.6   0   81.1
2003   48.0   9.9   7.6   20.1   85.7
2004   49.6   9.4   7.4   23.5   89.9
2005   51.3   9.8   7.6   18.3   87.0
2006   53.8   10.5   7.7   17.4   89.4
2007   66.9   10.1   7.7   14.2   98.9
2008   67.2   10.0   7.6   14.6   99.5
2009   67.9   10.4   7.6   14.8   100.7
2010   66.9   10.3   7.6   15.6   100.5
2015   64.4   11.3   7.6   17.3   100.7
2020   62.0   12.0   7.8   20.6   102.5

(1)
Results are expressed in real 2000 dollars.

5.6  RELATIVE UNCERTAINTY OF CASH FLOWS

    As discussed in Chapter 3, the revenues from the NGC Portfolio arise primarily from the Northfield pumped storage station. These revenues are determined by the spread between high and low daily prices, when Northfield is generating or pumping respectively. The variation in net revenues from the NGC portfolio is similar to that from new merchant combined cycle units, and substantially less than that from new combustion turbine capacity.

    As part of the analysis of this portfolio, PHB Hagler Bailly investigated the possible variations in NGC portfolio revenue for representative samples of hourly prices drawn from the 100 sets of hourly prices derived as part of the volatility analysis. The results of this analysis are shown in Table 5-14, which illustrates the relative uncertainty of the Case 1 cash flows in 2004 for the NGC portfolio, contrasted with the revenues from new merchant capacity for the same hourly prices. The Coefficient of Variation4 illustrates the range of possible revenues: the lower the Coefficient of Variation, the narrower the spread in probable revenues and hence in the uncertainty of the cash flows. Note that the NGC portfolio appears to have an uncertainty in cash flow that is more like a combined cycle plant than like a combustion turbine.


(4)
The Coefficient of Variation is defined as: (Coefficient of Variation = Standard Deviation of Distribution/Mean of Distribution).

B–60


    As shown in Table 5-14, the revenues included are the energy and ancillary services revenues as these are determined by the underlying hourly prices. We do not expect quickstart revenue to vary significantly with the hourly prices, so we have excluded this from the comparison of cash flows.


Table 5-14
Relative Risk of Case 1 NGC Portfolio Revenues ($/kW-yr)

 
  NGC Portfolio Net
Revenues

  Generic CC Net
Revenues

  Generic CT
Net Revenues

 
Mean Net Revenue   59.92   84.50   47.46  
Standard Deviation of Net Revenue   3.87   5.23   7.72  
Coefficient of Variation   6.5 % 6.2 % 16.3 %

B–61



APPENDIX A
PRICING AREAS

NPCC/MAAC Pricing Areas

• NYPP-East   • NEPOOL-South East
• NYPP-West   • NEPOOL-Maine
• NYPP-In-City   • NEPOOL-West
• NYPP-Long Island   • Ontario
• PJM-East   • Quebec
• PJM-Central   • New Brunswick/Nova Scotia.
• PJM-West    


NPCC/MAAC Utilities by Pricing Area

Pricing Area
  Utility
NEPOOL-Maine   Bangor Hydro-Electric Company
Central Maine Power Company
Maine Cooperative
Maine Public Service Company
New England Power Pool Maine
NEPOOL-South East   Boston Edison Company
Braintree Electric Light Department
Chicopee Municipal Lighting Plant
Commonwealth Energy System Companies
Eastern Utilities Associates Companies
Fitchburg Gas and Electric Light Company
Hingham Municipal Lighting Plant
Holyoke Gas and Electric
Hudson Light and Power Department
Ipswich Municipal Light Department
Middleborough Gas and Electric Department
Marblehead Municipal Light Department
Massachusetts Municipal Wholesale Electric Company
New England Electric System Operating Companies
NEPOOL-South East   North Attleborough Electric Department
Peabody Municipal Light Plant
Princeton Municipal Light Department
Shrewsbury Electric Lighting Plant
Sterling Municipal Light Department
Taunton Municipal Light Plant
Milford Power
New England Power Pool SE

B–62


NEPOOL-West   New England Power Pool W
Connecticut Municipal Electric Energy Cooperative
Great Bay Power Corporation
New Hampshire Electric Cooperative
Northeast Utilities Companies
The United Illuminating Company
UNITIL Power Corp. Companies
Vermont Group
Central Vermont Public Service Corp.
Green Mountain Power
NYPP-East   Central Hudson Gas & Electric Corporation
Orange & Rockland Utilities, Inc.
City of Plattsburgh
NYPP-In-City   Consolidated Edison Company of New York, Inc.
NYPP-Long Island   Long Island Lighting Company
NYPP-West   New York Power Pool
Village of Freeport
Jamestown Municipal Electric System
New York Power Authority
New York State Electric & Gas Corporation
Niagara Mohawk Power Corporation
Rochester Gas & Electric Corporation
PJM-Central   Pennsylvania Power & Light Company
Baltimore Gas & Electric Company
Potomac Electric Power Company
Metropolitan Edison Company
Allegheny Electric Cooperative, Inc.
UGI Corporation
Southern Maryland Electric Cooperative
PJM-East   PSEG Power LLC
Philadelphia Electric Company (PECO Energy)
General Public Utilities Corporation
Atlantic Electric
Delmarva Power & Light Company
Jersey Central Power & Light Company
CRSS Capital, Inc.
City of Dover
City of Vineland Electric Utility
Easton Utilities Commission (The)
U.S. Generating Company
PJM-West   Pennsylvania Electric Company
Ontario   Ontario Hydro
Quebec   Hydro Quebec
New Brunswick/ Nova Scotia   Maritime Electric Company, Limited
New Brunswick Power Corp.
Nova Scotia Power Inc.

B–63



APPENDIX B

REGIONAL SPECIFIC COAL PRICE DISCUSSION

NPCC/MAAC

    The following details the methodology used for projecting pricing for Central Appalachian, Northern Appalachian, Pittsburgh Seam, and other coals used in the NPCC/MAAC region.

    Central Appalachia.  PHB Hagler Bailly projects the use of 1.2-pound(1) and 1.5-pound Central Appalachian coals in MAAC and NPCC regions during the forecast period. Both coal types have energy contents of 12,500 Btu per pound, and are both priced on an FOB railcar basis.


(1)
The terms "1.2 pound" and "1.5 pound" coal refer to a particular coal's sulfur content. For example, a coal with a sulfur content corresponding to 1.2 pounds of sulfur dioxide for each MMBtu of energy content is called a "1.2-pound" coal.

    PHB Hagler Bailly projects that the real price for both of these types of coal will decline by about 10% between 2000 and 2020 (an average annual decline of approximately 0.5%). This relatively slow rate of decline reflects expectations of high demand for this coal, and significant depletion of reserves, offset by modest productivity gains and continued strong price competition among Central Appalachian coal producers.

    Northern Appalachia and Pittsburgh Seam.  PHB Hagler Bailly projects the use of 1.8-pound, 3.8-pound, and 6.3-pound Northern Appalachian coals, and 2.4-pound and 3.2-pound Pittsburgh Seam coals in MAAC and NPCC during the forecast period. The energy contents of these coals ranges from 12,000 to 13,000 Btu/lb, with most of the coal types being toward the higher end of this heat content range. Real prices for all of these coal types decline during the forecast period. Prices for the Northern Appalachian 3.8-pound coal decline most rapidly (declining 19% over the forecast period or almost 1%/year), because we expect that higher SO2 allowance prices will reduce the demand for this coal at unscrubbed plants and therefore reduce the price premium this coal has traditionally enjoyed relative to the Northern Appalachian high-sulfur coal. The prices for the Pittsburgh Seam coals are expected to decline by about 12% over the forecast period, as reserve depletion and limited potential for future productivity gains at these longwall mining operations offset the effects of reduced demand for these mid-sulfur coals.

    Very high sulfur coals primarily serve generating units that are equipped with scrubbers that remove SO2 from emission streams. These units obtain very little benefit from lower sulfur coals and typically seek to minimize cost with the use of cheap, very high sulfur coals. The analysis projects the price of 6-pound coals to decline at slightly more than 1% per year in real terms.

    Other.  Several other coal types are expected to be used in the projected in the MAAC and NPCC-U.S. regions. These include Central Pennsylvania 3.8-pound coal, waste coals (both bituminous and anthracite), and coals imported from South America by ocean vessel.

    The price of the Central Pennsylvania coal is expected to decline by about 7% over the forecast period (a decline of slightly less than 0.5%/year). This reflects decreased demand for this mid- sulfur coal, offset by very substantial depletion of reserves.

    Demand for waste coals is expected to remain relatively steady. The supply of this coal is highly localized, and therefore competition to supply any particular plant is limited. Real prices for this coal are expected to decline by about 7% over the forecast period.

    The prices for imported coal are largely driven by the competing coals available at a given generating plant. This coal moves to a limited number of plants in New England that have vessel-

B–64


receiving capability. Prices for this coal were projected on a delivered basis for individual plants, by assuming that the delivered price of this coal was 10 cents per million Btu lower than the delivered price of the cheapest domestic coal available to that plant.

    Transportation costs.  Transportation rates were estimated using several publicly available data sources that provide information on electric utility delivered fuel costs and commercial publications providing spot coal market pricing. Transportation costs for coal types not historically used at a particular location were based on industry experience and analysis of economic options at the unit. Projected escalation rates for coal transportation modes are provided below.

    Rail.  Rail escalation rates were projected in real dollar terms and differentiated according to origin region and whether particular plants were captive to a single railroad or had access to competitive transportation alternatives (including either more than one railroad or a railroad and another mode of coal transportation such as barge or truck).

    Rail rates for Central Appalachian coal moving to captive plants are expected to remain flat in real terms during the forecast period. Rail rates for Central Appalachian coal movements to competitively-served plants are expected to decline by an average of 1%/year over the forecast period. Rail rates for Northern Appalachian and Pittsburgh Seam coal moving to captive plants are expected to decline by 0.5%/year in real terms during the forecast period. Rail rates for Northern Appalachian and Pittsburgh seam coal movements to competitively-served plants are expected to decline by an average of 1%/year over the forecast period. These relatively low rates of decline reflect the eastern railroads' historical success in maintaining duopoly pricing, despite strong productivity gains.

    Some generating plants in the Northeast which are currently captive to one railroad are expected to achieve lower rates either through regulatory relief or through constructing additional transportation facilities. These lower rate levels are assumed to be achieved by 2005. After achieving a lower rate level, rates for these plants decline at 1%/year, as is the case for other competitively served plants in this region.

    Vessel and barge.  Vessel and barge rates are projected to decline during the forecast period, on average, at a rate of 2% per year in real terms, reflecting improved productivity in competitive markets.

    Truck.  Truck rates are projected to decline at an average annual rate of 2.0%/year during the forecast period, reflecting low costs of entry and continued strong competition among trucking firms.

    Multi-Modal Movements.  Some coal movements in NPCC/MAAC involve more than one transportation mode. Specifically, the coal movements within NPCC/MAAC include eastern rail/vessel, and western rail/vessel movements. For these movements, the escalation of the transportation rate is estimated based on the approximate proportion of the overall transportation rate that is attributable to each transportation mode. The rail portion of any multi-modal movement is assumed to be competitive.

    Eastern Rail/Vessel.  Real transportation rates for rail/vessel movements originating on eastern railroads are assumed to decline at an average annual rate of 1.2%/year.

B–65



APPENDIX C

TRANSFER CAPABILITY

Transfer Capability

    The transmission system is the transportation mechanism that moves power from where it is generated to where it is to be used. There are a number of technical factors that limit the amount of power between utilities, control areas or large regions. While facility ratings are one key element, voltage levels or instability are other considerations that need to be considered in establishing transfer capabilities. In addition, transfers that involve two utilities or control areas will have an impact on the transfer capabilities of neighboring utilities because a portion of that transfer will flow on neighboring utilities' lines. In order to quantify transmission capabilities between NERC regions and major subregions, seasonal analyses are performed that include current operating parameters, load patterns and scheduled transfers to determine regional import and export capabilities.

    The transfer capabilities that are shown are non-simultaneous, meaning that for any given transfer at an identified limit, the other transfer limitations shown in the tables are unlikely to be attainable at the same time. Concurrent exports or imports for any particular region may not be technically feasible at the total of the capabilities listed. These values represent the ability of the transmission networks to accommodate the transfer electricity from one area to another area for a single load and generation pattern. Therefore, the actual patterns of demands and generation can result in changes in transfer capabilities on both an hourly and daily basis. These transfer capabilities have been considered as representative of the level of interchange that could occur between the various transmission areas. The following Tables and Figures identify the bulk transfer capabilities between regions and subregions that have been included in this report.

Wheeling Rates

    Wheeling rates were determined based on assumptions associated with proposed or existing RTO, ISO and Transco organizational structures. The NEPOOL region is part of the New England ISO. Wheeling rates within the New England ISO are set at $0.00/MWh and rates between the New England ISO and other regions are set at $3.00/MWh.

Table C-1
NPCC/MAAC Transmission Transfer Capability

From

  To
  Winter Capability
(MW)

  Summer Capability
(MW)


Can-Ontario

 

ECAR

 

2,370

 

1,930
Can-Quebec   NEPOOL-SE   525   1,800
NEPOOL-SE   Can-Quebec   1,670   1,370
NEPOOL-SE   NYPP-East   122   191
NEPOOL-West   NYPP-East   510   802
NEPOOL-West   NYPP-In-City   334   525
NEPOOL-West   NYPP-Long Island   84   132
NYPP-East   NEPOOL-SE   200   154
NYPP-East   NEPOOL-West   925   811
NYPP-In-City   NEPOOL-West   575   443
NYPP-Long Island   NEPOOL-West   150   116

B–66


ECAR   Can-Ontario   2,230   1,680
Can-Nova Scotia   Can-Quebec   400   400
Can-Nova Scotia   NEPOOL-Maine   700   700
Can-Ontario   Can-Quebec   309   309
Can-Ontario   NYPP-West   1,850   1,850
Can-Quebec   Can-Nova Scotia   1,050   1,050
Can-Quebec   Can-Ontario   1,391   1,391
Can-Quebec   NYPP-West   1,200   1,200
NEPOOL-Maine   Can-Nova Scotia   55   55
NEPOOL-Maine   NEPOOL-West   1,200   1,200
NEPOOL-SE   NEPOOL-West   3,600   3,600
NEPOOL-West   NEPOOL-Maine   1,450   1,450
NEPOOL-West   NEPOOL-SE   3,600   3,600
NYPP-East   NYPP-In-City   4,441   4,441
NYPP-East   NYPP-Long Island   1,390   1,390
NYPP-East   NYPP-West   5,339   5,339
NYPP-East   PJM-East   1,784   1,784
NYPP-In-City   NYPP-East   4,441   4,441
NYPP-In-City   PJM-East   2,750   2,750
NYPP-Long Island   NYPP-East   1,306   1,306
NYPP-West   Can-Ontario   1,850   1,850
NYPP-West   Can-Quebec   1,500   1,500
NYPP-West   NYPP-East   5,261   5,261
NYPP-West   PJM-West   725   725
PJM-Central   PJM-East   8,673   8,673
PJM-Central   PJM-West   5,254   5,254
PJM-Central   ECAR   400   400
PJM-Central   SERC   1,700   1,700
PJM-East   NYPP-East   735   735
PJM-East   NYPP-In-City   766   766
PJM-East   PJM-Central   6,971   6,971
PJM-West   NYPP-West   725   725
PJM-West   PJM-Central   5,146   5,146
PJM-West   ECAR   2,600   2,600
ECAR   PJM-Central   494   494
ECAR   PJM-West   2,000   2,000
SERC   PJM-Central   1,700   1,700

B–67


Figure C-1
NPCC/MAAC Transmission Transfer Capacity (MW)(1)

     LOGO

B–68



APPENDIX D

GENERIC CAPACITY ADDITIONS

    The market entry and exit logic determines the amount and timing of new generation capacity added to the system as well as the retirement of existing units. Starting in 2003, the market entry and exit logic, at a minimum, builds enough new capacity to meet the estimated reserve requirements.

    The following tables describe the timing and amount of market entry and exit (retirements) for Case 1 for NEPOOL.


Table D-1
Generic Capacity Additions in NEPOOL (MW)

Year(1)

  Combined Cycle
Plants Added

  Combustion
Turbines Added

  Retirements
  Cumulative
Capacity Additions


2003

 

0

 

0

 

0

 

0

2004

 

0

 

0

 

184

 

-184

2005

 

0

 

0

 

664

 

-848

2006

 

0

 

0

 

0

 

-848

2007

 

1040

 

0

 

0

 

192

2008

 

520

 

0

 

1

 

711

2009

 

1040

 

0

 

0

 

1,751

2010

 

520

 

0

 

0

 

2,271

2011

 

520

 

0

 

23

 

2,768

2012

 

1,040

 

0

 

1

 

3,807

2013

 

1,040

 

0

 

500

 

4,347

2014

 

520

 

0

 

0

 

4,867

2015

 

520

 

0

 

0

 

5,387

2016

 

1,040

 

690

 

871

 

6,246

2017

 

520

 

0

 

0

 

6,766

2018

 

0

 

690

 

4

 

7,452

2019

 

520

 

345

 

4

 

8,313

2020

 

520

 

345

 

69

 

9,109

Total

 

9,360

 

2,070

 

2,321

 

9,109

(1)
2001 and 2002 additions are merchant plants as shown in Chapter 4.

B–69





    Until [      ], 2002, all dealers that effect transactions in these securities, whether or not participating in this exchange offer, may be required to deliver a prospectus. Each broker-dealer that receives bonds for its own account pursuant to the exchange offer must acknowledge that it will deliver a prospectus in connection with any resale of such bonds. We have agreed that we will make this prospectus available to any broker-dealer for use in connection with any such resale for such period of time as is necessary to comply with applicable laws in connection with any resale of such exchange bonds.

$440,000,000

LOGO

Offer to Exchange

4.998% Series A-1 Senior Secured Bonds due 2005
for any and all of its outstanding
4.998% Series A Senior Secured Bonds due 2005

and

8.812% Series B-1 Senior Secured Bonds due 2026
for any and all of its outstanding
8.812% Series B Senior Secured Bonds due 2026


PROSPECTUS

[      ], 2001





PART II

INFORMATION NOT REQUIRED IN PROSPECTUS

ITEM 20. INDEMNIFICATION OF DIRECTORS AND OFFICERS.

    Section 33-772 of the Connecticut Business Corporation Act ("CBCA") requires a corporation to indemnify a director who was wholly successful, on the merits or otherwise, in the defense of any proceeding to which he was a party because he was a director of the corporation against reasonable expenses incurred by him in connection with the proceeding.

    Section 33-771 of the CBCA generally permits indemnification of a director if (1) (A) the director conducted himself in good faith; (B) the director reasonably believed (i) in the case of conduct in an official capacity, that the conduct was in the best interests of the corporation; and (ii) in all other cases, that the director's conduct was at least not opposed to the best interests of the corporation; and (C) in the case of any criminal proceeding, the director had no reasonable cause to believe the conduct was unlawful; or (2) the director engaged in conduct for which broader indemnification has been made permissible or obligatory under a provision of the certificate of incorporation. Unless ordered by a court, a corporation may not indemnify a director: (1) In connection with a proceeding by or in the right of the corporation except for reasonable expenses incurred in connection with the proceeding if it is determined that the director has met with the above standard of conduct section; or (2) in connection with any proceeding with respect to conduct for which he was adjudged liable on the basis that he received a financial benefit to which he was not entitled, whether or not involving action in this official capacity. The statute states that the termination of a proceeding by judgment, order, settlement or conviction or upon a plea of nolo contendere or its equivalent is not, of itself, determinative that the director did not meet the relevant standard of conduct.

    Section 33-776 of the CBCA provides that a corporation may indemnify an officer, employee or agent of the corporation to the same extent that it may indemnify a director, or to such further extent, consistent with public policy, as may be provided by contract, the certificate of incorporation, the bylaws or a resolution of the board of directors. Section 33-776(c) of the CBCA provides that a corporation may indemnify an officer, employee or agent of the corporation to the same extent that a director must be indemnified under Section 33-772 of the CBCA.

    Sections 33-773 and 33-776 of the CBCA provide that a corporation may advance expenses to a director, officer or agent prior to final disposition of a proceeding if the director, officer or agent affirms in writing his good faith belief that he has met the relevant standard of conduct required for indemnification and he undertakes in writing to repay any funds if he is not entitled to mandatory indemnification and it is ultimately determined that he has not met the relevant standard of conduct for permissive indemnification.

    Article IV of the Certificate of Incorporation of the Registrant (see Exhibit 3.1 filed herewith and incorporated by reference herein) provides for indemnification of directors, officers and other persons as follows:

II–1


    The directors and officers of the registrant are covered by liability insurance.

ITEM 21. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

Exhibit
Number

  Description

1.1 

 

Purchase Agreement, dated October 12, 2001, by and between Northeast Generation Company and Salomon Smith Barney Inc. as representative of the initial purchasers named therein.

3.1 

 

Certificate of Incorporation, filed December 28, 1998, of Northeast Generation Company.

3.2 

 

By-laws of Northeast Generation Company.

4.1 

 

Indenture, dated as of October 18, 2001 between Northeast Generation Company and The Bank of New York, as trustee.

4.2 

 

First Supplemental Indenture, dated as of October 18, 2001, between Northeast Generation Company and The Bank of New York, as trustee.

4.3 

 

Form of certificate of 4.998% Series A-1 Senior Secured Bond due 2005.

4.4 

 

Form of certificate of 8.812% Series B-1 Senior Secured Bond due 2026.

II–2



4.5 

 

Registration Rights Agreement, dated as of October 12, 2001, between Northeast Generation Company and Salomon Smith Barney Inc., as representative of the initial purchasers named therein.

5.1 

 

Opinion of Day, Berry & Howard LLP.

10.1 

 

Power Purchase and Sales Agreement, dated December 27, 1999, between Northeast Generation Company and Select Energy, Inc.

10.2 

 

Guaranty, dated October 18, 2001, by Northeast Utilities in favor of Northeast Generation Company.

10.3 

 

Consent and Agreement, dated as of October 18, 2001, among Northeast Utilities, Select Energy, Inc., The Bank of New York, as trustee, and Northeast Generation Company.

10.4 

 

Security Agreement, dated as of October 18, 2001, between Northeast Generation Company and The Bank of New York, as trustee.

10.5 

 

Form of Mortgage, Assignment of Leases and Rents, Security Agreement and Fixture Filing dated as of October 18, 2001, by Northeast Generation Company in favor of The Bank of New York, as trustee.

10.6 

 

Management and Operation Agreement, dated February 1, 2000, between Northeast Generation Company and Northeast Generation Services Company.

10.6.1

 

Amendment No. 1, dated March 1, 2000, to Management and Operation Agreement, dated February 1, 2000, between Northeast Generation Company and Northeast Generation Services Company.

10.7 

 

Service Contract, dated as of January 4, 1999, between Northeast Utilities Service Company and Northeast Generation Company.

10.7.1

 

Renewals, dated December 31, 1999 and December 31, 2000, of Service Contract, dated as of January 4, 1999, between Northeast Utilities Service Company and Northeast Generation Company.

10.8 

 

Amended and Restated Tax Allocation Agreement, dated as of January 1, 1990, by and among Northeast Utilities and its subsidiaries.

10.8.1

 

First Amendment, dated as of October 26, 1998, to the Amended and Restated Tax Allocation Agreement dated as of January 1, 1990.

10.8.2

 

Second Amendment, dated as of March 1, 2000, to the Amended and Restated Tax Allocation Agreement dated as of January 1, 1990 (incorporated by reference to Exhibit D.3 to the Northeast Utilities Form U5S, File No. 30-246, for the year ended December 31, 1999).

10.9 

 

Interconnection Agreement, dated July 2, 1999, between Connecticut Light & Power Company, and Northeast Generation Company, as amended August 26, 1999.

10.10 

 

Interconnection Agreement, dated July 2, 1999, between Western Massachusetts Electric Company and Northeast Generation Company, as amended August 26, 1999.

10.11 

 

Purchase and Sale Agreement, dated July 2, 1999, between Northeast Generation Company and Connecticut Light & Power Company.

10.12 

 

Purchase and Sale Agreement, dated July 2, 1999, between Northeast Generation Company and Western Massachusetts Electric Company.

II–3



10.13 

 

Form of Exchange Agent Agreement between Northeast Generation Company and The Bank of New York as exchange agent.

12   

 

Computation of ratio of earnings to fixed charges.

23.1 

 

Consent of Arthur Andersen LLP.

23.2 

 

Consent of Day, Berry & Howard LLP (included in Exhibit 5.1).

23.3 

 

Consent of S&W Consultants, Inc.

23.4 

 

Consent of PA Consulting Services, Inc.

24.1 

 

Powers of Attorney (included as part of signature page to this registration statement).

25.1 

 

Form T-1 Statement of Eligibility of The Bank of New York to act as trustee under the indenture.

99.1 

 

Form of Letter of Transmittal.

99.2 

 

Form of Notice of Guaranteed Delivery.

99.3 

 

Form of Letter to Brokers, Dealers, Commercial Banks, Trust Companies and Other Nominees.

99.4 

 

Form of Letter to Clients.

ITEM 22. UNDERTAKINGS

    The undersigned registrant hereby undertakes:

    The undersigned registrant hereby undertakes to respond to requests for information that is incorporated by reference into the prospectus pursuant to Item 4, 10(b), 11 or 13 of this Form, within one business day of the receipt of such request, and to send the incorporated documents by first class mail or other equally prompt means. This includes information contained in documents filed subsequent to the effective date of the registration statement through the date of responding to the request.

    The undersigned registrant hereby undertakes to supply by means of post-effective amendment all information concerning a transaction, and the company being acquired involved therein, that was not the subject of and included in the registration statement when it became effective.

    Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers and controlling persons of the registrant pursuant to the provisions described in Item 20 above, 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 counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question of 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.

II–4



SIGNATURES

    Pursuant to the requirements of the Securities Act, Northeast Generation Company has duly caused this Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Berlin, State of Connecticut, on the 6th day of December, 2001.

    NORTHEAST GENERATION COMPANY

 

 

By:

/s/ 
BRUCE D. KENYON   
Name: Bruce D. Kenyon
Title:  President


POWER OF ATTORNEY

    We, the undersigned directors and officers of Northeast Generation Company, do hereby constitute and appoint Jeffrey C. Miller and Jane P. Seidl, and each of them, our true and lawful attorneys-in-fact and agents, to do any and all acts and things in our names and on our behalf in our capacities as directors and officers of Northeast Generation Company and to execute any and all instruments for us and in our name in the capacities indicated below, that such attorneys and agents, or either of them, may deem necessary or advisable to enable Northeast Generation Company to comply with the Securities Act of 1933, and any rules, regulations and requirements of the Securities and Exchange Commission, in connection with this Registration Statement, including specifically, but without limitation, the power and authority to sign for us in our names in the capacities indicated below, any and all amendments (including post-effective amendments) to this Registration Statement; and we do hereby ratify and confirm all that such attorneys and agents, or either of them, shall do or cause to be done by virtue hereof.

    Pursuant to the requirements of the Securities Act of 1933, this Registration Statement has been signed by the following persons in the capacities indicated on the 6th day of December, 2001:

Signature
  Title
  Date

 

 

 

 

 
/s/ BRUCE D. KENYON   
Bruce D. Kenyon
  President and Director (Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer)   December 6, 2001

/s/ 
WILLIAM J. NADEAU   
William J. Nadeau

 

Vice President and Director

 

December 6, 2001

/s/ 
FRANK P. SABATINO   
Frank P. Sabatino

 

Vice President and Director

 

December 6, 2001

/s/ 
WILLIAM W. SCHIVLEY   
William W. Schivley

 

Director

 

December 6, 2001

II–5



EXHIBIT INDEX

Exhibit
Number

  Description

1.1 

 

Purchase Agreement, dated October 12, 2001, by and between Northeast Generation Company and Salomon Smith Barney Inc. as representative of the initial purchasers named therein.

3.1 

 

Certificate of Incorporation, filed December 28, 1998, of Northeast Generation Company.

3.2 

 

By-laws of Northeast Generation Company.

4.1 

 

Indenture, dated as of October 18, 2001 between Northeast Generation Company and The Bank of New York, as trustee.

4.2 

 

First Supplemental Indenture, dated as of October 18, 2001, between Northeast Generation Company and The Bank of New York, as trustee.

4.3 

 

Form of certificate of 4.998% Series A-1 Senior Secured Bond due 2005.

4.4 

 

Form of certificate of 8.812% Series B-1 Senior Secured Bond due 2026.

4.5 

 

Registration Rights Agreement, dated as of October 12, 2001, between Northeast Generation Company and Salomon Smith Barney Inc., as representative of the initial purchasers named therein.

5.1 

 

Opinion of Day, Berry & Howard LLP.

10.1 

 

Power Purchase and Sales Agreement, dated December 27, 1999, between Northeast Generation Company and Select Energy, Inc.

10.2 

 

Guaranty, dated October 18, 2001, by Northeast Utilities in favor of Northeast Generation Company.

10.3 

 

Consent and Agreement, dated as of October 18, 2001, among Northeast Utilities, Select Energy, Inc., The Bank of New York, as trustee, and Northeast Generation Company.

10.4 

 

Security Agreement, dated as of October 18, 2001, between Northeast Generation Company and The Bank of New York, as trustee.

10.5 

 

Form of Mortgage, Assignment of Leases and Rents, Security Agreement and Fixture Filing dated as of October 18, 2001, by Northeast Generation Company in favor of The Bank of New York, as trustee.

10.6 

 

Management and Operation Agreement, dated February 1, 2000, between Northeast Generation Company and Northeast Generation Services Company.

10.6.1

 

Amendment No. 1, dated March 1, 2000, to Management and Operation Agreement, dated February 1, 2000, between Northeast Generation Company and Northeast Generation Services Company.

10.7 

 

Service Contract, dated as of January 4, 1999, between Northeast Utilities Service Company and Northeast Generation Company.

10.7.1

 

Renewals, dated December 31, 1999 and December 31, 2000, of Service Contract, dated as of January 4, 1999, between Northeast Utilities Service Company and Northeast Generation Company.

10.8 

 

Amended and Restated Tax Allocation Agreement, dated as of January 1, 1990, by and among Northeast Utilities and its subsidiaries.


10.8.1

 

First Amendment, dated as of October 26, 1998, to the Amended and Restated Tax Allocation Agreement dated as of January 1, 1990.

10.8.2

 

Second Amendment, dated as of March 1, 2000, to the Amended and Restated Tax Allocation Agreement dated as of January 1, 1990 (incorporated by reference to Exhibit D.3 to the Northeast Utilities Form U5S, File No. 30-246, for the year ended December 31, 1999).

10.9 

 

Interconnection Agreement, dated July 2, 1999, between Connecticut Light & Power Company, and Northeast Generation Company, as amended August 26, 1999.

10.10 

 

Interconnection Agreement, dated July 2, 1999, between Western Massachusetts Electric Company and Northeast Generation Company, as amended August 26, 1999.

10.11 

 

Purchase and Sale Agreement, dated July 2, 1999, between Northeast Generation Company and Connecticut Light & Power Company.

10.12 

 

Purchase and Sale Agreement, dated July 2, 1999, between Northeast Generation Company and Western Massachusetts Electric Company.

10.13 

 

Form of Exchange Agent Agreement between Northeast Generation Company and The Bank of New York as exchange agent.

12   

 

Computation of ratio of earnings to fixed charges.

23.1 

 

Consent of Arthur Andersen LLP.

23.2 

 

Consent of Day, Berry & Howard LLP (included in Exhibit 5.1).

23.3 

 

Consent of S&W Consultants, Inc.

23.4 

 

Consent of PA Consulting Services, Inc.

24.1 

 

Powers of Attorney (included as part of signature page to this registration statement).

25.1 

 

Form T-1 Statement of Eligibility of The Bank of New York to act as trustee under the indenture.

99.1 

 

Form of Letter of Transmittal.

99.2 

 

Form of Notice of Guaranteed Delivery.

99.3 

 

Form of Letter to Brokers, Dealers, Commercial Banks, Trust Companies and Other Nominees.

99.4 

 

Form of Letter to Clients.



QuickLinks

TABLE OF CONTENTS
NOTICE TO NEW HAMPSHIRE RESIDENTS
FORWARD-LOOKING STATEMENTS
PROSPECTUS SUMMARY
The Exchange Offer
Summary of the Terms of the Exchange Bonds
The Issuer
Our Ownership
Summary Selected Financial Data
RISK FACTORS
THE EXCHANGE OFFER
USE OF PROCEEDS
CAPITALIZATION
SELECTED FINANCIAL DATA
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
INDUSTRY OVERVIEW
NEPOOL Annual Capacity and Summer Peak Load
OUR BUSINESS
SUMMARY OF THE INDEPENDENT TECHNICAL CONSULTANT'S REPORT
Station Performance Statistics (Average, %)
Projected Cash Flow Summary
Projected Debt Service Coverage Ratios
SUMMARY OF THE INDEPENDENT MARKET CONSULTANT'S REPORT
OUR AFFILIATES
Select Energy Management of Load Obligations
REGULATION
MANAGEMENT
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
SUMMARY OF CERTAIN PRINCIPAL AGREEMENTS
DESCRIPTION OF THE EXCHANGE BONDS
FEDERAL INCOME TAX CONSIDERATIONS
ERISA CONSIDERATIONS
PLAN OF DISTRIBUTION
RATINGS
INDEPENDENT CONSULTANTS
LEGAL MATTERS
INDEPENDENT PUBLIC ACCOUNTANTS
WHERE YOU CAN FIND MORE INFORMATION
INDEX TO FINANCIAL STATEMENTS
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
NORTHEAST GENERATION COMPANY BALANCE SHEETS
NORTHEAST GENERATION COMPANY STATEMENTS OF INCOME
NORTHEAST GENERATION COMPANY STATEMENT OF STOCKHOLDER'S EQUITY
NORTHEAST GENERATION COMPANY STATEMENTS OF CASH FLOWS
NORTHEAST GENERATION COMPANY NOTES TO FINANCIAL STATEMENTS Nine Months Ended September 30, 2001 (Unaudited) Years Ended December 31, 2000 And 1999
SEGMENT INFORMATION BALANCE SHEETS AT SEPTEMBER 30, 2001 (UNAUDITED) AND DECEMBER 31, 2000
SEGMENT INFORMATION STATEMENTS OF INCOME
LEGAL NOTICE
ELECTRONIC MAIL NOTICE
Independent Technical Review for Northeast Generation Company Table of Contents
Table 1-1. Station Characteristics
Table 1-2. Station Performance Statistics (Average, %)
Table 3-1: Basic Unit Data
Figure 3-1.
Figure 3-2.
Figure 3-3.
Figure 3-4
Figure 3-5
Figure 3-6
Northfield Mountain System O&M Expenses (All Values in Nominal $000)
Northfield Mountain System Capital & O&M Project Expenses (Nominal $000's)
Table 4-1. Housatonic Hydro System
Figure 4-1
Figure 4-2
Figure 4-3
Figure 4-4
Figure 4-5
Figure 4-6
Figure 4-7
Figure 4-8
Figure 4-9
Figure 4-10
Figure 4-11
Housatonic Hydro System O&M Expenses (All Values in thousands of Nominal dollars)
Housatonic Hydro System Capital and O&M Project Expenses (All Values in Nominal $000)
Table 5-1 Basic Data for the Eastern Hydro Stations
Eastern Hydro System O&M Expenses (All Values in Nominal $000)
Eastern Hydro System Capital & O&M Project Expenses (All Values in Nominal $000's)
ICU Air Pollution Emission Limitations
Figure 6-1. Connecticut River Flow vs Northfield Generation
Table 6-1 High Flow Impact on Northfield Mountain Operations
Figure 6-2. Connecticut River Flow vs Cabot
Table 6-2. Approximate Impact of Water Availability on Generation
Table 7-1. Year 2001 PPA Pricing
Table 7-2—Approved Capital Expenditures under the MOA
Tranche A Amortization Schedule
Tranche B Amortization Schedule
Table 8-1. Technical Assumptions
Cash Flow Summary ($MM Unless Otherwise Noted) Base Case
Cash Flow Summary ($MM Unless Otherwise Noted) Base Case
Northeast Generation Company Cash Flow Summary ($MM Unless Otherwise Noted) Low Fuel Case
Northeast Generation Company Cash Flow Summary ($MM Unless Otherwise Noted) Low Fuel Case
Northeast Generation Company Cash Flow Summary ($MM Unless Otherwise Noted) Overbuild Case
Northeast Generation Company Cash Flow Summary ($MM Unless Otherwise Noted) Overbuild Case
Independent Market Expert's Report for the Portfolio of the Northeast Generation Company Final Report Prepared for: Salomon Smith Barney, Inc. 390 Greenwich Street New York, NY 10013 Prepared by: PHB Hagler Bailly, Inc. 1881 Ninth Street, Suite 302 Boulder, Colorado 80302 303-449-5515 December 20, 2000
DISCLAIMER
TABLE OF CONTENTS
CHAPTER 1 INTRODUCTION
CHAPTER 2 REGIONAL COMPETITIVE POWER MARKET STRUCTURES
Figure 2-1 New England Transmission System(1)
CHAPTER 3 APPROACH TO MARKET PRICE FORECASTING
Figure 3-1 Price vs. Load—PJM West, February 2000
Figure 3-2 Approach to Developing Compensation for Capacity and Energy Prices
Figure 3-3 Example Supply and Demand Curve
Figure 3-4 PJM Hourly Energy Prices, Summer 1999
Figure 3-5 PJM Hourly Energy Prices, Production-Cost Model, Summer 1999
Figure 3-6 Two Different Approaches to Modeling Hourly Demand
Figure 3-7 Dispatch Results Simulated by a Conventional Production-cost Model
Table 3-1 Possible Target Generating Unit Profit Levels
Figure 3-8 PHB Hagler Bailly's Market Valuation Process (MVPSM)
CHAPTER 4 ASSUMPTIONS
Table 4-7 Reference Terminal Assignments for No. 2 Fuel Oil Analysis
Table 4-8 NPCC/MAAC Delivered No. 2 Fuel Oil Price (real 2000 $/MMBtu)
Table 4-9 NPCC/MAAC Delivered No. 6 Fuel Oil Price (real 2000 $/MMBtu)
Table 4-10 Projected Average Annual Load Growth Rates
Table 4-11 SO2 Cost Curves (real 2000 $/ton)
Table 4-12 NOx Cost Curves (real 2000 $/ton)
Table 4-13 NEPOOL Nuclear Unit Retirements—2000 through 2020
Table 4-14 NEPOOL Base Case Additions—2000 through 2002
Table 4-15 New CC Generating Characteristics (real 2000 $)
Table 4-16 Full Load Heat Rate Improvement (Btu/kWh)(1)
CHAPTER 5 MARKET PRICE FORECASTS
Figure 5-1 NEPOOL Load and Resource Balance
Table 5-1 NEPOOL Case 1 Compensation for Capacity Forecast (real 2000 $/kW-yr)
Table 5-2 NEPOOL West Case 1 Energy and All-In Price Forecasts (real 2000 $/MWh)
Figure 5-4 NEPOOL West Case 1 Energy, All-In, and Compensation for Capacity Forecasts(1)
Table 5-3 NEPOOL Case 2 Compensation for Capacity Forecast (real 2000 $/kW-yr)
Table 5-4 NEPOOL West Case 2 Energy and All-In Price Forecasts (real 2000 $/MWh)
Figure 5-5 NEPOOL West Case 2 Energy, All-In, and Compensation for Capacity Forecasts(1)
Table 5-5 NEPOOL Case 3 Incremental Merchant Plant Assumptions
Table 5-6 NEPOOL Case 3 Compensation for Capacity Forecast (real 2000 $/kW-yr)
Table 5-7 NEPOOL West Case 3 Energy and All-In Price Forecasts (real 2000 $/MWh)
Figure 5-6 NEPOOL West Case 3 Energy, All-In, and Compensation for Capacity Forecasts(1)
Table 5-8 NEPOOL West Case 1 Energy Price Forecasts(1) Volatility Adjusted, Energy Only Market
Table 5-9 NGC Portfolio Revenues(1)—NEPOOL West Case 1 Volatility Adjusted, Energy Only Market ($M)
Table 5-10 NEPOOL West Case 2 Energy Price Forecasts(1) Volatility Adjusted, Energy Only Market
Table 5-11 NGC Portfolio Revenues(1)—NEPOOL West Case 2 Volatility Adjusted, Energy Only Market ($M)
Table 5-12 NEPOOL Case 3 Energy Price Forecasts(1) Volatility Adjusted, Energy Only Market
Table 5-13 NGC Portfolio Revenues(1)—NEPOOL West Case 3 Volatility Adjusted, Energy Only Market ($M)
Table 5-14 Relative Risk of Case 1 NGC Portfolio Revenues ($/kW-yr)
APPENDIX A PRICING AREAS NPCC/MAAC Pricing Areas
NPCC/MAAC Utilities by Pricing Area
APPENDIX B REGIONAL SPECIFIC COAL PRICE DISCUSSION
APPENDIX C TRANSFER CAPABILITY
APPENDIX D GENERIC CAPACITY ADDITIONS
Table D-1 Generic Capacity Additions in NEPOOL (MW)
PART II INFORMATION NOT REQUIRED IN PROSPECTUS
SIGNATURES
POWER OF ATTORNEY
EXHIBIT INDEX

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1/31/21
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1/31/05
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10/15/04
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1/1/04
10/15/03
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4/15/02
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